Au5 Online Operating Manual

PRODUCTION DEPARTMENT

Gujarat Refinery Units (GRU)

ATMOSPHERIC UNIT-V (AU -V)

O P E R A T I N G M A N U A L

SEQ/PN/(GR)/SI/7.5.1/4

Revised By :A.K.ROY (DMPN)

Checked By :S.KHAN (SPNM)

Approved By :B.V.RAMA GOPAL (CPNM)

GUJARAT REFINERY

INDIAN OIL CORPORATION LTD.

VADODARA

PREFACE

The unit has been revamped during August/Sept ’02 to modify the flexibility of operation

by installing new preheat train and increase in the number of pumps for different products

& circulating refluxes.

This operating manual contains necessary guidelines for normal operation and emergency

procedures such as startup, shutdown and different emergencies and is supplemented with

write-ups, drawings etc. wherever necessary. The various operating parameters are

indicative only. It may call for any modification or change in operating parameters based

on the actual operating experience in near future. The operating manual was updated in

May-05 and various changes were incorporated such as shut down & start up checklists,

PSVs’ list, unit equipments list etc., for fusing the plant related information.

In this revision, special attention is given for startup, shutdown and emergency handling

procedures. It is thoroughly revised & step-by-step procedure is given for easy

understanding. New chapters on Safety System, Control Valve Data and Advanced

Process Control have been added. Control valves fail safe position and Operation and

Maintenance of HSD Coalescer has been incorporated in this manual for better operation

guidance.

LPG Vapouriser line to MSQ and Light Naphtha from AU-V to AU-I rerun section lines

were commissioned and that has been incorporated in the revised manual.

GR1 Units

Date: 25/09/07 B.V.RAMA GOPAL

(Chief Production Manager)

Sl. No DESCRIPTION Page. No Chapter 1 GENERAL 8-17

1.1 INTRODUCTION 91.2 ONSTREAM FACTOR 91.3 DESIGN FEED RATE 91.4 FEED & PRODUCT SPECIFICATIONS 101.5 FEED & PRODUCT BATTERY LIMIT CONDITIONS 141.6 UTILITY SPECIFICATIONS 15

Chapter 2 EQUIPMENT DATA 18-292.1 COLUMNS 192.2 HEAT EXCHANGERS/COOLERS/CONDENSERS 192.3 PUMPS 202.4 FURNACE/AIR PRE-HEATER 212.5 TURBO BLOWERS (ID & FD FANS) 212.6 VESSELS 222.7 TANKS 232.8 FILTERS 232.9 PSV’S 232.10 TSV’S 252.11 LIST OF CONTROLLERS 27

Chapter 3 PROCESS DESCRIPTION 30-923.1 BASIC OPERATIONS INVOLVED 313.2 CRUDE CHARGING INTO UNIT 323.3 CRUDE PREHEAT TRAIN-I 333.4 CRUDE DESALTING 34

3.4.1 DESALTERS OPERATION 353.4.2 DESALTER WATER SYSTEM 403.5 CRUDE PREHEAT TRAIN-II 413.6 FURNACE 42

3.6.1 PROCESS SYSTEM 423.6.2 FUEL SYSTEM 44

3.6.2.A FUEL GAS SYSTEM 453.6.2.B FUEL OIL SYSTEM 463.6.3 AIR PRE-HEATER (APH) 473.6.4 COMBUSTION AIR SYSTEM 473.6.5 ID/FD FAN STARTING & STOPPING PROCEDURE 48

3.6.5.1 ID FAN STARTING PROCEDURE 483.6.5.2 ID FAN STOPPING PROCEDURE 483.6.5.3 FD FAN STARTING PROCEDURE 493.6.5.4 FD FAN STOPPING PROCEDURE 503.6.5.5 FURNACE LIGHT UP & CUTOFF PROCEDURE 51

1

CONTENTS

Sl. No DESCRIPTION Page. No3.6.5.6 FURNACE CUTOFF PROCEDURE 513.6.5.7 FURNACE INTERLOCKS 523.6.6 DECOKING SYSTEM 553.7 MAIN ATMOSPHERIC COLUMN 56

3.7.1 FLASH ZONE 563.7.2 OVERHEAD SECTION 573.7.3 MIDDLE SECTION 583.7.4 BOTTOM SECTION (RCO CIRCUIT) 593.7.5 CIRCULATING REFLUXES/PUMP AROUND

CIRCUITS60

3.7.6 PRODUCT DRAW OFF TRAYS 603.8 PRODUCT STRIPPERS 61

3.8.1 HEAVY NAPHTHA STRIPPER 613.8.2 KEROSENE/ATF STRIPPER 623.8.3 GASOIL STRIPPER 633.9 NAPHTHA STABILISER 653.10 LPG-AMINE ABSORPTION SECTION 683.11 PRODUCT COOLING & RUNDOWN FACILITY 693.12 CAUSTIC/WATER WASH FACILITY FOR PRODUCTS 71

3.12.1.A LPG CAUSTIC WASH SYSTEM 723.12.1.B LPG WATER WASH SYSTEM 733.12.2.A LIGHT NAPHTHA CAUSTIC WASH SYSTEM 743.12.2.B LIGHT NAPHTHA WATER WASH SYSTEM 763.12.3.A KERO/ATF CAUSTIC WASH SYSTEM 763.12.3.B KERO/ATF WATER WASH SYSTEM 78

3.13 CHEMICAL INJECTION FACILITIES 793.13.1 CAUSTIC INJECTION 803.13.2 AMMONIA SOLUTION INJECTION 813.13.3 DEMULSIFIER INJECTION 813.13.4 CORROSION INHIBITOR/AHURALAN SOLN.

INJECTION81

3.13.5 WASH WATER SYSTEM 823.14 EFFECT OF OPERATING VARIABLES 82

3.14.1 DESALTER PARAMETERS 833.14.1.A WATER INJECTION & PRESSURE DROP 833.14.1.B OIL/WATER INTERPHASE LEVEL 833.14.1.C DESALTER PRESSURE 843.14.1.D DESALTER TEMPERATURE 843.14.1.E DEMULSIFIER INJECTION 843.14.1.F VOLTAGE & AMPERAGE 843.14.2 FURNACE COIL OUTLET TEMPERATURE &

OVERFLASH FLOW85

3.14.3 MAIN FRACTIONATING COLUMN PRESSURE 853.14.4 MAIN FRACTIONATING COLUMN TEMPERATURE 86

2

Sl. No DESCRIPTION Page. No

3.14.5 CIRCULATING REFLUXES FLOW 863.14.6 PRODUCT WITHDRAWL TEMPERATURE 873.14.7 STRIPPING STEAM 88

3.14.7.A STRIPPING STEAM IN FRACTIONATING COLUMN 883.14.7.B STRIPPING STEAM IN STRIPPERS 88

3.15 NORMAL OPERATING CONDITIONS 893.16 CRITICAL OPERATING PARAMETERS &

INSTRUMENTS90

Chapter 4 UTILITIES SYSTEM 93-1084.1 INTRODUCTION 944.2 INSTRUMENT AIR 944.3 PLANT AIR 954.4 COOLING WATER 954.5 SERVICE WATER 964.6 DM WATER 964.7 BOILER FEED WATER 974.8 LP STEAM 974.9 MP STEAM 984.10 HP STEAM 984.11 FUEL GAS 994.12 FUEL OIL 1004.13 FLUSHING OIL 1004.14 ELECTRIC SYSTEM 102

4.14.1 ELECTICAL POWER FOR PUMPS 1024.14.2 PLANT ILLUMINATION 1024.14.3 INSTRUMENTATION POWER SYSTEM 1034.15 EFFLUENT SYSTEM 103

4.15.1 SLOP SYSTEM 1034.15.2 CLOSED BLOWDOWN (CBD) SYSTEM 1044.15.3 OILY WATER SEWER (OWS) SYSTEM 1054.15.4 SEWER WATER SYSTEM 1054.15.5 AMINE DRAIN SYSTEM 1064.15.6 FLARE SYSTEM 106

Chapter 5 NORMAL START-UP PROCEDURE 109-147

5.1 INTRODUCTION 110

5.2 BRIEF START-UP PROCEDURE 110

5.3 DETAILED START-UP PROCEDURE(AFTER M&I SHUT DOWN)

112

5.3.1 PRELIMINARY PREPARATION 112

5.3.2 AIR REMOVAL FROM THE PROCESS SYSTEM 116


3

5.3.3 TIGHTNESS/PRESSURE TEST 124

5.3.4 FUEL GAS BACKUP 124

5.3.5 COLD CIRCULATION 127

5.3.6 HOT CIRCULATION 131

5.3.7 COMMISSIONING OF DESALTERS 137

5.3.8 NORMALIZATION OF OPERATING CONDITIONS 138

5.3.9 BRINGING UP NAPHTHA STABILISER SYSTEM 140

5.4 STEPS INVOLVED IN START UP FROM BOTTLED UP CONDITION

142

5.5 CHECK LIST FOR UNIT NORMAL STARTUP FROM BOTTLED UP CONDITION

145

Chapter 6 NORMAL SHUT DOWN PROCEDURE 148-158

6.1 INTRODUCTION 149

6.2 BRIEF SHUT DOWN PROCEDURE 149

6.3 DETAILED SHUT DOWN PROCEDURE (FOR M&I SHUT DOWN)

150

6.3.1 THROUGHPUT REDUCTION 150

6.3.2 DISCONTINUATION OF CHEMICAL INJECTION 151

6.3.3 SHUT DOWN OF NAPHTHA STABILISER 151

6.3.4 DECOMMISSIONING OF DESALTERS 152

6.3.5 NORMAL SHUT DOWN 153

6.3.6 SHUT DOWN OF ATMOSPHERIC SECTION FOR M&I 154

6.3.7 EMPTYING OUT OF THE UNITS AND PURGING/ISOLATION

155

6.3.8 CHECK LIST FOR UNIT NORMAL SHUTDOWN FOR BOTTLED UP CONDITION

156

Chapter 7 EMERGENCY PROCEDURES 159-201

7.1 GENERAL GUIDELINES 160

7.2 POWER FAILURE 162

7.3 STEAM FAILURE 173

7.4 COOLING WATER FAILURE 177

7.5 INSTRUMENT AIR FAILURE 181

7.6 FEED FAILURE 185

7.7 ALL UTILITIES FAILURE 185


4

7.8 FAILURE OF HEATER TUBES 186

7.9 110V DC SUPPLY FAILURE 187

7.10 24V DC SUPPLY FAILURE 190

7.11 UPS FAILURE 194

7.12 DCS CONSOLE FAILURE 197

7.13 FIRE IN THE PLANT 201

Chapter 8 PROCEDURES FOR EQUIPMENT HAND OVER TO MAINTENANCE/INSPECTION

202-213

8.1 PUMPS 203

8.1.1 COLD PUMP 203

8.1.2 HOT PUMP 204

8.2 VESSELS 204

8.3 COLUMNS 207

8.4 EXCHANGERS/COOLERS/CONDENSERS/REBOILERS 210

8.5 TANKS 211

8.6 FURNACE 211

8.7 FLARE HEADER 212

8.8 CONTROL VALVES 212

8.9 SAFETY VALVES 213

Chapter 9 PROCEDURES FOR EQUIPMENT TAKING OVER FROM MAINTENANCE

214-217

9.1 PUMPS/MOTORS 215

9.2 EXCHANGERS/CONDENSERS/COOLERS/REBOILERS/FIN COOLERS

215

9.3 FURNACE 216

9.4 VESSELS 216

9.5 COLUMNS 217

Chapter 10 SAFETY 218-254

10.1 FIRE PREVENTION REGULATIONS 219

10.2 FIRE PREVENTION ACTIVITIES 219

10.2.1 SOUND ENGINEERING 219

10.2.2 GOOD HOUSE KEEPING 219


10.2.3 INSTRUCTION TO PERSONNEL 219

5

10.2.4 REGULAR TRAINING OF EMPLOYEES 219

10.2.5 SAFETY AUDITS/SAFETY STUDIES 220

10.2.6 FIRE EMERGENCY MOCK DRILLS 220

10.3 FIRE PROTECTION SYSTEM IN REFINERY 220

10.4 FIRE PROTECTION SYSTEM IN THE UNIT 222

10.5 WORK PERMIT SYSTEM 222

10.5.1 TYPES OF WORK PERMITS 223

10.5.1.A HOT WORK PERMIT 223

10.5.1.B COLD WORK PERMIT 223

10.5.1.C EXCAVATION PERMIT 223

10.5.1.D WORK AT HEIGHT PERMIT 224

10.5.1.E WORK AT DEPTHS 224

10.5.1.F ELECTRICAL WORK PERMIT 224

10.5.1.G VESSEL ENTRY PERMIT 224

10.5.2 RESPONSIBILITIES OF THE PERMITTEE 225

10.5.3 RENEWAL OF THE PERMIT 225

10.5.4 SURENDERING OF THE PERMIT 225

10.5.5 SIGNATORIES FOR FIRE PERMITS 225

10.5.6 COPIES OF PERMIT 226

10.5.7 POINTS TO BE ENSURED WHILE GIVING CLEARANCE

226

10.5.8 ACCIDENT REPORTING PROCEDURE 227

10.5.9 MATERIAL SAFETY DATA SHEET 229

10.5.9.1 AHURALAN 229

10.5.9.2 AMMONIA 233

10.5.9.3 CAUSTIC SODA 236

10.5.9.4 DIETHANOL AMINE 240

10.5.9.5 DEMULSIFIER 243

10.5.10 CONTROL VALVE FAIL SAFE CONDITION 247


10.5.12 SAFETY SYSTEM AND THEIR FUNCTIONS IN THE UNIT

250

6

10.5.13 SAFETY PRECAUTION IN EQUIPMENTS HANDLING DURING OPERATION

252

10.5.13.1 FURNACE BURNER LIGHT UP (DURING STARTUP) 252

10.5.13.2 WARMING UP OF PUMPS 252

10.5.13.3 PUMP CHANGE OVERS/START UP 253

10.5.13.4 HEAT EXCHANGER COMMISSIONING 253

10.5.13.5 MAN ENTRY IN CLOSED VESSEL/EQUIPMENT 254

10.5.13.6 FURNACE BURNER LIGHT UP (DURING NORMAL OPERATION)

254

Chapter 11 PROCESS UPSET & CORRECTIVE ACTIONS 255-258

Chapter 12 HANDING & TAKING OVER OF INFORMATION DURING SHIFT CHANGE

259-261

Chapter 13 CONTROL OF HAZARDOUS CHEMICAL INVENTORY LEVEL

262-263

Chapter 14 PLANT EQUIPMENT IDLING METHOD 264-265

14.1 FOR SHORT SHUTDOWN 265

14.2 FOR LONG SHUTDOWN 265

Chapter 15 DCS INFORMATION 266-268

Chapter 16 LABORATORY TEST SCHEDULE 269-270

Chapter 17 MASTER BLIND LIST 271-274

Chapter 18 AU-V CONTROL VALVE DATA 275-277

Chapter 19 LIST OF INTERLOCKS 278-282

Chapter 20 SKO/ATF SALT DRYER 283-285

Chapter 21 HSD COALESCER 286-290

Chapter 22 PROCESS DIAGRAMS (FROM P&ID) 291-292

Chapter 23 EQUIPMENT HANDLING PROCEDURE 293-298

7

GENERAL 1.1 INTRODUCTION

8

CHAPTER-1

GENERAL

The atmospheric Unit AU-V of Gujarat Refinery is designed to process

3.0 MMTPA of Arab Mix Crude (50:50 by weight of Light and Heavy

Arab Crude).

This unit was commissioned in the year 1997.

The unit was revamped during August/Sept ’02 to increase the on stream

factor and flexibility of operation by providing additional heat exchanger

train and increase in the number of pumps for different products &

circulating refluxes.

The unit comprises of Crude Preheat Train, Crude Desalting, Atmospheric Distillation,

Naphtha Stabilization, LPG Amine wash and Caustic wash, Light Naphtha Caustic wash,

and Kerosene/ATF caustic wash. The main products from the unit are LPG, Light

Naphtha, Heavy Naphtha, Kerosene, Gas Oil and Long residue. Provision is also there for

with drawl of ATF (boiling range 140-240) during alternate mode of operation. During

ATF mode of operation Kerosene will not be withdrawn and the material boiling in the

range of 240-370° C will be withdrawn as Gas Oil stream.

1.2 ONSTREAM FACTOR

No of onstream hours in a year considered for design is 8000 hrs.

1.3 DESIGN FEED RATE

The following table provides hourly rates of feed and various products based on Arab

Mix Crude feed.

Sl no Material Quantity Wt%

1 Crude 375,000 100

9

2 LPG (Ex Stabilizer) 4750 1.3

3. Light Naphtha 34350 9.1

4. Heavy Naphtha 9280 2.5

5. Kerosene 73,571 19.6

6. Gas Oil 57,551 15.1

7. Long residue 195,573 52.3

1.4 FEED & PRODUCT SPECIFICATION

A. CRUDE:

a) 100% Arab mix Crude consisting of Light and Heavy Arab Crude in 50:50

proportion by weight.

b) Main Column along with overhead condensers and furnace have flexibility to

process 3.0 MMTPA Arab mix crude in 50:50 weight proportion with respect

to flow and hydraulics alone.

The properties of Arab Crude mix are as follows:

Sr. No.

Specification Unit Value

1. Specific gravity @15 oC 0.87282. TBP Distillation (%

volume)

oC

3 IBP oC 27.34 5 oC 52.95 10 oC 97.26 30 oC 223.07 50 oC 344.48 70 oC 476.89 90 oC 658.310 95 oC 709.311 EP oC 732.212 API Gravity oC 30.613 Viscosity @37.8 oC Cst 10.514 Pour Point oC -12415 RVP@38 oC Kg/cm2 0.616 Salt content(max) Ppm 16517 BS&W %Vol 2.0

10

B. PRODUCTS

Sr.No. Product Specification Value1. O/H Naphtha TBP cut oC IBP-170 oC2. Heavy

NaphthaTBP cut oC 120-170 oC

3.ATF

TBP cut oCFlash Point oC

Freezing point oCASTM D-86 EP

140-24038 (min)-50 (max)

288 oC

4. SKO TBP cut oCFlash Point oC

ASTM D-86 EP

140-27036 (min)

300 (max)5. Gas Oil TBP cut oC

Flash Point oCASTM D-86 95%

240/270-37034 (min)

Not to exceed 365oC6. Long residue TBP cut oC Shall not contain

more than 8% vol (max) of material

boiling below 370 oC7. LPG Vapor pressure 6.5

Kg/cm2

Weathering oC

Not more than 16.87 Kg/cm2

95% vol to contain not more than 2% of

C5+ component.

MOTOR SPIRIT

S.No

Characteristic BIS Spec

Prec. Limits

Manf. Spec.

Justification/Remarks

1 Density, 15C, Kg/m3

710-770 0.5/1.2 711-768*

To take care of addition of 5% ethanol

2 RON, min. 88 0.2/0.7 88.5 To take care of test margin(In case due to sensitivity of the blend MS is not in a position to meet AKI, meeting AKI will be guiding factor in line with BIS Spec)

3 Distillation:Recovery at 70C, %v

10-45 Slope 11-38* Lower limit to take care of storage and handling impact.Upper limit to take care of

11

Recovery at 100C, %vRecovery at 180C, %v, minFBP,0C max

40-70

90

215

Slope

Slope

Slope

41-70

91

200

addition of ethanol.Lower limit to take care of storage and handling impact.To take care of storage and handling impact.Based on present quality trend.

4 Benzene Content, %v, max

1

3

0.04/0.18

0.03/0.84

0.9

2.7

To take care of test margins and environmental parameter. -do-

5 Total Sulphur, ppm mass, max

500 1000

145/467153/495

450900

Testing margin and environmental parameter

6 RVP at 38C, kPa

35-60 3.2/5.2 38-57* Lower limit to take care of testing margin. Upper limit to facilitate absorption of ethanol.

7 Copper Corrosion

1 max NA 1a To improve product quality further

* Parameters are applicable for ethanol doping areas only. For other areas BIS specs will Prevail. Gasoline containing ethanol should be supplied with addition of metal deactivator.

KEROSENE

S.No. Characteristic BIS Spec. Prec. Limits Manf. Spec

Justification/ Remarks

1 Smoke Point, mm , min

18

20 (Rlys)

22(Def)

1/2 19

20 (Rlys)

22(Def)

To take care of test margin

2 Distillation:Final Boiling Point, Deg C, max

300 Slope 290 To take care of test margin.

3 Flash point, degree C, min

35 1/1.5 38 Safety parameter. To take care of test margin.

4 Total sulphur, ppm mass, max

2500 175/580 2400 Environmental parameter. To take care of test margin.

HIGH SPEED DIESEL

S.No. Characteristic BIS Spec.

Prec. Limits

Manf. Spec


12

1 Cetane Index, min

46

43 (Assam crude)

Function of density

and distillation

-do-

47

44



2 Rec at 370C, %v, min

95 Slop 96 To take care of test margin. Recovery higher than 95% to be ensured.

3 Flash Point, Deg C, min

35 1/1.5 37 To take care of test margin

4 Total sulphur, ppm mass, max

500

2500

145/467

175/580

450

2400



5 Lubricity, microns, max

460 60/120 420 To take care of test margin and also due to customer complaints.

6 Copper Corrosion, max

1 NA 1a To improve product quality further

7 Particulate Matter, mg/Kg,max

Not specified

2.4/7.2 24 Customer problem of filter chokage.

AVIATION TURBINE FUEL


Prec. Limits

Manf. Spec


1 Freezing Point, degree C, max

-47 0.7/2.6 -49 To take care of test margin

2 Distillation, final boiling point, degree C, max

300 Slope 290 To take care of test margin

3 Flash Point, Deg C, min

38 1/1.5 40 To take care of test margin

4 Sulphur total, ppm mass, max

3000 (Genl)2500

(Defense)

50/175 2500 Defense requirement. Product can not be segregated to defense and non defense categories

5 Electrical Conductivity,

50-450 3-20/10-63

250-440

Lower limit to take care of transit losses.

13

ps/m, 6 Aromatics, %

vol, max25

(Genl.)20

(Defense)

1.4/3.0 20 Defense requirement. Product can not be segregated.

7 Sulphur Mercaptan, ppm mass, max

30 (Genl)20

(Defence)

NA 20 Defence requirement

8 Lubricity, WSD mm max

0.85 (General)

0.65 (Defense)

0.65 To meet Defense requirement. Product cannot be segregated. Not applicable to Haldia Refinery as it produces entire ATF thru’ hydro treatment .

1.5 FEED & PRODUCT BATTERY LIMIT CONDITIONS

Sl.No. Feed/Product PressureKg/cm2 / Temp o C

Source/Destination

FEED1. Crude 9.5/30 OM&S2. Sour LPG 12.0/40 AU2/AU3/AU43. Lean Amine 26.5/35 Amine Regeneration Unit4. Wild Naphtha/

Drag Stream15/38 DHDS/LAB

CRU/MSQPRODUCTS

1. LPG 12.0/40 LPG Horton Sphere2. Light Naphtha 7.0/40 a) Storage/H2 feed storage

b) AU-1 rerun section3. Heavy Naphtha -/40 a) Light Naphtha r/d within the

unitb) SKO r/d within the unitc) Gas Oil r/d within the unit

4. SKO 7.0/40 OM&S5. ATF 7.0/40 Routed to 6”GHP r/d line

outside AU-V b/l6. Gas Oil

Kero Case

ATF case

6.0/40

7.0/40

Storage for DHDS unit feed/DHDS unitSweet Diesel Storage (During Gujarat Crude processing)

7. Long residue 6.5/1206.5/120

Old FPUNew FPU

14

6.5/80 (min) VDUStorage

8. Sour Water -/40 SRU9. FLO (2.5/5.0)/40 Routed to line from AU-3 to

GHP10. Slop 6.0/4011. Spent Caustic 5.0/40 GRE-ETP12. Rich Amine 7.0/55 Amine Regeneration Unit

1.6 UTILITY SPECIFICATIONS

Sr.No. Utilities PressureKg/cm2 Temp oC Specification1. HP Steam 33 4302. MP Steam 11.5 2303. LP Steam 4.5 1654. BFW 17(max) 120(max)

5. Instrument Air 6.5 Ambient -15oC dew point6. Plant Air 6.5 Ambient -15oC dew point7. DM Water 5 408. Fuel Oil(VR +

VBLSHS)5 90 Calorific Value 9600

Kcal/Kg9. Fuel Gas 3 40 Calorific Value

13000 Kcal/Kg

FUELOIL

S.No. Characteristic BIS Spec. Prec. Limits

Manf. Spec


1 Kinematic Viscosity at 50C, cSt, max

125 (winter)

180(summer)

150

0.8/2.5

1.0/3.6

0.8/3.0

120

175

148


2 Water content, %v, max

1 max 0.025/0.1 0.8 Test margin and cushion

HPS

15

S.No. Characteristic BIS:Spec./Customer rqmt.

Prec. Limits

Manf. Spec



40

50

100

0.24/0.80

0.3/1.0

0.6/2

38

48

98

Test margin

2 Flash point, C, max

72 2/3.5 93 In line with LSHS flash spec


1.0 0.025/0.1 0.8 Test margin and cushion

LSHS

S.No. Characteristic BIS Spec./Customer rqmt.

Prec. Limits Manf Spec



50

100

0.3/1.0

0.6/2

49

98


---do---


1.0 0.025/0.1 0.8 Test margin and cushion

PAVING BITUMEN (S-65/S-90 grades)

16


Prec. Limits(Repeatability/

Reproducibility)

Manf. Spec


1 Penetration, 1/10mm

80-100

60-70

2.4-3/6.4-8

1.8-2.1/4.8-5.6

84-96

62-68



2 Softening Point, Degree C

40-55 (S90)

45-55 (S65)

1/5.5

1/5.5

45-54

46-54

Lower limit in line with MoRT Requirement

To take care of test margins

17

18

CHAPTER-2

EQUIPMENT DATA

EQUIPMENT DATA

2.1 COLUMNS

Sl.No

Col.No

Service Tray Safety Valves

No Type Set PrKg/Cm2

No

1 CC-01 Atmospheric Distillation column 51 Valve 4.5 32 CC-02 Heavy. Naphtha Stripper 10 Valve - -3 CC-03 Kero Stripper 6 Valve - -4 CC-04 Gas Oil Stripper 6 Valve - -5 CC-05 Naphtha stabilizer 43 Valve 15 26 CC-06 LPG Amine Absorber 10 Valve 29.5 2

2.2 HEAT EXCHAGERS/COOLERS & CONDENSERS

S.No Exchanger No ServiceShell Tube

1 EE-01 Crude Kero/ATF2 EE-02 Crude Top CR3 E03 Crude Gas Oil4 EE-04 LR Crude5 EE-05 Kero/ATF Crude6 EE-06A/B Kero/ATF Crude7 EE-07A/B/C LR Crude8 EE-08A/B Crude Gas Oil9 EE-09A/B GO CR Crude10 EE-10A/B/C/D LR Crude11 EE-12A/B/C Desalter water Brine12 EE-13 Brine CW13 EE-14 GO CR C-05 Bottom.14 EE-15 GO CR Hy. Naphtha.15 EE-16A/B/C/D/E/F C-01 O/H CW16 EE-17A/B/C/D C-05 O/H CW17 EE-18A/B/C/D C-05 FEED LN18 EE-19A/B LN CW19 EE-20 HN CW20 EE-21 LR CW21 EE-22A/B/C/D LR CW

S.No Exchanger No Service22 EE-23A/B/C GO CW23 EE-24 ATF / KERO CW

19

24 EE-28A/C FO HP Steam25 EE-28B/D HP Steam FO26 EE-29 LPG LP Steam27 EA-01A to H Fin Cooler C-01 O/H28 EE-102A/B Crude LGO29 EE-103A/B/C LR CRUDE30 EE-104A/B CRUDE KERO-I CR31 EE-105A/B/C/D/E LR CRUDE32 EE-106 A/B/C/D CRUDE LGO33 EE-107 A/B/C/D LR CRUDE34 EE-108 A/B HGO CR CRUDE35 EE-109 KERO-I CW36 EE-110 A/B LGO CW37 EE-111 A/B LR CW

2.3 PUMPS

Pump NoPA

Service KW Rated Amps

CapacityM3/hr.

max

DPKg/cm2

1A to E Crude Feed 240 25 287 162A to E Desalted Crude 300 31 310 225A/B/C Top Reflux 45 75 146 116A/B/C CC-05 Feed 75 126 79 207A/B Top CR 37 62 242 98A/B HN r/d 30 52 18 159A/B Kero r/d 75 126 124 1710A/B/C Kero CR 75 126 358 1011A/B GO r/d 75 126 125 1412A/B/C GO CR 160 260 361 1514A/B LPG Reflux 22 37 78 1415A/B Desalter Water Stage-I 15 26 38 17.516A/B Desalter Water Stage-II 55 93 38 1917A/B LPG NaOH Circulation 75 14 36 1118A/B LPG water wash 75 14 36 1219A/B LN caustic wash 5.5 10 25 920A/B LN water wash 5.5 10 25 1323A/B Kero caustic wash 7.5 14 34 1824A/B Kero Water wash 7.5 14 34 1725A/B LPG Caustic / Water m-up 18.5 32 5 2026A/B NH3 Injection 0.37 1.1 7 Lit/hr 8.5Pump No

PAService KW Rated

AmpsCapacityM3/hr.

max

DPKg/cm2

20

27A/B Demulsifier Injection 0.37 1.1 11 Lit/hr 1129A/B Ahuralan Injection 0.37 1.1 24 Lit/hr 1031A/B Caustic injection 0.75 2.7 410 Lit/hr 15.832A/B Caustic Circulation / m- up 11 20 5 11.533 47% caustic transfer 3.7 5 3.140A/B Wash water make up 11 20 5 10.541A/B LN rundown 15 26 58 842A/B VV-2 sour water 3.7 7.3 9 643A/B Spent caustic 5.5 10.2 10 6.544A/B Kero / ATF caustic M/up 15 28 5 19.345A/B IFO 45 75 30 15.546 CBD 18.5 37 20 6.848 ABD 7.5 9.6 6 550A/B LPG booster 45 75 37 2251A/B/C LR 180 19 275 16.852A/B Coolant Water 30 50 98 5.5102A/B Kero-I CR 90 150 371 11103A/B LGO product 90 150 132 15.1104A/B HGO CR 90 150 470 9101A/B Kero-I 110 183 106 21.6

2.4 FIRED HEATER

05-FF-001-Charge heater

2.5 AIR PREHEATER

05-FD-001-Cast Air pre-heater05-FD-002-Glass Air pre-heater

2.6 FANS

05-KA-001A/B FD fans05-KA-02-ID fan.

2.7 DRUMS/VESSELS

21

Sl.No Vessel no Service OperatingPres./ Temp

Safety valve data

Kg/cm2 // 0

CPSV tag Set

Press1 VV-01A Desalter 1st stage 11.5 / 123.5 1201A/B 162 VV-01B Desalter 2nd stage 11.5 / 123.5 1202A/B 163 VV-02 CC-01 O/H reflux Drum 2.1 / 40 1601 / 1602 4.54 VV-03 CC-05 O/H reflux Drum 9/40 1703 / 1704 155 VV-04 Amine settler 18.7 / 406 VV-05 Desalting water drum Atm / 407 VV-06 LPG caustic wash 18 / 40 1901 / 1902 29.58 VV-07 LPG water wash 16.5 / 40 1903/1904 29.59 VV-08 LPG coalescer 15 / 4010 VV-09 LN caustic wash 9.5 /40 2001 / 2002 1611 VV-10 LN water wash 8 / 40 2003 / 2004 1612 VV-13 Kero / ATF Caustic wash 15/40 2201/2202 2313 VV-14 Kero / ATF water wash 14/40 2203/2204 2314 VV-15 Kero / ATF Coalescer 13/4015 VV-16 Spent caustic degasser 1.2/4016 VV-17 Decoking pot Atm / 10017 VV-

18A/BNH3 solution Vessel Atm / 40

18 VV-19A/B

Ahuralan soln. Vessel Atm / 40

19 VV-120 LPG surge drum 9/40 2501 A/B 14.520 VV-25 HN coalescer 10/4021 VV-26 IFO surge drum 1.5 / 90-120 3101 / 3102 3.522 VV-27 HP steam condensate 32/237 -430 3105 4323 VV-28 FG KOD 2/40-80 3203/3204 6.524 VV-29 LPG drum 10 / 40-80 3201/3202 14.525 VV-30 CBD Atm/ 80-

12026 VV-32 Flare KOD 1.5 /14427 VV-33 ABD drum Atm / 6028 VV-34 Brine degasser Atm / 4529 VV-35 Flash condensate 4 / 15230 VV-

37A/BInst. Air vessel 7.5 / amb 9.0

31 VV-38 Coolant sump amb32 Salt Dryer 4 / amb. 16.033 VV-301 HSD Coalescer 4/amb

2.8 TANKS

22

1. 05-TT-001-47% Caustic Solution Tank2. 05-TT-002A/B-10% Caustic Dilution Tank3. 05-TT-005-Wash water make-up Tank4. 05-TT-06A/B-3.5% Caustic Dilution Tank

2.9 FILTERS

1. 05-GN-DO-001A/B IFO Pump such on strainers2. 05-GN-DO-002A/B IFO Pump discharge strainers

2.10 LIST OF SAFETY VALVES & RELIFE VALVES

Safety valves are normally characterized by fast opening, (popping action). These are

used for compressible fluids like gases. In this category come pressure safety valves

(PSV). Relief valves are used for non-compressible fluids (normally liquids). Relief

valves open in proportion to pressure increase over the set value or opening pressure. In

this category come temperature safety valves (TSV).

These pressure relief devices (safety valves as well as relief valves) are spring-loaded

valves. It is important to note that relief valves provide no protection against high

temperature.

The pressure relief valves are actuated by inlet static pressure and designed to open

during an emergency or abnormal condition, causing pressure build up. This action of

relief valve prevents internal fluid pressure from rising above specified value. Depending

upon type of application, safety valves are selected as closing type (auto reset) or non-

closing type.

Brief description of pressure and temp. Safety valves: -

a) LIST OF PSV’s

23

TAG NO. Service LOCATION Set

pressure

Kg/cm2 g

Relieving

Temp ° C

Selection

Basis

24

PSV1201A/B H/C Desalter-I

stage

16.00 Hold Hold

PSV1202A/B H/C Desalter-II sta 16.00 Hold Hold

PSV-1501 H/C 05-CC-001 4.5 130 Block discharge



PSV-1601 H/C 05-VV-002 4.5 128 Fire

PSV-1602 H/C 05-VV-002 4.5 128 Fire

PSV-1701 H/C 05-CC-005 15 87 Block discharge

PSV-1702 H/C 05-CC-005 15 87 Block discharge

PSV-1703 H/C 05-CC-003 15 97 Fire

PSV-1704 H/C 05-CC-003 15 97 Fire

PSV-1901 H/C 05-VV-006 29.5 132 Fire

PSV-1902 H/C 05-VV-006 29.5 243 Fire

PSV-1903 H/C 05-VV-007 29.5 132 Fire

PSV-1904 H/C 05-VV-007 29.5 243 Fire

PSV-2001 H/C 05-VV-009 16 205 Fire

PSV-2002 H/C 05-VV-009 16 212 Fire

PSV-2003 H/C 05-VV-0010 16 205 Fire

PSV-2004 H/C 05-VV-0010 16 212 Fire

PSV-2201 H/C 05-VV-013 23 316 Fire

PSV-2202 H/C 05-VV-013 23 230 Fire

PSV-2203 H/C 05-VV-014 23 316 Fire

PSV-2204 H/C 05-VV-014 23 230 Fire

PSV-2501A LPG 05-VV-020 14.5 85 Fire

TAG NO. Service LOCATION Set

pressure

Kg/cm2 g

Relieving

Temp ° C

Selection

Basis

PSV-2501B LPG 05-VV-020 14.5 85 Fire

PSV-2601A LPG 05-CC-006 29.5 110 External fire

PSV-2601B LPG 05-CC-006 29.5 110 External fire

25

PSV-3101 Fuel oil 05-VV-026 3.5 526 External fire

PSV-3102 Fuel oil 05-VV-026 3.5 526 External fire

PSV-3105 HP steam 05-VV-027 43 266 Fire

PSV-3108 LP steam 05-VV-035 6.5 173.5 Fire

PSV-3109 LP steam 05-VV-035 6.5 173.5 Fire

PSV-3201 LPG 05-VV-029 14.5 96 Fire

PSV-3202 LPG 05-VV-029 14.5 96 Fire

PSV-3203 FG 05-VV-020 14.5 60 Fire

PSV-3204 FG 05-VV-020 14.5 60 Fire

PSV-

43002A/B

Inst Air 05-

VV0037A/B

9.0 186.6 Fire

PSV-4401 MP Steam

05-MD-001 15 285 C/V failure

PSV-4402 MP Steam

05-MD-001 15 285 C/V failure

PSV-0000 HC Salt dryer 16 Ambient

PSV-0000 HC Salt dryer 16 Ambient

b) LIST OF TSV’s

TAG.NO SERVICE LOCATION SP kg/cm2 Relieving Temp.

Selection Basis

TSV-1101 Crude 35.5 150 Thermal ExpansionTSV-1102 Crude 35.5 150 “TSV-1103 Crude 35.5 150 “TSV-1104 Crude 35.5 150 “TSV-1105 Crude 35.5 150 “TSV-1201 CW 6 65 “TSV-1202 CW 22 65 “TSV 1301 Crude 43 215 “TAG.NO SERVICE LOCATION SP kg/cm2 Relieving

Temp.Selection Basis

TSV 1302 Crude 43 175 “TSV 1303 Crude 43 215 “TSV 1304 Crude 43 225 “TSV 1305 Crude 43 255 “TSV 1307 Crude 43 305 “

26

TSV 1308 Crude 43 65 “TSV 1604 CW 6.0 65 “TSV 1605 CW 6.0 65 “TSV 1606 CW 6.0 65 “TSV 1703 CW 6.0 65 “TSV 1704 CW 6.0 65 “TSV 1705 CW 6.0 65 “TSV 1801 CW 6.0 65 “TSV 1802 CW 6.0 65 “TSV 1803 CW 6.0 65 “TSV 1805 CW 6.0 65 “TSV 1806 CW 6.0 65 “TSV 1807 CW 6.0 65 “TSV 1808 CW 6.0 65 “TSV 1809 CW 6.0 65 “TSV 1810 CW 6.0 65 “TSV 1811 CW 6.0 65 “TSV 1812 CW 6.0 65 “TSV 3101 FO 16.5 245 “TSV 3102 FO 16.5 245 “TSV 3103 FO 3.5 245 “TSV 3104 FO 3.5 245 “TSV 3105 FO 16.5 245 “TSV 3106 FO 16.5 245 “TSV 5002 H/C EE-102A/B 35.5 150 THER.EXPANSIONTSV 5003 H/C EE-103A/B 35.5 150 “TSV 5004 H/C EE-104A/B 35.5 150 “TSV 5005 WATER EE-13B 6.9 65 “TSV 5006 WATER EE-12 A/B/C 2.2 130 “TSV 5007 WATER EE-16D 6.9 65 “TSV 5008 WATER EE-16E 6.9 65 “TSV 5009 WATER EE-16F 6.9 65 “TSV 5010 H/C EE-106A/B 43 210 “TSV 5011 H/C EE-105A/B 43 250 “TSV 5012 H/C EE-107A/B 43 310 “TSV 5013 H/C EE-108A/B 43 310 “TSV 5014 H/C EE-18 C/D 2.5 150 “TSV 5015 WATER EE-17D 6.9 65 “TAG.NO SERVICE LOCATION SP kg/cm2 Relieving

Temp.Selection Basis

TSV 5016 WATER EE-19B 6.9 65 “TSV 5017 WATER EE-109 6.9 65 “TSV 5018 WATER EE-110A/B 6.9 65 “TSV 5019 WATER 6.9 65 “TSV 5020 WATER EE-111A 6.9 65 “

27

TSV 5021 WATER EE-111B 6.9 65 “TSV 5022 H/C EE-103C 35.5 150 “TSV 5023 H/C 43 210 “TSV 5024 H/C EE105C/D 43 250 “TSV 5025 H/C EE-105 A/B 43 250 “TSV 5026 H/C EE-107 C/D 43 310 “

2.12 LIST OF CONTROL VALVES

S.No. TAG NO. SERVICE SIZE(in.)1 BOILER FEED WTR 12 5LV2602 RICH AMINE TO ARU 13 5LV3104 STM CONDEN. TO FLASH DRM 14 5LV3106 LP STM COND. FRM VV-035 15 5FV1807 HY. NAPHTHA FOR GAS OIL 1.56 5FV2502 LPG BOOSTER PMP FLW 1.57 5LV3202 LPG TO LPG DRM VV-029 1.58 5PV1701 VENT FRM VV-003 1.59 5FV2501 LPG SURGE DRM 210 5PV3111 FO TO VV-026(BPC) 211 5FV1508 STRIPPING STM TO CC-001 BTM. 212 5FV2011 HY. NAPHTHA TO KERO R/D 213 5FV2503 LPG FRM PA-014A/B 214 5PV1415 FO TO HTR 215 5PV1504A FG TO FLARE FRM CC-001 216 5PV1504B FG TO VV-002 217 5PV1912 LPG PRODUCT R/D 218 5PV2011 HY. NAPHTHA TO STORAGE 219 5PV3203 LPG TO FG KOD VV-028 220 5PV4406 HP STM TO DESUPER HTR 221 5SDV1406 FG SUPPLY(PILOT) 222 5SDV1701 DRAIN FRM VV-003 223 5SDV1901 CAUSTIC SOL. EX VV-006 224 5SDV1902 WASH WTR EX VV-007 225 5SDV1903 WTR EX VV-008 226 5SDV1904 CAUST. WASH WTR EX VV-016 227 5SDV2001 CASTIC EX VV-009 2

S.No. TAG NO. SERVICE SIZE(in.)28 5SDV2002 WASH WTR EX VV-010 229 5SDV2003 WTR FRM VV-025 230 5SDV2201 CAUSTIC EX VV-013 231 5SDV2202 WASH WTR EX-VV-014 232 5SDV2203 WASH WTR EX VV-015 233 5SDV2601 AMINE SETTLER BTM 2

28

34 5SDV2602 LPG AMINE ABSORBER BTM 235 5LV1201 BR IN FRM DSTLR TO DGASR 236 5LV3103 FO TO VV-026 337 5FV1201 2nd STAGE DESAL. WTR I/L 338 5FV1409 PLANT AIR FOR DECOCKING 339 5FV2501 LPG TO AMINE ABSORBER 340 5LV1602 SOUR WTR TO VV-005 341 5PV3202 LP STM TO LPG VAPORISER 342 5SDV1401 FO RETURN 343 5LV1202 1st STAGE DIST. WTR I/L 344 5TV1702 NAPH. STAB. BTM. SAT. EE-018A/B 445 5FV1401 CRUDE TO HTR PASS-1 446 5FV1402 CRUDE I/L PASS-2 447 5FV1403 CRUDE I/L PASS-3 448 5FV1404 CRUDE I/L PASS-4 449 5FV1804 HSD R/D 450 5FV2206 KERO/ATF COALASCER O/L 451 5FV3102 HP STM TO EE-028A/B/C/D 452 5HV1701 STABISER O/H VAPOUR 453 5PDV1420 ATM STM TO HTR 454 5SDV1402 FO SUPPLY 455 5SDV1601 SOUR WTR TO SRU 456 5SDV2501 LPG TO LPG SURGE DRM 457 5PV1423 FG TO HTR 658 5FV1410 DECOCKING STM TO HTR PASS-1 659 5FV1412 DECOCKING STM TO HTR PASS-3 660 5FV1413 DECOCKING STM TO HTR PASS-4 661 5FV1414 DECOCKING STM TO HTR PASS-2 662 5FV1505 TOP RFLX TO CC-001 663 5FV1805 LR TO BL(FPU) 664 5FV1806 LR TO BL STORAGE 665 5HV2001 LN+CAUSTIC TO VV-009 666 5HV2002 LN WTR TO VV-010 667 5HV2201 KERO+ATF+CAUST. TO VV-013 668 5HV2202 KERO+ATF+WASH WTR TO VV-014 669 5SDV1801 LN TO CAUSTIC WASH 670 5FV1501 TOP CIR. RETURN TO CC-001 871 5LV1508 KERO STRIPPER FEED 872 5LV1510 GAS OIL STRIPPER FEED 8

S.No. TAG NO. SERVICE SIZE(in.)73 5SDV1403 FG SUPPLY 874 5LV1206 CRUDE BOOSTER PMP D/S 875 5FV1502 ATF/KERO CR RETURNED TO CC-001 1076 5TV1116 EXCH-05-EE-006 A/B BYPASS 12

29

PROCESS DESCRIPTION

30

CHAPTER-3

PROCESS DESCRIPTION

PROCESS DESCRIPTION

3.1 BASIC OPERATIONS INVOLVED

In Atmospheric Unit, Crude Oil is separated into various fractions in fractionation

column based on relative volatility, boiling point and condensation temperature ranges of

the various components. These fractions have different properties. Most of them are

lighter then crude accepting the bottom product LR (Long Residue).

Basic operation involved in AU are as follows:-

Crude Preheating and Desalting

Crude heating in Charge Heater

Atmospheric Distillation

Naphtha Stabilization

LPG Amine and Caustic washing

Light Naphtha Caustic washing

Kero/ATF Caustic washing

For the sake of simplicity in process description, Atmospheric Unit is divided into a

Number of subsections as given below:

Crude Preheat Train I (old and new)

Crude Desalter

Crude Preheat Train II (old and new)

Crude Charge Heater

Atmospheric Distillation Column

Naphtha Stabilizer

Product Cooling and Run Down system

LPG Amine wash system

LPG Caustic wash system

Light Naphtha Caustic Wash system

Kero/ATF Caustic wash system

Chemical Injection system.

31

3.2 CRUDE CHARGING INTO UNIT

Refer P&ID’s 3551-05-02-41-0111 Rev 2

Crude from crude storage tanks in GRE crude offsite area is pumped into Atmospheric

Unit through a 14” header. In the battery limit of AU double block valve and a spectacle

blind is provided for positive isolation. Crude is received at 9.5 Kg/cm2 g pressure and

ambient temperature. The following instruments are provided in the crude inlet line to the

Unit within Unit battery limit.

Local pressure gauge PG-1101

Pressure Transmitter PT-1102 with DCS indication

PSL-1123 with alarm in DCS.

From the 14” headers, Crude Booster 05-PA-001 A/B/C/D/E take suction and deliver

crude to the preheat Train-I through a 12” discharge header. Provision was made at B/L

to receive LAB plant Return stream along with crude. The following connections are

provided in the suction line of booster pumps inside battery limit.

1” Caustic solution line in order to maintain pH of Desalter effluent.

2” demulsifier solution line to break crude and water emulsion.

10” LR circulation line for start-up purpose.

2” service water line for unit flushing.

3” slop line from CBD Pump Discharge for reprocessing the slop.

The crude booster pumps have a capacity of 261 m3/hr . The normal discharge pressure of

crude booster pump is 23.87 Kg/cm2 g. Normally two crude pumps will be in operation

and one will remain standby.

The following instruments are provided in the discharge header of crude booster pumps.

Local Temperature Gauge TG-1102

Temperature Indicator TI-1101

PT-1103 with DCS indication and recording

Local Pressure Gauge PG-1104

PSHH-1130 with interlock to trip Crude booster pumps

FI-1101 with flow tantalizer and recorder at DCS and sends signals to furnace pass

ratio balancing and also heat duty control

32

PV-1206/PV-5001 is provided on common discharge line of crude booster pump for

controlling the Desalter pressure through PIC-1206 by Sequential action. A 2” LP steam

connection is provided in the discharge Header of Crude booster pump for air removal of

the system during start-up.

3.3 Crude Preheat Train-I

Refer P&ID’s 3551-05-02-41-0111 Rev 2

Crude preheat trains are provided to accomplish the following.

To heat the crude oil and bring it to the required desalting temperature.

To further heat the crude oil after desalting.

To recover heat from out going products and circulating reflux streams by heating the

crude oil, thereby improving fuel economy in operation at unit.

Crude Preheat Train–I is divided in to two parts.

1. Preheat Train–I (Old)

2. Preheat Train – I (New).

After PV-1206/PV -5001 Crude is divided in to two parts by H/C 5001 (New train) and

HIC 5002 (Old train). After HIC 5002 Crude is passed through exchanger EE-01, EE-02,

EE-03 (shell side) and then through EE-04 and EE-05 (Tube side). At the outlet of EE-05

Crude oil pick up heat gain temperature to 127 ° C (Kero run) / 123 ° C (ATF run)

Preheat Train –I (New) – After HIC 5001 Crude passes through exchangers EE-102A/B

(shell side) then Parallel to EE-103A/B/C (tube side) & EE-104A/B (shell side) and it is

heated up to 130 ° C. Then both streams are joined together and feed to desalter VV-01A

via HIC-5003.

New preheat Train – I Temp. Profile

After HIC 5001, Crude flows through exchanges EE-102A/B shell side. Crude is

heated up to 74.3° C LGO (Tube side) is cooled from 134.9° C to 65° C.

Crude then passes through EE-103A/B/C/ and EE-104A/B in parallel. Crude

flows in EE-103A/B/C tube side and further get heated from 74.3° C to 120.5° C.

In exchanger EE-103A/B/C shell side LR gets cooled from 165° C to 120° C.

33

In Exchanger EE-104A/B Crude passes in shell side and gets heated from 74.3° C

to 138.8° C tube side flow is Kero – I C.R. and it is cooled from 185.7° C to 128°

C.

Combined outlet from exchanger EE-104A/B and EE-103A/B/C then joins with

old Pre-heat Train – I stream via H/C 5003.

All exchangers in Preheat Train-I are provided with bypasses to tackle maintenance/tube

Leakage problems. Thermal Safety Valves (TSV) are provided on each of exchanger

outlets on the crude side (cold stream) to take care of pressurization due to thermal

expansion of Local pressure gauges and temperature indications in DCS are provided

across every exchanger for performance monitoring of the particular exchanger unit.

The purpose of heating up crude in preheat train I before Desalter is to improve oil’s

Fluidity, reduce it’s viscosity, and to help mixing desalter water thoroughly with it. Here

crude is preheated from 30° C to 127° C for normal Kero Case (for ATF case 123.6° C).

From Crude Preheat Train-I, crude is routed to two stage Crude Desalter. MV-1201 &

MV-1202 are provided just upstream of two stage desalter. Normally desalting water is

added upstream of these mixing valves. Provision exists to add desalting water into crude

upstream of 05-EE-005. The purpose of the mixing valve is to thoroughly mix the crude

and water prior to desalting.

3.4 CRUDE DESALTING

Refer P&ID No. 3551-05-02-41-0112 Rev.2

Crude oil brings along with it salts, particularly those of sodium, Magnesium etc, metals

like Arsenic, Vanadium etc, and mud. Although these are present only in small amounts,

their presence can result in serious problems in down stream equipment’s viz. Heat

exchangers, charge heater and Atmospheric column. Hence the need of their removal is

important before processing.

At high temperatures, Magnesium chloride decomposes and forms Hydrochloric acid,

corroding trays in the top section of column and tubes of overhead condensers etc. The

presence of calcium and sodium salts can cause plugging of heat exchanger and heater

tubes, there by rapidly reducing heat transfer co-efficient. The presence of Arsenic acts as

34

a poison to platinum catalysts if it is used in down stream process units. Presence of these

salts also promotes coke formation in heater tubes which results in increased pressure

drop as well as less heat transfer rates. The excessive coke formation results in escalation

of hot spots on heater tubes which can have serious and disastrous consequences for

heater tubes. At high temperature salts in crude oil show a tendency to deposit along heat

exchange surface of the equipment.

Caustic injection upstream of desalter in crude is done to neutralize acids present in crude

and convert them into water solvable salts. These salts are then removed by desalter

water in desalter. Caustic injection down stream desalter is provided to neutralize any

other acid traces formed at desalter operating conditions.

Brine is associated with crude both as a fine suspension of droplets and more permanent

emulsion. To break this tight emulsion, Demulsifier is added. This ensures better function

of Desalter. Demulsifier is injected into crude upstream of desalter. Provision also Exists

for injection of Demulsifier into the crude line at B/L for better mixing.

In fact, both caustic solution and Demulsifier are added into the crude before the first

exchanger in the preheat train I.

3.4.1 DESALTERS OPERATION

Two stage crude desalter comprising of two identical desalting units. 05-VV-00-001A/B

has been provided for reducing salt content in crude oil to the level of <0.5 PTB. Two

stage Desalter unit arrangement is provided to handle crude with widely carrying salt

contents. Depending upon salt contents in crude both desalter units can be operated either

in series or Individually but not in parallel. Any of the two desalters can be isolated and

bypassed. Crude desalter operates at 12.5 Kg/cm2 g pressure. It is designed to bring down

the salt content of the crude from 165 ppm to less than 0.5 ptb. Also, the water content of

crude is brought down from 0.2% volume to less than 200 ppm at the exit of desalter.

Crude and desalter water enters the Desalter (05-VV-00-001A/B) from its bottom. Crude

outlet from top of the vessel is connected to the Desalted crude pumps (05-PA-00-

002A/B/C) suction. For draining oily water and handling wash streams, desalter drain

connections to CBD/OWS are provided.

35

The material that collects at desalter bottom is a thick sludge that is corrosive and often

has a tendency to choke the piping. This material needs to be cleaned periodically. For

this de-sledging arrangements in both the desalter have been provided. Stage-I Desalting

water Pumps 05-PA-00-015A/B discharge is associated with distributors inside both the

desalter. FI-1211A and FI-1210B indicate desludging water flow to 05-VV-001A and 05-

VV-001B respectively. Desludging is a batch process. When desludging water is injected

in the desalter through distributor, it loosens up the muck collected at the bottom, and

facilitates its easy exit from outlet. Meticulous care should be taken during this operating

as sudden jerk can upset oil water inter phase, leading to water and salt carryover to

CDU. On stage-I desalter 05-VV-001A, inter phase level controller ILIC-1202 is

provided to ensure smooth functioning of the unit. In addition one inter-phase level low –

low switch LSLL-1207 along with alarm is provided to prevent inter phase from getting

lost and resulting into oil carryover along with brine from desalter. Another low–low

level (oil) switch LSLL-1203 with alarm (which in effect is high inter phase level) is

provided. In case of low oil level, amperage in desalter increases due to increased

conductivity and may eventually lead to short-circuiting. On actuation, this switch trips

power supply to desalter to prevent such an eventuality.

Since desalter is liquid filled vessel, the pressure control is achieved by manipulating PV-

1206/PV5001 provided on crude pump discharge line upstream of preheat train-I. Panel

mounted push buttons (to start PB-1201 A& to stop PB1201B) are provided to control

power supply to desalter. Actuation of LALL-1203 trips power supply to desalter, PSV-

1201A & 1201 B are provided to protect 1st stage desalter from over pressurization due to

blocked outlet. The discharge of these safety valves is routed to flash zone of

Atmospheric Column. Since this is a liquid discharge, safety valve outlet line is kept free

draining towards atmospheric fractionating column to avoid formation of liquid pockets.

Also the PSV 1201A/1201B are located close to the column to reduce the discharge pipe

length where two-phase flow may occur after PSV discharge.

Similar instrumentation and other facilities exist for II stage desalter 05-VV-001B also.

On II stage desalter 05-VV-001B, inter-phase level controller ILIC-1202 is provided to

maintain inter-phase level in the desalter unit. It can manipulate either LV- 1202 on I

stage desalter water pump discharge or LV-1201 on cold brine outlet from 05-VV-001A.

36

The selection for this is made by SS-1201/Ss-1202. One interphase level low-low switch

LSLL-1208 along with alarm is provided to prevent interphase from getting lost and

resulting into oil carryover along with brine from desalter. On actuation the switch closes

LV-1201 through de-energization of SOV-1201. The selection for this is made by SS-

1207. Local PG/TG are provided to indicate desalter pressure and temperature. PIC-1206

on desalted Crude line is provided for manipulation of PV-1203/PV5001 on crude charge

pump discharge line. Another low-low level (oil) switch (LSLL-1204) along with alarm

(which in effect is high inter-phase level) is provided. In case of low oil level, amperage

in desalter increases due to increased conductivity & may eventually lead to short-

circuiting. On actuation this switch trips power supply to desalter.

Since desalter are liquid filled vessels, the pressure control is achieved by manipulating

PV-1206/PV5001 provided on crude pump discharge line upstream of preheat train-I.

PSV-1202A &1203B are provided to protect 2nd stage desalter from over pressurization

due to blocked outlet.

To ensure that the crude and water are mixed thoroughly, the mixing valves MV-

1201/1202 respectively are provided at the upstream of both the desalter.

Depending upon salt content in crude, following three cases for desalter operation are

considered:

1) Both Desalter Stages in operation

2) Only Stage I Desalter in operation

3) Only Stage II Desalter in operation

All these cases are taken up in detail in following pages:

1) Both Desalter stages in operation in series:

Crude from preheat train I is premixed with desalter water in mixing valve MV-1201 at

upstream of desalter 05-VV-001A. The desalting water drawn from 05-VV-001B is

pumped by 05-PA-015A/B (I stage desalting water pumps) under interphase level

controller LIC-1202 of 05-VV-001B to 05-VV-001A. Manual selection for the interphase

control of 05-VV-001B on outgoing brine from it is made by SS-1202. Interphase of 05-

VV-001A is indicated by ILIC-1201 and is controlled by operating LV-1201 on outgoing

brine from 05-VV-001A. Linking of ILIC-1201 with LV-1201 operation is manually

done by SS-1201. This linking automatically deselects LIC-1202 of 05-VV-001B from

37

LV-1201 operation 05-VV-001A. Interphase level low low as indicated by LSLL-1207 is

manually selected by SS-1207 to actuate SOV-1201 and close LV-1201 on outgoing

brine line from 05-VV-001A. This selection automatically deselects LSLL-1208 on 05-

VV-001B and this acts as mere interphase level low-low alarm only in 05-VV-001B.

Crude from 05-VV-001A overflows to 05-VV-001B for further and final desalting. Water

for desalting in this unit is drawn from 05-VV-005 by 05-PA-016A/B (II stage desalting

water pumps) under flow control FIC-1201, heated in shell side of 05-EE-012A/B/C and

enters through mixing valve MV-1202. Its flow towards MV-1201 is kept completely

closed to receive adequate quantity of desalting water in 05-VV-001B. Brine from 05-

VV-001B bottom is diverted to suction of 05-PA—015A/B and again follows a complete

cycle as described earlier. PIC-1206 on desalted crude outlet from desalter is selected to

maintain its pressure by manipulating PV-1206/PV5001 sequentially.

2) Only stage II Desalter in operation

In this case only 05-VV-001B is put in operation and 05-VV-001A is completely

isolated/bypassed from crude, desalting water and brine networks. Crude from preheat

train I enters 05-VV-001A through MV-1201 and leaves through top to suction of 05-PA-

002A/B/C/D/E (desalted crude pump suction) under desalted crude outlet pressure

control PIC-1206. This controller manipulates the pressure of PV-1206/PV5001 provided

at crude line before the preheat train I. Water for desalting in this unit is drawn from 05-

VV-005 by 05-PA-016A/B (II stage desalting water pumps) under flow control FIC1201,

heated in shell side of 05-EE-012A/B/C and enters through mixing valve MV1201. Inter-

phase of 05-VV-001A as indicated by ILIC-1201 is controlled by LV-1201 operation is

manually done by SS-1201. This linking automatically de-select LIC-1202 of 05-VV-001

from LV-1201 operation of 05-VV-001A. Inter-phase level low low, as indicated by

LSLL-1207 is manually selected by SS-1207 to actuate SOV-1201 and close LV-1201 on

outgoing brine line from 05-VV-001A. This selection automatically de-links LSLL-1208

of 05-VV-001B from LV-1201 operation.

3) Only stage II Desalter in operation

38

In this case only 05-VV-001B is put in operation and 05-VV-001A is completely

isolated/bypassed from crude, desalting water and brine networks. Crude from preheat

train I enters 05-VV-001B through MV-1202 and leaves through top to suction of 05-PA-

02A/B/C/D/E (desalted crude pump suction) Desalter pressure is controlled by PIC-1206

provided at desalted crude outlet line. PIC-1201 controls by manipulating

PV-1206/PV5001 on crude to preheat train I. Water for desalting in this unit is drawn

from 05-VV-005 by 05-PA-016A/B (II Stage desalting water pumps) under flow control

FIC-1201, heated in shell side of 05-EE-012A/B/C and enters through mixing valve MV-

1201. Interphase of 05-VV-001B as indicated by ILIC-1201 is controlled by LV-1201.

Finally cooled brine of 05-VV-001B, still appearing as outgoing from 05-VV-001A.

Linking of ILIC-1202 with LV-1201 operation is manually done by SS-1202&SS-1201.

This linking automatically de-selects ILIC-1201 of 05-VV-001A from LV-1201

operation 05-VV-001A. Interphase level low, as indicated by LSLL-1208 is manually

selected by SS-1207 to actuate SOV-1201 and close LV-1201 on outgoing brine line

from 05-VV-001A. It is important to be noted that actually it is outgoing brine of 05-VV-

001A and not from 05-VV-001B. This section automatically de links LSLL-1207 of 05-

VV-001A from LV-1202 operation.

Some of the parameters that are to be closely monitored to realize operation are:

Water Injection Rate

Chemical Injection Rate

Oil Water Interphase Level

Mixing valve performance (Delta P)

Desalter Pressure

Desalter Temperature

Influence of these variables on desalter operation is discussed later in a section discussing

effect of operating variables.

Sample points are provided from crude oil outlet from desalter. Crude oil or water from

respective sample point flows through a coil in sample cooler on outside of which cooling

water flows to cool the hot sample. Sampling cock lines have been provided with a 2” LP

steam flushing line to clean the line of any crude after taking sample. Sample cocks are

39

provided on each desalter at various elevations of the vessel. These are used to check

interphase level physically against that indicated by corresponding LIC.

3.4.2 Desalter Water System

Water used for desalting is stripped sour water from SRU. As other alternative, DM/SW

can also be used. Sour water or DM water/service water is first collected in desalter water

vessel 05-VV-005. Desalter water drum level is maintained by LIC-1205, manipulating

LV-1205 acting on incoming stripped water line/ DM water line in sequence. Provision

of Caustic solution injection in this drum is there to neutralize acids formed in crude at

elevated desalter temperatures.

Combined desalting water from desalter water drum 05-VV-005 is pumped by Second

Stage Desalting Water Pumps 05-PA 16A/B/C to 05-VV-001B under flow control FIC-

1201. It is heated up to about 99 C in shell side of 05-EE-012A/B/C by exchanging heat

with brine solution going out from desalter, which gets cooled from 122/118.5 C to 63-

59.5 C. TI-1208 is provided at the downstream of this exchanger on the desalter water

line. This heated water can join the crude header upstream of crude oil mixing valve MV-

1202 of desalter 05-VV-001B. Water containing dissolved salts from crude (also called

brine) in 05-VV-001B is pumped out by First Stage Desalting water pump (05-PA-

015A/B) to 1st stage desalter. This brine joins the crude header upstream of crude oil

mixing valve MV-1201 of Desalter 05-VV-001A. Provision is also available for make up

desalter water from Desalter drum 05-VV-001 to the first stage desalter pump 05-PA-

015A/B. The brine solution from 1st stage desalter 05-VV-001A is cooled in tube side of

05-EE-012A/B/C and 05-EE-013. Finally cooled brine is sent to brine degasser 05-VV-

034. From brine degasser it is routed into OWS Selector switches have been provide for

inter-phase controllers of desalter 05-VV-001A & 05-VV-001B to manipulate LV-1201

on outgoing brine. On very low desalter level actuated by an low level alarm, SOV-1201

shall close LV-1201 to stop further withdrawal of water, thus eliminating risk of oil

carryover with brine.

3.5 CRUDE PREHEAT TRAIN - II

40

Refer P&ID’s 3551-05-02-41-0113 Rev 2

Crude preheat train–II is desalter outlet to crude charge heater (05-FF-01). Major

equipments at this section are shell and tube type heat exchangers. Crude preheat train –

II can be subdivided to crude preheat train – II (old) and Crude preheat Train – II (New).

New Preheat Train – II

Desalted crude from PA-02A/B/C/D/E is divided in to two streams, via HIC 5005 (new

preheat Train) and HIC 5006 (old preheat train – II).

After HIC 5006, Crude passes through shell side of exchanger 05-EE-06A/B and

exchanges heat with Kero-II CR from 05-PA-10A/B/C. TC-1116 has been provided at

the inlet of Kero-II CR to adjust the crude inlet temperature to desalter at a desired value.

Further, Crude passes through 05-EE07A/B/C in series and exchanges heat with LR from

05-EE-10B outlet. Again, crude is heated in 05-EE-08A/B and 05-EE-09A/B by HGO

and LGO CR streams in series. LR from the discharge of PA-51A/B/C is passes through

05-EE-10A/B/C/D in counter current manner with crude coming out from EE-09A/B,

where heat transfer takes place from LR to Crude. Crude from 05-EE-10A/B/C/D

combines together and combined stream is joint with the stream of new preheat train – II

(i.e. EE-108A/B). And feed to furnace 05-FF-01.

One 10” line from EE-108 o/l to EE-10 inlet is provided. Crude flow to new preheat train

– II is measured by 05-PI-5028

Crude Preheat Train – II (New) – Temp. Profile.

After H/C 5005 desalted crude is divided in to two streams and flows to exchanger 05-

EE-106A/B/C/D shell side and exchange 05—EE-105A/B/C/D/E tube side in parallel.

In exchanger EE-106A/B/C/D crude is heated from 128° C to 184.2° C by exchanging

heat from tube side hot stream LGO product. LGO product is cooled from 282° C to 138°

C in exchanger EE-105A/B/C/D/E crude is heated from 128° C to 228.7° C by getting

heat from hot stream LR. LR is cooled from 265° C to 165° C.

Combined outlet of EE-106 & EE-105 again divided in to two branches parallely and

pass through exchanger EE-107A/B/C/D and EE-108A/B tube side. In exchanger EE-

107A/B/C/D crude is heated from 206.8° C to 291° C and hot stream L.R. is cooled from

360.4° C to 265° C. In exchanger EE-108A/B crude is also heated from 206.8° C to 291°

41

C and hot stream HGO CR is get cooled from 326° C to 275° C heated crude @ 291° C is

then joins with EE-10A/B/C/D crude oil line and then fed to furnace FF-01.

3.6 FURNACE

Refer P&ID No. 3551-05-02-41-0114A Rev.3

3551-05-05-42-0114B Rev.3

Major equipment of this section is atmospheric heater, air pre-heaters, ID fan, FD fans

and Steam air decoking pot. Description of atmospheric heater is divided into following

subsections:

Process System

Fuel System

Air Preheating System

Steam-Air Decoking System

These sections are described below in detail:

3.6.1 PROCESS SYSTEM

Crude oil from Preheat Train–II is heated to desired vaporization temperature of 375 C in

crude furnace before entering the atmospheric column 05-CC-001 for fractionation.

Crude enters crude charge heater at the top of the convection zone. Bottom of the

convection zone the coils come out and enter the radiation zone from radiation zone,

crude flows to atmospheric column 05-CC-001.

The heater 05-FF-001 is a box type furnace having four parallel passes of 6” size,

numbered as pass 1 to pass 4.

Flow in each pass is regulated by individual pass flow controller FIC-1401 through FIC-

1404 (provided on each branch or pass). Ratio of crude flow in a particular pass to total

crude flow is maintained by a ratio controller. The crude flow in each pass is controlled

by a pass balancer in such a way that the weighted average temperature at the outlet of

each pass is maintained almost same. Crude flow through each pass is automatically

adjusted by individual pass flow controllers of each pass. Pass balancer receives software

input signals from FIC-1101 controlling crude flow, current values of all crude heater

pass flows and temperature as indicated by FIC-1401 through FIC-1404/TI-1407 through

42

TI-1410. Pass balancing is an advanced control feature, conceived for future

implementation. Pass balancer output is utilized by atmospheric column duty controllers

on circulating refluxes also. The distribution of crude through each pass should be

adjusted in such a way that the heat duties and hence out let temperature of all the passes

is more or less same. Depending on heat duty variation pass flow will vary. Inequalities

of flow through each pass to the extent of 10% can be tolerated, while operating on

manual mode or pass balancing is not working.

All the four passes of 05-FF-001 join together at the outlet of the radiation zone and then

enter the crude column 05-CC-001. Pressure gauges and temperature indications are

provided at all the external crossover of pass flows from convection to radiation section.

To avoid repetitive description, features of only pass 1 have been taken up. For other

passes identical arrangements exist.

FIC-1401 controls and indicates crude flow through pass 1. Through dual transmitter FT-

1401 from the same flow element, one flow low-low alarm FAL-1401B has been

provided to indicate vary low flow condition in pass 1. Actuation of this alarm will trip

the fuel supply to all burners of the heater excluding pilots. TI-1432/PI-1308 indicates

temperature/pressure of all pass flow control valves.

TI-1409 indicates coil outlet temperature (COT) of crude at pass 1 outlet High

temperature software alarm on the COT has been provided to alert the operator against

inadequate flow or harder firing in that particular pass. Prolonged high temperature may

lead to cooking up of that particular pass. Software signal of this TI-1409 is utilized by

pass balancer also. Finally heated crude enters a common manifold of 28” size, called

transfer line before entering atmospheric column.

TIC-1416/TI-1413 indicates combined, final coil outlet temperature of the crude. The

temperature indicator controller TIC-1416, which regulates the quantity of fuel to the

furnace, controls the final crude outlet temperature of the common transfer line. PI-1428

indicates pressure at radiation zone outlet in common transfer line. Pressure drop across

pass I measured as a difference of PI-1401 & PI-1428 readings is indicated in dc.

Pressure drop across the heater coil is a measure of internal tube condition and increase in

pressure drop indicates tube fouling due to coke formation in the tubes.

43

Turn down ratio for the heater is spelt out in section 1. Emergency coil steam connection

are give in each pass, down stream of pass flow control valves to displace the crude from

the coil to the column during any emergency or after normal shut down operation.

Soot blowers, using MP steam are provided in convection zone of the heater. Need of

soot blowing will be indicated by poor heat pick up in convection zone and slight

increase in flue gas temperature.

Emergency steam, decoking steam connections are taken from 10” MP steam header.

Snuffing steam (Box purging steam) connection in header boxes and radiation zone of the

heater are provided to extinguish fire and provides steam blanketing LP steam is used for

the above snuffing steam header.

Soot blower steam connections are taken from 4” MP steam header. To facilitate safe

approach to emergency steam even during an emergency scenario like fire in heater area,

common valve on emergency steam and box purge steam has been provided at a safe

distance of at least 15 meters from heater.

3.6.2 FUEL SYSTEM

05-FF-001 is a balanced draft furnace. Both the convection and radiation sections are

used for heating crude. The combustion chamber houses the radiant tubes. In this section

heat is primarily transferred by radiation from the flame and hot combustion products.

The convection section provided at the top of the radiation section serves to increase the

thermal efficiency of the furnace by removing further heat from the flue gas. The

radiation section has four identical cells & each cell has two flow passes. Tubes in

radiation section are arranged vertically along the walls. Convection selection has

horizontal tubes.

05-FF-001 is a dual fired furnace i.e. either fuel gas or fuel oil or both can be used as fuel.

The furnace has 19 burners. Each burner is mounted vertically upward at furnace floor.

Furnace fuel systems are discussed below.

3.6.2.A FUEL GAS SYSTEM

Fuel gas (FG) from battery limit is supplied by a 8” header. The FG line is steam traced

to avoid condensation of heavier components in it inside the line itself and carry-over of

44

hydrocarbon liquid droplets to the burner. To arrest carry over of foreign particles like

rust etc a 100-mesh strainer is provided on the line.

FG to main burners passes through a shut down valve SDV-1403 whose open or close

position is indicated in control zoom by ZLH-1403 A/ZLL-1403B. Fuel gas flow to the

main FG burners is indicated in DCS by FI-1417. A local temperature & pressure alarm

PAL-1435B and a very low-pressure trip alarm PALL-1424A is provided at the inlet of

fuel gas to the main burners. If fuel gas pressure falls below PALL-1424A set value,

chances of flame failure in burner, accumulation of un-burnt FG in firebox and possibility

of explosion/back fire through heater opening is exists. Actuation of PALL-1424A will

shut the SDV-1403 on fuel gas supply to the main burners of the furnace, eliminating this

possibility. Minimum stop limit to PV-1423 and all valves on similar duty has also been

considered to avoid extinguishment of FG burners on closure of valve due to signal from

COT controller TIC-1416. Fuel gas pressure and hence flow to burners is controlled by

PIC-1423. It can be cascaded with crude oil coil outlet temperature (COT) controller

TIC-1416 through a selector switch SS-1415, COT can be used to select either for fuel oil

or fuel gas as the fuel-controlling COT. A 2” FG tapping upstream of shut down valve

SDV-1403 has been taken for pilot burners. On the pilot fuel gas line, FI-1416 is

provided to measure FG flow to pilot burners. Pressure in the pilot gas line is manually

adjusted.

A low-pressure alarm PAL-1419B will alert the operator when pilot gas pressure falls.

PB-1401 has provided in the pilot line, for actuating SDV-1406 when the alarm has

come. PG-1418/PG-1425 indicates FG pressure in main and pilot gas lines in field at

heater battery limit.

3.6.2.B FUEL OIL SYSTEM

45

Fuel oil (FO) is supplied to atmospheric furnace by a 4” line under pressure control PIC-

1415.

Flow indicator FI-1420 is provided on main fuel oil supply line and FI-1419B is provided

on the main fuel oil return line from heater. Since this is a closed circuit through which

FO circulation is maintained, the net consumption of fuel oil is measured as the

difference between the two by FDI-1420. Shut down valves SDV-1402/SDV-1401 is

provided on supply & return header of fuel oil. Open and close indications for these

valves are available in control room. A fuel oil pressure low low trip alarm PALL-1427B

and a pre trip alarm PAL-1426A are provide on FO (supply) line. Local PG near heater

battery limit is also provided to indicate pressure the FO in the field for local burner

adjustments.

Since FO is normally a congealable material, it needs to be always maintained in

circulating state. If it is left stagnant and unused in oil burners and piping, it can get

congealed despite the fact that tracing steam of the FO circuit is on. Circulation in heater

area FO piping (forming a closed circuit across all passes called fuel oil ring) is

maintained even when no FO burner is in use. A ratio of 1:1 fuel oil consumption to

return is normally maintained to obtain good control on firing and prevent congealing of

the IFO system. To prevent congealing inside piping, FO circulation past heater as well

as each burner should be maintained. FO is drawn by individual burners through a 3/4”

header from main FO supply line and balance quantity is sent to FO return header. This

return header from cells joins a common return header before leaving heater area. When

there is no need of FO firing in the heater, the circulation can be maintained outside

heater, through a 2” header called ring by pass. Purge steam connection is provided on

each oil burner. Pressure gauges are provided on FO and atomizing steam line of each

burner. FO and atomizing steam lines are routed to each burner of the cell. FO burners

should be kept steam purged when idle. 2” flushing oil connection is provided on FO

(supply) line. CBD/OWS drain is provided on FO (Return) line. These provisions are

used to flash the line within battery limit after heater shut down. When fuel oil is fired, it

is atomized or sprayed as a fine mist for releasing complete combustion. The spraying of

FO is done by de-superheated MP steam in FO burners. Atomizing steam is supplied to

heater through a 4” header. Atomizing steam pressure is controlled by differential

46

pressure controller PDIC-1420, taking pressure signals from FO supply and MP steam

headers simultaneously. It maintains the atomizing steam pressure 1.5-2.0 Kg/cm2 above

fuel oil pressure. Atomizing steam pressure and flow is measured by PI-1421A and FI-

1418. Local pressure gauge is also provided on the atomizing steam header. To arrest

carry over of foreign particles like rust etc, a 100-mesh strainer is provided on the line

3.6.3 AIR PRE HEATER(APH)

The heat carried away by the flue gas after the convection section is utilized for

preheating the air required for combustion. Atmospheric heater has independent air

preheating system to cater combustion air requirement of its burners. The combustion air

required for heater burners is supplied by two forced draft fans, 05-KA-001 A/B. Pilot

burners are self inspiriting type and do not consume combustion air from FD fan

discharge. The combustion air is preheated by flue gases in pre-heaters CAPH (05-FD-

001) & GAPH (05-FD-002). Air pre-heater is a shell and tube type heat exchanger. Cold

air from atmosphere is sucked by FD fans and forced through shell side. The hot flue gas

leaving the convection section of furnace is sucked by an ID fan 05-KA-002 from up

stream of stack damper and through tubes of APH. Flue gas exchanges heat with cold air

in tube side of APH. Cold flue gas from Air Pre-heater is discharged back to at D/S of

stack damper and let out to the atmosphere.

3.6.4 COMBUSTION AIR SYSTEM

Combustion air is sucked from atmosphere by the FD fans. Combustion air from FD fan

enters APH. Bypass is provided to divert cold air with the help of hand operated damper

HIC-1462 & HIC-1463 in case APH outlet temp is below 176OC to avoid corrosion. A

pressure transmitter and thermocouple are provided on the combustion air to F-1.

3.6.5 ID/FD FAN STARTING & STOPPING PROCEDURE

The following procedures are to be followed for starting and stopping of ID & FD fans.

47

3.6.5.1 ID FAN STARTING PROCEDURE

Keep STD open by 100%

Bypass following interlocks

o BPS1418: - ID Fan Circulating Oil Flow Low.

o BPS1415: - ID Fan Speed Low

Start ID Fan from the field. As soon as the motor starts, the indication of motor on

panel changes from red to pink.

Reset HS1456: - ID fan coupling reset. Button is provided near DCS panel

Slowly increase ID Fan suction HIC opening by operating 5PC1451.Incremental

openings of 0.2 to be given. As soon as the motor gets coupled, the coupling

indication on panel turns from red to pink.

When ID suction temperature achieves >160 0 C fully or as per requirement close

STD.

3.6.5.2 ID FAN STOPPING PROCEDURE

Bypass following interlocks

o BPS1418: - ID Fan Circulating Oil Flow Low.

o BPS1415: - ID Fan Speed Low.

Open Furnace Stack Damper completely by increasing 5HC1453 opening

gradually to 100%.

Slowly decrease ID Fan suction HIC opening by operating 5PC1451.The opening

of 5PC1451 to be decreased gradually.

At around 10-15% opening the motor gets decoupled. As soon as motor gets

decoupled, the coupling indication on panel turns from pink to red.

Reduce HIC opening to 0%.

Stop ID fan from the field or by activating 5HS1457C ID Fan Stop Button

provided on DCS panel.

As soon as the motor starts, the indication of motor on panel changes from pink to

red.

48

3.6.5.3 FD FAN STARTING PROCEDURE

Case 1: - No FD Fans Are Running And One FD Fan To Be Started:

Consider the case of FD-1A.Same procedure to be applied for FD-1B.

Open STD by 100%.

Following interlocks to be kept in bypass mode while starting FD fan:

05FSLL1455 - FD1A fan flow low low interlock.

05FSLL1460 - FD1A fan circulating lube oil flow low low

interlock.

05FSLL1453 - Total Air flow low low interlock.

05BPS1412- FD fan1A low speed interlock

Reset SOV1454: - FD1A discharge damper. As soon as it is reset the indication

on motor panel has to change from red color to green color. If it does not changes

into green color I/M to be notified to attend it.

Then, Reset SOV1451: - FD 1A coupling reset SOV. Its indication on panel

remains red.

Start FD. Open slowly 5HIC1451 (by 0.2% MV in steps). At around 15-20%

HIC opening the fan gets coupled with motor. As soon as the motor gets coupled,

the motor indication on panel turns from red to pink. Increase load as per

requirement.

Close STD.

Case 2: - One FD Fan is Running And Other FD Fan TO Be Started

Consider the case FD 1A is running and FD 1B to be started

Open STD by 100%

Following interlocks to be kept in bypass mode while starting FD fan:

05FSLL1454 - FD1B fan flow low low interlock.

05FSLL1463 - FD1B fan circulating lube oil flow low low

interlock.

05FSLL1453 - Total Airflow low low interlock.

05BPS1453- FD fan1B low speed interlock.

49

Then Reset SOV1452: - FD 1B coupling reset SOV .Its indication on panel

remains red.

Start FD. Open slowly 5HIC1451 (by 0.2% MV in steps). At around 15-20%

HIC opening the fan gets coupled with motor. As soon as the motor gets coupled,

the motor indication on panel turns from red to pink.

Reset SOV1455: - FD1B discharge damper. As soon as it is reset the indication

on panel has to change from red color to green color and airflow is obtained.

Adjust FD1 /FD2 load.

Close STD.

3.6.5.4 FD FAN STOPPING PROCEDURE

Consider the case of stopping FD-1A when both FD Fans are running.

Following interlocks to be kept in bypass mode while starting FD fan: -

05FSLL1455 - FD1A fan flow low low interlock.

05FSLL1460 - FD1A fan circulating lube oil flow low low

interlock.

05FSLL1453 - Total Air flow low low interlock.

05BPS1412- FD fan1A low speed interlock

Reduce 5HC1451 opening in steps of 0.2.Simultaneously increase 5HC1452 so as

to maintain same constant combustion airflow to the furnace.

At about 10-15% opening the fan gets decoupled with the motor. As soon as the

motor gets decoupled, close SOV1454 FD Fan 1A discharge damper.

As soon as the motor gets decoupled, the motor indication on the panel changes

from pink to red.

Then slowly reduce 5HC1451 opening to 0%.

Then stop FD1A by pressing HS1451C button provided on DCS panel.

3.6.5.5 FURNACE LIGHT UP PROCEDURE

1. Fully open Stack damper.

2. Check & close all FO / FG / Pilot gas burner valves.

50

3. Start box-purging steam at a rate such that slight steam is seen coming out from

the stack. Steaming is done to serve two purposes

i) To purge out hydrocarbons from inside.

ii) To create a –ve draft inside furnace of about –5mm H2O to –3mm

H2O.

4. Keep low pass flow interlock FALL 1401 through FALL 1404 in line.

5. Stop box purging steam after creating a –ve draft.

6. Start FD fan.

7. Check all igniters.

8. Reset pilot gas shut down valve SOV1406. Ensure all the individual pilot gas

burner valves at the furnace are closed before opening the SOV. By operating

B/V present in d/s of SOV1406 maintain pilot gas header pressure around 1.0-1.2

kg/cm2, pressure gauge is present in the field and flow indication is on the panel.

9. Pinch the primary and secondary air register of the pilot burner to be taken in line.

If needed pinch the air registers of adjacent burners. This is because if airflow is

very high then it is difficult for the burner to be light up.

10. Light up pilot gas burner with electrical igniter.

11. Once all the pilot gas burners are lighted up, gas burners are to be taken in line.

For this, below mentioned procedure is to be followed

a. Bypass PALL1424: - FG low pressure interlock.

b. Now Reset SOV1403: - FG Shut Down Valve. Ensure all the individual

gas burner valves at the furnace are closed before opening the SOV.

c. Take FG c/v 5PC1423 in manual mode. Slowly increase FG c/v opening

manually such that gas pressure at the burner is around 1.5kg/cm2.

d. Then slowly open the gas burner valve to the burner where pilot burner is

in line and light it up.

e. For taking FO burner in line

f. Bypass PALL1427: - FO low pressure interlock

g. Reset SOV1402: - FO Shut Down Valve. Ensure all the individual oil

burner valves at the furnace are closed before opening the SOV

51

h. Now Reset SOV1401: - IFO Return shutdown Valve

i. Open the FO return valve present near Burner Number 19.If this is not

opened then congealing will occur.

j. Maintain 5PC3111 around 8.5 kg/cm2

Take FO c/v 5PC1415 in manual mode. Slowly increase FO c/v opening

manually such that oil pressure at the burner is around 4 kg/cm2.

k. Do steam flushing of the burner by means of flushing steam line present in

each burner.

l. Once steam flushing is over slowly take FO burner in line and light it up.

3.6.5.6 FURNACE CUTOFF PROCEDURE

1. Open Furnace Stack Damper completely by increasing 5HC1453 opening

gradually to 100%.

2. Stop ID Fan as per ID Fan stopping procedure.

3. First bypass following interlock FO Low Pressure Interlock PALL1427.Take FO

c/v 5PC1415 in manual mode.

4. Cut off first oil burners one by one & flush with steam.

5. Keep IFO circulation on

6. Close gas burners one by one except one. For putting off the last burner isolate

gas at main isolation valve. By this FG header to furnace will be depressurized,

then close the burner block valve. Get 5PC1423 & SDV 1403 closed, bypassing

inter lock.

7. After all the gas burners are off, cut off pilot gas burners by closing the main

isolation valve. After putting off all pilot burners, isolate individual burner valves.

8. Blind FG and Pilot gas lines.

3.6.5.7 FURNACE INTERLOCKS

Following interlocks are provided to trip the furnace:

52

1. Fuel Gas pressure at the inlet of furnace goes very low as sensed by PALL-1424A

when the furnace is operating on fuel gas. It will close SDV-1403 on fuel gas line

to main burners of FF-001 only.

FUEL GAS PRESSURE LOW LOW: PALL-1424---BPS 1407---FUEL GAS

SDV CLOSE

2. Fuel oil pressure at the inlet of furnace goes very low as sensed by PALL-1427

when the furnace is operating on fuel oil. It closes SDV-1402/SDV-1401 on fuel

oil supply & return lines.

FUEL OIL PRESSURE LOW LOW: PALL-1427---BPS-1407---FUEL OIL

SDV CLOSE

3. Crude oil flow through individual passes to the furnace goes low as sensed by any

of FALL-1401 to FALL-1404. It will close both fuels to heater excluding pilot FG

05-FC-1401-PASS FLOW LOW LOW—FALL 1401 1.Furnace cut

off IFO SDV

05-FC-1402-PASS FLOW LOW LOW—FALL 1402 1402 close

BPS-1405—2.IFO return

05-FC-1403-PASS FLOW LOW LOW—FALL 1403 SDV1401

close

05-FC-1404-PASS FLOW LOW LOW—FALL 1404 3. FG supply

SDV1403

Close.

4. Actuation of emergency push button shall stop fuel oil/gas to heater.

5. Very low total combustion air flow (FALL 1453)

Fuel Oil SDV 1402 close

53

FALL-1453---BPS 1409---- Fuel Gas SDV 1403 close

Fuel Oil return SDV 1401 close.

6. Very high arch pressure (PAHH 1452)

ARCH PRESSURE HIGH HIGH–PAHH–1452---BPS1410---STACK DAMPER

OPEN

If stack damper doesn’t open with in 30 sec, furnace will cut-off.

7. 05-KA-01A (FD Fan) Circulating Oil flow low low (FALL 1460)

FALL-1460—BPS 1416---FD 1A TRIP

8. 05-KA-01B (FD fan) Circulating Oil flow low low (FALL 1463)

FALL-1463—BPS 1417---FD 1B TRIP

9. Very low speed of 05-KA-01A (FD Fan)

FD FAN 1A SPEED LOW---BPS 1412---FD FAN 1A TRIP

10. Very low suction air flow of 05-KA-01A (FD fan)

FD FAN 1A SUCTION AIR FLOW LOW---BPS 1412---FD FAN 1A TRIP

11. Very low speed of 05-KA-01B (FD fan)

FD FAN 1B SPEED LOW---BPS 1413---FD FAN 1B TRIP

12. Very low suction air flow of 05-KA-01B (FD fan)

FD FAN 1B SUCTION AIR FLOW LOW---BPS 1413---FD FAN 1B TRIP

13. 05-KA-02 (ID Fan) Circulating Oil flow low low (FALL 1457)

FALL-1457---BPS 1418---ID FAN WILL TRIP


14. Very low speed of 05-KA-02 (ID Fan)

ID FAN SPEED LOW---BPS 1415---ID FAN TRIP


15. CAST APH O/LET TEMP. HIGH

TSHH-1497----STACK DAMPER OPEN


3.6.6 DECOKING SYSTEM

54

Steam air decoking (SAD) of atmospheric heater tubes is done to remove coke deposit

from inside heater tubes with the help of steam and air. Removal of coke results in clean

heater tube internals & improves heater performance by better heat transfer to process

field. SAD also achieves low-pressure drop through heater tubes and reduces chances of

hot spot on heater tubes. Increased pressure drop and hard firing in furnace indicates

requirement of steam air decoking of the heater tubes. For this operation a dedicated

arrangement called SAD arrangement is provided. It comprises of decoking pot 05-VV-

017 and piping for Plant Air, Service Water and MP Steam connections to each pass flow

are provided to dislodge coke film deposit from inside the heater tubes. Local and control

room DCS mounted flow indications (FIC-1410, FIC-1412, FIC-1413, FIC-1414) are

provided on each steam connection. Plant air is injected to burn the remaining coke film

deposit clinging inside heater tubes and achieves final cleaning of the tubes. FIC-1409

indicates total flow of plant air into MP steam lines for SAD. Service water quench

provision is given on 05-VV-017 as well as flue gas line to quench the contents before

letting out to atmosphere.

To carry out SAD, pass flow inlet and outlet of the furnace 05-FF-001 are isolated from

process network and connected by means of swinging elbows with the decoking network.

Heater pass flow outlets are connected to the Decoking Drum 05-VV-017. MP steam is

introduced in heater passes and it is fired from outside. Thermal shock caused by flame

cracks coke scales inside tube and flowing steam dislodges them. These are carried to 05-

VV-017 after being quenched in flue gas line as well as decoking pot by service water

from where it is drained out. This operation is called spalling. When no more coke is

removed by spalling as indicated by relatively clear colour of effluent, Air along with

steam is introduced into pass flow to burn the coke of inside tube while firing from

outside. Coke is burnt by oxygen of air and thus tube cleaning is achieved. Burning of the

coke is indicated by increased tube metal temperature and presence of CO/CO2 in flue

gas. Number of passes selected for spalling and coke burning is largely dependant on

limitations posed by steam availability and piping network. Sudden release of coke

during spalling may result in choking of the piping handling effluent or as hot spots on

tube during burning. SAD of only one pass at a time should be done if limitations in

55

steam and SAD piping are experienced. During SAD utmost care should be taken so that

heater tube temperature does not exceed the limit provided.

SAD of other heaters can also be planned along with CDU heater subject to limitations in

steam availability & case of monitoring.

3.7 MAIN FRACTIONATING COLUMN

Please Refer P&ID 3551-05-02-41-0115 Rev.2

The crude after final heating in furnace is fed to the Atmospheric Column for separation

of products by fractionation. Atmospheric column CC-001 contains 51 valve type trays

for side stream withdrawal. The column has a stripping section at the bottom. It has lower

diameters at top and bottom sections than middle to cater to higher vapor load in middle

section. Local pressure gauges and DCS mounted TI are provided to indicate

pressure/temperature profile inside the column.

Description of entire column has been taken up zone wise.

3.7.1 FLASH ZONE

Heated and partly vaporized crude feed coming from fired heater enters the flash zone of

the column above tray no.6 at 375 C. Hydrocarbon vapors flash in this zone and get

liberated. Non-flashed liquid moves down ward, which is largely bottom product, called

Long Residue. Certain degree of over flashing of crude is desirable for proper

stabilization of LR and fractionation of gas oil components. Over flash is achieved by

setting up COT at slightly higher than actually required. This over flashed material is

washed with gas oil coming down from below of 15 th tray. It strips out heavier vapor

components coming up which otherwise would move-up & cause coloration of gas oil

stream. Tray 7th to 14th forms the wash zone section of atmospheric column along with

LR. Flow of over flash liquid can be increased by both increasing COT and condensing

more material on 7th tray gas oil draw off. However, this will result in less gas oil yield

and higher energy consumption without any advantage. Too large flow of over flash

liquid may result in drop in bottom temperature and lighter bottom product, LR.

Over flash flow and temperature is indicated by FI-1504/TI-1527. Flash zone temperature

and pressure is indicated by TI-1502/PI-1525. Min. 1000 mm piping elevation is

56

provided between liquid entry nozzle on 6th tray and U loop bottom tangent line over

which FE-1504 is mounted. This elevation provides adequate liquid build up on up

stream of FE and ensures un-flickering, steady flow through orifice. Additionally it

provides some back pressure which is required to prevent flashing just down stream of

flow orifice due to pressure drop. One line of 3” is provided above 8 th tray to release

uncondensed components from over flashed liquid.

MP steam is introduced in the column below tray 1, at approximately 3.5 Kg/cm2 g and

2300 C for stripping of LR. Steam stripping helps to remove lighter constituents from the

bottom product LR by reducing their partial pressure and vaporize without requiring

addition heat. Hydrocarbon vapors liberated by flashing move up along with steam in the

column for further mass transfer at trays in upper section. Steam flow to column is

controlled by FIC-1506. Steam flow to column is regulated based on outgoing LR

quantity to FPU/Storage. SS-1501 is provided for cut-off the LR Pump 05-PA-051A/B to

storage if LIC-1501 i.e. atmospheric column bottom low level. Desalters PSVs are

released to above 6th tray of fractionating column (CC-01).

3.7.2 OVERHEAD SECTION

Refer P & ID No. 3551-05-02-41-0116 Rev.2

The overhead vapors of Atmospheric Column C-01 at 1120 C/1150 C passes through the

overhead air condensers 05-EA-001 A-H (Fin fan cooler) and trim condenser 05-EE-

0016A/B/C/D/E/F. The condensed Naphtha & steam are accumulated in crude column

overhead reflux drum 05-VV-002.

Top pressure of atmospheric column is maintained by PIC-1504, manipulating PV-

1504A on outgoing uncondensed gases from 05-VV-002 to flare or PV-1504B on

incoming FG from fuel gas header. Condensed hydrocarbons are allowed to settle in

reflux drum where steam condensate settles in vessel boot and is pumped by P42A/B to

desalter water drum 05-VV-004 or sour water stripper of SRU unit under inter phase

controller LIC-1602. Sour water flow is measured by FI-1801 & its pH is indicated by

PHI-1601. On actuation of boot level alarm low (indicated b LAL-1603) SOV-1601 shall

be closed by operation and the flow has cut off. A part of accumulated hydrocarbons in

05-VV-002 is be pumped back to atmospheric column as top reflux by Column reflux

57

pumps 05-PA-005A/B/C under flow control FIC-1505 to control top temperature. This

flow controller can be cascaded with atmospheric column top temperature controller TIC-

1501 for precise control of column top temperature.

Ahuralan is dozed at the top of column to arrest corrosion and ammonia solution is dozed

O/H vapor outlet line to maintain sour water PH level @ 6 to 6.5.

Excess quantity of Naphtha in reflux drum is pumped by stabilizer feed pumps 05-PA-

06A/B/C to stabilizer as feed. Reflux drum level controller LIC-1606 can be cascaded

with discharge of stabilizer feed pump flow controller, FIC-1701.

Minimum flow protection controllers FI-1610B/FI-1611B are provided for discharge of

reflux pumps & stabilizer feed pumps respectively. In the event of low flow in reflux or

stabilizer feed lines due to throttling of control valves, minimum continuous flow to each

pump, this arrangement prevents heating of pump due to closed discharge operation &

resultant damage to pump.

3.7.3 MIDDLE SECTION:

Middle section of the column has circulating refluxes and product withdrawal network. In

order to maximize heat recovery and balance the column loading for maintaining proper

temperature profile across the column, three circulating refluxes (CR) systems are

provided viz. Heavy Naphtha CR, Kero/ATF CR, and Gas Oil CR. These circulating

refluxes are drawn from their respective product draw off trays and are routed to preheat

recovery trains for heat recovery before entering back to the column again.

Duty controllers are provided on CR circuits to control CR flow rates to column. These

duty controllers take corrective action based on actual CR duty & desire CR duty. For a

particular type of crude and crude through put, the CR under reference will have certain

duty. This will be governed by total crude flow and specific heat of CR and is called

desired CR duty. Actual CR duty is also computed by duty controller based on real time

measurement of temperature difference between CR draw off and CR return stream, CR

flow rate and specific heat of CR. Total crude flow, CR temperature difference and CR

flow are measured by various instruments. Specific heat of CR is fixed by operator in

software for computation purpose and no on line measurement for this property is

available. Actual and desired CR duty is calculated in the duty controller as under:

58

Actual CR duty = Measured CR flow X CR temp. Difference X sp. Heat of CR

stream

Desired CR duty = (Desired CR duty/Desired total crude Flow) X Actual Crude

flow

Inputs to be manually configured by operator are specific heat of CR stream and ratio

(Desired CR duty/ Desired total crude flow) for each crude. Desired CR duty should be

estimated on pro-data feed rate basis to CDU. This is typical to all such duty controllers

on circulating reflux lines. Desired CR duty is compared with actual CR & the flow of

CR is varied to achieve desired CR duty.

3.7.4 BOTTOM SECTION (RCO CIRCUIT)

Please Refer P&ID’s 3551-05-02-41-0115 Rev.2

3551-05-02-41-0111 Rev.2

3551-05-02-41-0113 Rev.2

3551-05-02-41-0118 Rev.2

Long Residue product is collected at bottom of the column. Column bottom level is

indicated and controlled by LIC-1501. Column bottom level control can be done either by

manipulating LR flow to FPU/Storage during normal operation or by manipulating LR

flow. LR at a temperature of 365 C is pumped out from the bottom of the column by LR

pumps 05-PA-051A/B/C to LR Storage (or) FPU through (i) 05-EE-010A/B/C/D, 05-EE-

007A/B/C, 05-EE-004, 05-EE-021 and 05-EE-022A/B/C/D. (ii) 05-EE-107A/B, 05-EE-

105A/B/C/D/E, EE-103A/B, EE-111A/B. Independent level control LIC-1501 with high

& low level software alarm is provided to have redundancy of indication. SS-1501

selector switch is also provided for cutting the LR flow to LR Storage/FPU when the

atmospheric column level is low. A low level switch along with alarm LSLL-LALL-1504

is also given. Bottom temperature and LR pump suction temperature are indicated by TI-

1522. MOV-1501 also provided at column bottom LR line. ZLH-1501A & ZLL-1501B

limit switch connected through the MOV-1501 for open (or) close indication to DCS.

Pushbutton PB-1501A & PB-1501B are provided to close the MOV-1501 and to trip the

LR pump 05-PA-051A/B.

59

3.7.5 CIRCULATING REFLUXES/PUMP AROUND CIRCUITS

Three circulating refluxes are described below.

(1) Top CR (2) Kero CR (3) G.O. CR.

(1) Top CR – Drawn from tray – 43 to pumps PA-07A/B @ temp ~ 150° C PA-7A/B

discharge to exchangers 05-EE-02 tube side EE-02 tube outlet stream returns back to

column CC-01. Top CR flow is controlled by 05-FC-1501

Kero C.R.- Drawn from tray 25 to pumps PA-10A/B/C (Kero–II CR) and PA-102A/B

Kero-I CR) @ temp 200° C to 220° C.

Kero-I CR Pump P102A/B discharge flows through exchanger EE-104 tube side. CR

flow is controlled by 05-FC-5008 located at D/S of EE-104 outlet to CC-01 line.

Kero-II C/R Pumps 05-PA-10A/B/C discharge flows through EE-06A/B shell side, EE-

05 shell side and ultimately to column CC-01. Flow is controlled by FC-1502 situated

between EE-05 shell out let to CC-01 line.

Kero CR temperature is controlled by temperature controller TC1116 placed across EE-

06A/B. Kero-I CR and Kero-II CR are joining together and enter back to CC-01 on tray

No. 28.

G.O. CR - Drawn from tray-16 to pump PA-12A/B/C (LGO Cr Pumps) and pumps

104A/B (HGO CR pumps) at temperature ~ 300° C to 315° C.

LGO Pump PA-12A/B/C discharge flows through EE-09A/B shell side, EE-14 (CC-05

re-boiler), EE-15 (CC-02 re-boiler) and then enter back to column via flow controller FC-

1503 on tray-18.

HGO CR pump PA-104A/B discharge flows through exchange EE-108A/B shell side and

then joins with LGO CR line at d/s of FC-1503 via flow controller FC-5010.

C5 bottom temperature is controlled by FC1704 casketed with TC 1707 situated across

E14. Whereas Heavy Naphtha stripper C2 bottom temperature is controlled by FC 1507

casketed with TC 1538 situated across E15.

3.7.6 PRODUCT DRAW OFF TRAYS:

Heavy Naphtha, Kero/ATF, Gas oil products (are withdrawn) flow by gravity from 34 th,

26th and 15th trays of atmospheric column to respective strippers 05-CC-002/05-CC-003

60

and 05-CC-004 (under respective level control of strippers). Draw off temperature of HN,

Kerosene/ATF, Gas oil is indicated by temperature indicators TI-1526/1509/1510

respectively in DCS. Vapor return lines from HN, Kerosene/ATF, GO strippers goes

back to fractionators column are provided joining at 36th, 28th and 17th tray of the

atmospheric column. TI-1503/TI-1504/TI-1505 provided on vapor return lines from HN,

Kerosene/ATF, GO strippers indicate Vapor return temperature. 3000 mm elevation

difference from 05-CC-001 column nozzle to upstream of each level control valve for its

smooth functioning 1500 mm elevation down stream of the level control valve ensures

sufficient back pressure to prevent flashing just down stream of control valve &

consequent two phase flow in product draw off piping.

3.8 PRODUCT STRIPPERS

Refer P & ID No. 3551-05-02-41-0115 Rev. 2

There are three side strippers for stripping out side draw off products from atmosphere

column, viz. Heavy Naphtha, Kero /ATF and GO.

They are described as under:

3.8.1 HEAVY NAPHTHA STRIPPER

Ten valve type trays are provided in HN stripper 05-CC-002. Local PG and LP steam

connections are also provided on this stripper. LP steam is used to purge the column

during M&I S/D. HN to be stripped is admitted on 10th tray of 05-CC-002 under its level

control LIC-1506. Minimum 1500 mm elevation difference is provided between stripper

entry nozzle and LV-1506 piping to provide back pressure and prevent flashing in piping.

HN in 05-CC-002 bottom is re-boiled in re-boiler 05-EE-015 by HGO C/R. HN is

stripped off by its hot vapors generated in re-boiler 05-EE-015. Mass transfer between

down coming HN liquid from tray 10 to bottom and uprising HN vapors takes place on

each tray. Finally stripped HN is drawn by 05-PA-008A/B and sent to product cooling

section. Outgoing HN temp. Is indicated by TI-1512. Stripped light vapor goes back to

36th tray of atmospheric column.

Gas oil CR supplies heat to Heavy Naphtha Stripper Re-boiler 05-EE-015 through F/C –

1502. F/C-1502 is cascaded with TIC-1538. Pumps 05-PA-8A/B get suction from CC-02

bottom. PA-08A/B discharge line is divided into two branches.

61

In one branch it can be routed along with LGO through EE102 A/B via FC 5001. The

other part is cooled in cooler E20. After that, it flows through coalescer to remove carried

over water, and it can be routed to SKO R/D, LN R/D or BS2, Euro-III header of HSD.

PA-8A/B EE-20 (Cooler) . Coalescer for injection to SKO / G.O / LN.

PA-8A/B 05-FC-5001 EE102 (LGO)

C1LC1506 C2 P8A/B E20 (cooler) Coalescer PC2011 LN

FC2011 SKO

FC1807 GO (EURO3)

FC5001 E102A/B (LGO) GO

(BS2)

3.8.2 KERO/ATF STRIPPER

Six valve type trays are provided in Kero/ATF stripper 05-CC-003. Local PG and LP

steam out connections are also provided on this stripper. Kero/ATF to be stripped is

admitted on 6th tray of 05-CC-003 under its level control LIC-1508. Minimum 1500 mm

elevation difference is provided between stripper entry nozzle and LV-1508 piping to

provide back pressure and prevent flashing in piping. MP steam is used as stripping

medium in this stripper. Steam flow is regulated by FIC-1508 on steam line. It regulates

MP steam flow to 05-CC-003 based on per unit mass of Kero/ATF product outflow, as

indicated by FY-2203. Steam to product ratio is decided by operator and configured in

software for routine control. MP steam reduces partial pressure of hydrocarbon

components inside stripper and helps them vaporize at relatively low temp. Mass transfer

between down coming Kero/ATF liquid from tray 6 to bottom and uprising vapors takes

place on each tray. Finally lighter end stripped Kero/ATF is drawn by 05-PA-009A/B and

sent to preheat train I for exchanging its heat to crude in 05-EE-001. It is further cooled in

cooler E-23 / 24 before routing to caustic wash system. Provision is made for Pump PA-

62

101A/B getting suction from same suction header of PA-09A/B, which discharges to

cooler EE-109. Flow of this stream is controlled by 05-FIC-5007 located on EE-109

outlet line. Out let of both the circuits’ joins together & flows to caustic wash system.

Stripped light vapors goes to 28th tray of atmospheric column & its temperature is

indicated by TI-1504.

Combined kerosene flows to caustic wash vessel V13 through mixing valve

HIC2001.Continuous 10% caustic solution is circulated to neutralize H2S and light

mercaptans present in it. Outlet of V13 goes to water wash vessel V14 through HIC 2002.

Continuous water circulation is maintained in this vessel to wash out carried out caustic

along with it. After caustic wash the stream is passed through coalescer V15 to remove

carried over water particle along with it. It is then passed through a vessel containing rock

salt to absorb moisture from it.

Design data: salt to load: 61 Mt.

Inlet moisture: 1300-1500 ppm.

Outlet moisture: <200 ppm

SKO/ATF R/D flow is maintained FC2206 located U/S of salt dryer. It can be routed to

SKO/ATF/LABFS R/D as per requirement. Provision is also there to route SKO to HSD

or LR for which tapping is taken at upstream of salt dryer, its flow is controlled by FC

1807.

C1LC1508 C3 P9A/B E01 E24/E23C (cooler) HC2201

V13 HC2202 V14 V15 (coalescer) FC2206 Salt dryerSKO /

LABFS / ATF

FC1809 HSD/LR

3.7.3 GO STRIPPER

Six valve type trays are provided in GO stripper 05-CC-004. GO to be stripped is

admitted on 6th tray of 05-CC-004 under its level control LIC-1510 Minimum 1500 mm

elevation difference is provided between stripper entry nozzle and LV-1510 piping to

provide to back pressure and prevent flashing in piping.

63

MP steam is used as stripping medium in this stripper. Steam flow is regulated by FIC-

1509 on steam line. It regulates MP flow to 05-CC-004 based on per unit mass of GO

product outflow, as indicated by FY-1804. Steam to product ratio is decided by operator

and configured in software for routine control MP steam reduces partial pressure of

hydrocarbon components inside stripper and helps them vaporize at relatively low

temperature. These vapors move up in the stripper column Mass transfer between down

coming GO liquid from tray 6 to bottom and uprising MP steam hydrocarbon vapors

takes place on each tray.

Finally stripped GO is drawn by PA-011A/B and sent to Crude Preheat Train II for

exchanging heat with crude in 05-EE-008A/B (Gas Oil/Crude Exchanger – II) and then it

is sent to Crude Preheat Train I for exchanging heat with crude in 05-EE-003 (Gas

Oil/crude). It is further cooler in cooler E23A/B/C and its flow is controlled by FC1804.

LGO product pumps 05-PA-103A/B get suction from same suction header of pumps 05-

PA-1A/B. LGO flow passes through exchanger 05-EE-106A/B in a parallel way. EE-

106A/B outlet flow is controlled by 05-FC-5009. Then LGO flows through exchanges

05-EE-102A/B. It is than further cooled in coolers 05-EE-110A/B before is mixed with

HGO stream at D/S of 05-PC-1804. TI-1516 measures the outgoing GO stripped vapor

temperature, which enters to 17th tray of atmospheric column.

C1LC1510 C4 P11A/B E8A/B EE03 E23A/B/C (cooler) FC1804

**

P103A/B E106A/B FC5009 E102A/B E110A/B

FC 5003 R/D

** V-301

PC 5003 R/D

Mixed HGO & LGO from E110A/B and FC 1804 together enters the gas oil coalescer V-

301 to remove water carried over with it. Water accumulated in coalescer is controlled by

LC-5LV-0301 which is drained out to OWS / CBD. Gas oil from Coalescer outlet is

controlled by 1010FV5003 and 1010PV5003. Fixed quantity can be routed to desired

64

R/D tank and rest amount can be routed to other tank under PC control. HSD R/D can be

routed to as follows

Euro-III header

BS-2 header

GHC gas oil R/D header.

DHDS feed tank (At FCCU area)

Design data for HSD Coalescer: inlet water @ 600 ppm

: Outlet water <20 ppm.

3.9 NAPHTHA STABILISER

Refer P&ID No. 3551-05-02-41-0117 Rev.2

Naphtha obtained in atmospheric column overhead Naphtha reflux drum 05-VV-002

contains some light ends like C3 and C4, which vaporize at normal atmospheric

conditions. This naphtha if stored as such in storage tanks will release lot of hydrocarbon

vapors and can create unsafe conditions and pressurization of the storage. To avoid these

problems, the lighter components from naphtha are removed. This process is called

Naphtha stabilization.

Naphtha stabilization is carried out in naphtha stabilizer 05-CC-005 where C1/C2/C3 and

C4 hydrocarbons are removed from naphtha. Stabilizer column has 43 nos. of SS-410

valve type trays. The column is provided with a set of safety valves PSV-1701/1702 set at

15-kg/cm2 g. Their discharge is routed to flare header. MP steam connection is provided

on 05-CC-005 for steam purging of the column during shut down. DCS mounted

temperature indication of top outlet; tray 38, tray 5 and bottom outlet are provided. Local

PG at tray 43, and below tray I is also provided to monitor pressure profile in the column.

Un-stabilized naphtha feed to the stabilizer is first heated up to 119 0 C in feed/ Stabilizer

Bottom Exchanger 05-EE-018A/B & 05-EE-018C/D parallel by exchanging heat with

outgoing stabilized naphtha product stream from stabilizer bottom. Feed from 05-VV-002

enters the column on the 20th tray under flow control FIC-1701 that is normally cascaded

with 05-VV-002 level controllers LIC-1606. Local PG, TG and TI-1701/TIC-1702 are

also provided on feed line to monitor feed temperature pickup.

65

Wild naphtha from DHDS, LAB plant & MSQ plant and drag stream from CRU are fed

to stabilizer along with it’s feed. DHDS Wild naphtha & CRU drag stream fed through 2”

line each and joins at B/L. Wild naphtha from MSQ & LAB lines were commissioned

and wild naphtha enters the B/L through 2” line each joins at D/S of feed C/V FC1701.

The stabilizer overhead pressure is maintained by pressure controller PIC-1701. This

PIC-1701 acts on the control valve PV-1701 on outgoing line from stabilizer reflux drum

to fuel gas system. In case of increase of stabilizer pressure above set valve PV-1701

shall open and allow more fuel gas vapor to FG system. This will cause drop in stabilizer

pressure. Closure of this valve will increase stabilizer pressure due to less vapor flow

through condenser and resultant less condensation. One hot vapor bypass of 4” size has

also been provided across 05-EE-017A/B/C/D. It can be used to maintain stabilizer

pressure in case of rapid fall of stabilizer pressure. HV-1701 can be made to act for this.

TI-1729 indicates 05-CC-05 overhead vapor temperatures. Overhead vapors from

stabilizer go to the stabilizer overhead condenser 05-EE-017A/B/C/D. The condensed

liquid at 40 C is collected in the stabilizer reflux Drum 05-VV-003. This is LPG stream,

consisting of C3 and C4 hydrocarbons. It is pumped out by naphtha stabilizer reflux/LPG

product pumps 05-PA-014A/B under 05-VV-003 level control of LIC-1704. Part of it is

used as reflux to 05-CC-005 to control top temperature. Its flow is controlled by FIC-

1703, which can be cascaded with 05-CC-005 top temperatures Controller TIC-1703.

Uncondensed light hydrocarbons from 05-VV-003 top (C1/C2 component) termed as fuel

gas are routed to fuel gas system. FIC-1702 measures net FG flow from 05-VV-003. PIC-

1701 controls the pressure of 05-VV-003, acting on outgoing FG line. FI-1710 indicates

LPG minimum flow to 05-PA-014A/B. LPG is run down to LPG wash section under

flow control FIC-2503.

Sour water collected in the boot of 05-VV-003 is sent to CBD under vessel pressure.

High water level in boot may result in water carry over with LPG and can make the

stabilizer upset. The level in stabilizer reflux drum boot is indicated by LG-1705. Water

draining from boot is done manually. Independent low-level alarm switches are provided

in the boot. On actuation of level alarm low is boot, as indicated by LAL-1709, SDV-

1701 provided on sour water outlet line shall close. This feature shall prevent escaping of

LPG with sour water during water draining. PSVs 1703/1704, set at 15.0 Kg/cm2 g are

66

provided on the stabilize reflux rum 05-VV-003, whose discharge is routed to flare

header. It prevents vessel from getting over pressurized in case of external fire. 2” line

connecting flare header with upstream of PSVs has been provided to depressurize the

column to flare. 2” service water connection is provided on 05-VV-003 LPG outlet line

to fill the vessel and wash the atmospheric column with water during shutdown.

One stabilizer re-boiler 05-EE-014 is provided at stabilizer bottom to supply necessary

heat duty for boiling the un-stabilized naphtha. Heating medium for this re-boiler is Gas

Oil CR from 05-EE-009A/B. FIC-1704 provided at GO CR supply line to 05-EE-014

controls GO CR flow to re-boiler. Tray 5 temperature controller TIC-1704 can be used to

control re-boiler duty with the help of FV-1704. It is to be noted that only one

temperature control i.e. either top vapor outlet temp. or tray 5 temp. Should be used for

stabilizer operation. While operating with relatively heavier un-stabilized naphtha stocks,

tray 5 temperature is normally more sensitive and results in more energy efficient

operation. One Baffle of adequate height inside column is provided. Height of baffle is so

selected that it ensures availability of adequate liquid head, which will be necessary to

cause gravity flow of colder liquid through re-boiler. Difference in densities of lighter

and colder liquid establishes circulation through re-boiler. TI-1706/TI1726 measures the

temp. Of GO CR supply and return respectively. Un-stabilized naphtha from column

bottom flows to re-boiler under gravity and is re-boiled in 05-EE-014. Heated and partly

vaporized naphtha from re-boilers enters below chimney tray. Lighter components from

un-stabilized Naphtha move up in the tray in vapor form and condense in overhead

condensers. Composition of re-boiler outlet liquid and liquid collected in column bottom

on either side of baffle is considered same. Stabilized naphtha overflows to other side of

baffle inside the column bottom. This is cooled in tube side of 05-EE-018A/B & EE-

18C/D then routed to product cooling section. 05-FI-5033 shows the light naphtha flow

from stabilizer bottom to feed/bottom exchanger 05-EE-018A/B & 05-EE-018C/D. The

temp. control valve TV-1702 has been provided at the bottom line and it has cascaded

with TIC-1702 provided at feed line to stabilizer. TI-1716 measures the outlet temp. of

light naphtha.

Stabilizer column bottom level is maintained by LIC-1702, acting as master controller to

FIC-2004 (Light Naphtha to storage). Independent high and low level alarm switches are

67

provided on column bottom. On actuation of level alarm low low in column bottom, as

indicated by LAL-1707, SDV-1801 provided on bottom outlet line shall close. This

feature shall prevent vapor break through i.e. escaping of vapors from stabilizer to caustic

wash section.

To cater the requirement of higher benzene & MS production, provision is made to

process AU5 Light Naphtha without caustic wash to AU1 naphtha splitter section via

5FC5106. Accordingly modification is made & tapping is taken at D/S of Light Naphtha

SDV.

Two separate LN R/D line from battery limit is provided to cater requirement to route

light naphtha to different rundown tanks.

3.10 LPG-AMINE ABSORPTION SECTION

Please refer P&ID’s 3551-05-02-41-0126 Rev.2

LPG mixture from Naphtha Stabilizer reflux drum 05-VV-003 is sent to LPG surge drum

05-VV-020 by 05-PA-014A/B under flow control FIC-2503. Sour LPG from outside

battery limit (from AU4 (or) AU-3) also joins at down stream of FV-2503. The surge

drum pressure is maintained at 10.0 Kg/cm2 by PV-2501, releasing to fuel gas system i.e.

upstream of FG K.O. Drum. The level of the surge drum should always be maintained at

50%. Combined streams passes through a shut down valve SDV-2501 whose open or

close position is indicated in control room by XL-2501B/XL-2501A. Separate high level

switch LSHH-2501/LALL-2501 is provided to trip the combined stream flow to surge

drum by closing SDV-2501.

A low level switch LSLL-2502 along with LALL-2502 is also provided. LIC-2504 along

with LAH/LAL has been provided for level control purpose. Interlock has been provided

along with LSLL-2502 to trip the pump 05-PA-050A/B.

The LPG from the surge drum is pumped by the LPG booster pumps (05-PA-050A/B) to

the bottom of LPG Amine absorber column (05-CC-006) under flow control of FIC-

2501. FIC-2501 is cascaded with LIC-2504 level of surge drum. FIC-2501 indicates total

LPG flow from surge drum. FIC-2502 indicates minimum flow protection to 05-PA-

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050A/B. PSVs’ 2501B set at 15 Kg/cm2 are provided on the top of surge drum 05-VV-

020, whose discharge is routed to flair header. It prevents vessel from getting over

pressurized in case of external fire. 2” line connecting flare header with upstream of

PSV’s has been provided to depressurize the drum to flare.

In this LPG absorber column LPG is brought into contact of lean amine solution counter

currently under flow control FIC-2601. The lean amine is available at 35 C from the

Amine regeneration unit in the existing GHP Sulphur block, which is taken to the column

on flow control. LPG Amine absorber column has 10 nos. of trays. The column is

provided with a set of safety valves PSV-2601A & 2601B. Their discharge is routed to

flare header.

Separate high pressure switch PSHH-2601 along with PAHH-2607 is provided in column

top for controlling the column pressure by the way of lean amine flow cut off. A low

level switch LSLL-2605, SDV-2602 (whose open/close position ZLH-2602B/ZLL-

2602A at DCS) provided on bottom rich amine line shell close on very low C06 level..

This feature shall prevent escaping of LPG with rich amine during low level. FI-2602

measures rich amine quantity from absorber column to ARU.

The H2S in LPG is transferred to the amine and rich amine is sent back to ARU unit for

regeneration through column bottom level control LIC-2602.

Amine washed LPG is sent to amine settler 05-VV-004. In this settler Amine is separated

in the boot and washed LPG the top is sent to caustic wash. Amine collected in the boot

05-VV-004 is drained to Amine blow down (or) OWS. The level in Amine settler boot is

indicated by LI-2603 has provided with LAH/LAL software alarms. Amine draining from

boot is done manually. On actuation of level alarm low in boot, as indicated by LALL-

2602, SDV-2601 provided on amine outlet line shall close. This feature shall prevent

escaping of LPG with amine during amine draining.

3.11 PRODUCT COOLING AND RUN-DOWN SYSTEM

Refer P&ID No:I) 3551-05-02-41-0118 Rev.2

II) 3551-05-02-41-0120 Rev.2

Light Naphtha product from 05-EE-018A/B/C/D) is cooled from 79 C to 40 C in cooler

E19A/B. Cooler O/L temperature can be seen by. TI-1801 shows in DCS. Light Naphtha

69

from the cooler is fed to Light Naphtha caustic wash drum VV9. SDV-1801 is provided

at the outlet line of product cooler. This product line is provided with additional tapings

to slops header.

Heavy Naphtha from the bottom of its stripper is drawn by 05-PA-008A/B and pumped at

184 C. The product is cooled in heavy naphtha cooler 05-EE-020 up to a temp.of 40 C.

From the heavy Naphtha cooler (05-EE-020) it is sent to Heavy Naphtha Coalescer.

Heavy Naphtha Coalescer 05-VV-025 is provided for reducing saturated water content in

Heavy Naphtha from 0.8 wt% to 100 ppm. Coalescer element is provided inside the

vessel to meet the above-mentioned parameter. Retention time is 4 hours for enabling

water droplets to settle in coalescer

LI-2010B shows the coalescer level in DCS. FI-2010 measures net Heavy Naphtha

quantity from coalescer. From the coalescer, the product is sent to Light Naphtha Storage

under pressure control PIC-2100. In the common product line, 3 tapping are provided for

different destinations.

The HN product can be sent to Gas Oil storage under flow control of FIC-1807

The HN product can be sent to Kero R/D line under flow control of FIC-2011

1” line tapping has provided from common HN product line for corrosion inhibitor

drum

Water collected in the boot of 05-VV-025, is sent to OWS under level control. Water

draining from boot is done manually. On actuation of level alarm low in boot, as

indicated by LALL-2100, SDV-2003 provided on outlet water line shall close. This

feature shall prevent escaping of product during water draining. Two PSVs 2005/2006 set

at 15 Kg/cm2 are provided on the coalescer 05-VV-025 whose discharge is routed to flare

header. It prevents vessel from getting over pressurized in case of external fire. A 2” line

connecting flare header with upstream of PSVs has been provided to depressurize the

vessel to flare.

Kero-II product flows from 05-PA-09A/B to EE-01 exchanger. Then it flows through

cooler EE-024. After cooler kero-II product flows through caustic wash vessel VV-13,

water wash vessel VV-14 and coalescer VV-15. Coalescer o/l is routed to R/D via salt

dryer (SKO / ATF / LABFS) & FC 2206. Kero is injected to G.O. via FC-1809.

70

Gas Oil from old & new circuit at 107.6 C/113 C is further cooled in 05-EE-023A/B/C &

E110A/B (Gas Oil Coolers) up to a temp. of 40 C and sent to RD through FV-1804

under flow control of FIC-1804, TI-1804 measures the GO outlet temp. This product line

is provided with additional tapings to slops header and DHDS unit and flushing oil,

product G.O can be routed to three locations.

G.O. to FCC units. (2) G.O. to GHC HSD R/D (3) G.O. to BS2 and (4) GO to Euro-

III

Kero can be injected to G.O. (either to O.M&S. or to FCC) through FC 1809.

Kero can be injected to RCO R/D as carter stock

HN to G.O. injection ( Both Euro-II & BS2 separately)

G.O. can be routed to slops-header.

G.O. can be taken to FLO line for flushing purpose.

Long residue from 05-PA-051A/B/C at 363.9 C/364.2 C sent to crude preheat trains II &

I for exchanging heat with incoming crude through 05-EE-010A/B/C/D (LR/Crude

Exchanger III), 05-EE-007A/B/C (LR/Crude Exchanger II), 05-EE-004 (LR/Crude

Exchanger I), and EE-107A/B/C/D/E, EE-105A/B, EE103A/B/C. The outgoing LR

temperature is around 143 C/ 134 C. After this the LR is cooled at LR cooler 05-EE-021

& EE-110A/B up to 120 C outlet of this cooler one portion has sent to FPU storage under

flow control FIC-1805 through FV-1805. Remaining LR product sent to further cooling

at LR cooler 05-EE-022A/B/C/D up to the temperature of 80 C. After that the product has

sent to LR storage under flow control FIC-1806 through FV-1806. Product tapings for

slop header and LR circulation to unit crude pump suction for unit start up is also

provided.

Provision is made to route Hot LR to VDU as hot feed via 5FC1805 in June 2006 and a

2” line tapping is provided to route FPU-2 Heavy gas oil to cold LR rundown at battery

limit as carter stock.

3.12 CAUSTIC/WATER WASH FACILITIES

Refer P&ID No.: I) 3551-05-02-41-0120 Rev 2

II) 3551-05-02-41-0119 Rev 2

III) 3551-05-02-41-0122 Rev 2

71

Caustic wash is generally used to remove Sulphur components like hydrogen sulphide

and/ or methyl & ethyl mercaptan. Equal volumes of hydrocarbon liquid & caustic

solution are mixed / re-circulated. During this operation, caustic hydrocarbon emulsion is

formed which is allowed to settle in a vessel. Typical retention time is 90 minutes to 45

minutes. Naphtha, Kerosene and ATF are washed with 10% caustic solution to remove

CS2, H2S, phenols and mercaptan which may be present or can be generated during

processing. Caustic solutions are hazardous wastes. Traces of caustic are removed by

water washing of these streams. The caustic water wash systems are described below:

3.12.1.A LPG CAUSTIC WASH SYSTEM

LPG from Amine Wash Unit is routed for caustic water wash. LPG is admitted in LPG

Caustic wash vessel 05-VV-006 through a static mixer 05-JV-002. LPG caustic wash

circulation pump 05-PA-017A/B, takes suction from bottom of 05-VV-006 and

discharging into 05-VV-006 through mixer. 10-vol% caustic solutions is circulated by

these pumps where it is mixed with LPG. Mixing in the static mixer results in conversion

and transfer of H2S, mercaptan & other chemicals to sodium sulphides. Depending on

efficiency of mixing in the mixer, reduction of above chemicals shall take place. Mixing

of the two streams can be improved by throttling the mixer rotation. Hydrocarbon phase

separates out from caustic in 05-VV-006 due to adequate availability of residence time.

LPG overflows from top of 05-VV-006 to water wash vessel 05-VV-007 through another

static mixer 05-JV-003. Caustic solution settled in 05-VV-006 bottom is re-circulated

again. On repeated circulations, strength of caustic goes down to less than 7.5% of its

initial strength due to picking up of compounds mentioned above. This is called spent

caustic and is drained out through 2” line to spent Caustic water Wash drum 05-VV-006.

Spent caustic draining from the bottom of the vessel 05-VV-006 is done manually.

Independent low-level alarm switches are provided in the vessel. On actuation of level

alarm low in the vessel is indicated by LALL-1903, SDV-1901 provided on spent caustic

outlet line shall close. This feature shall prevent escaping of LPG with spent caustic

during spent caustic draining.

72

During Caustic make up, normally caustic circulation should no be stopped and strength

of spent caustic solution should be increased by gradual draining and equivalent make up

by 05-PA-025A/B. Quantity of caustic make up in indicated by FI-1901B.

PSV-1901 & 1902 are provided on 05-VV-006 top, whose discharge is routed to flare

header. It prevents vessel from getting over pressurized in case of external fire. LI-1901B

with LAL has been provided for measuring the level of the vessel. 05-VV-006 always

operates with full of liquid, without any vapor space.

Spent Caustic degasser 05-VV-016 is a vertical vessel connected with flare. It receives

caustic from LPG caustic wash, Light Naphtha, Kero/ATF wash system. Vapors

disengaged from caustic solution escape to flare and spent caustic is pumped out to ETP

by spent caustic pumps 05-PA-043A/B. LI-1911 with LAL/LAH has been provided for

measuring level in the vessel. Independent low level alarm switches are provided in the

vessel. On actuation of level alarm low in the vessel is indicated by LALL-1914, SDV-

1904 provided on spent caustic degasser outlet line shall close. This feature shall prevent

escaping of hydrocarbon vapors with spent caustic during pumping.

3.12.1.B LPG WATER WASH SYSTEM

LPG carries with it fine droplets of caustic solution which can make product corrosive if

stored as such. Therefore to remove these traces of caustic solution LPG water wash

vessel 05-VV-007 is provided. LPG water circulation pump 05-PA-018A/B takes suction

from 05-VV-007 bottom and discharges water back to vessel through the static mixer 05-

Jv-003. Circulating water flow measures through FI-1903B in DCS.

Water mixes with LPG in 05-JV-003 results in its water saturation. An inter phase of

alkaline water and water washed LPG is formed in 05-VV-007. LI-1904B with LAL

shows the level of the vessel. Water washed LPG floats on top of water in the vessel.

Water saturated caustic free LPG is routed to LPG coalescer 05-EE-008.

Water entering with LPG settles down in lower portion of 05-VV-007. This alkaline

water draining from the bottom of the vessel 05-VV-007 is done manually. Independent

low level alarm switches are provided in the vessel. On actuation of level alarm low in

the vessel is indicated by LALL-1906, SDV-1902 provided to arrest escaping of washed

73

LPG with water during draining. Quantity of water make up to 05-VV-007 by 05-

PA025A/B is indicated by FI-1904B.

PSVs 1903/1904 are provided on 05-VV-007 top to prevent it from over pressurization

due to exposure of vessel in the external fire. 05-VV-007 always operates with full of

liquid, without any vapor space.

From the LPG Water Wash vessel 05-VV-007 the top portion is sent to LPG Coalescer

LPG Coalescer 05-VV-008 is provided for reducing saturated water content in LPG from

0.2 wt% to 80 ppm. Coalescer element is provided inside the vessel to meet the above-

mentioned parameter. Retention time is 4 hours for enabling water droplets to coalescer

and separate efficiently from LPG. LI-1910B shows the coalescer level in DCS. From the

Coalescer, the product is sent to LPG storage under pressure control of PIC-1912 through

PV-1912. In the common product line there is a product tapping for LPG Vaporizer. FIC-

1906 measures net LPG quantity from coalescer to storages.

Water collected in the boot of 05-VV-008, is sent to OWS/CS under level control. Water



feature shall prevent escaping of product with during water draining. Two PSVs

1905/1906 set at 15 Kg/cm2 are provided on the coalescer 05-VV-008, whose discharge

is routed to flare header. It prevents vessel from getting over pressurized in case of

external fire. 2” line connecting flare header with upstream of PSVs has been provided to

depressurize the vessel to flare.

3.12.2.A LIGHT NAPHTHA CAUSTIC WASH SYSTEM

Light Naphtha from light naphtha cooler 05-EE-019 is routed for caustic wash.

Light Naphtha is admitted in Light Naphtha caustic wash drum 05-VV-009 through a

mixing valve HIC/HV-2001 Caustic circulation pumps 05-PA-019A/B, taking suction

from bottom of 05-VV-009 and discharging into 05-VV-009 through mixing valve HV-

2001 are provided. 10% vol caustic solution is circulated by these pumps where it is

mixed with Naphtha. Mixing results in conversion and transfer of H2S, phenols

mercaptan & other chemicals to caustic solution. Depending on efficiency of mixing in

the mixing valve, reduction of above chemicals shall take place. Mixing of the two

74

streams can be improved by throttling the stream valve with the help of HIC-2001.

reduced port opening of the mixing valve increases stream velocity through the valve,

resulting in better energy transfer to streams for mixing. However, impact of additional

pressure drop due to mixing valve throttling on run down control valve and upstream

system should be carefully evaluated and monitored. Hydrocarbon phase separates out

from caustic in 05-VV-009 due to adequate availability of residue time. Naphtha over

flows from top of 05-VV-009 to water wash vessel 05-VV-010 through another mixing

valve HIC-2002/HV-2002. Caustic solution settled in 05-VV-009 bottom is re-circulated

again on repeated circulations, strength of caustic goes down to less than 75% of its

initial strength due to picking up of compounds mentioned above. This is called spent

caustic and is drained out through 4” line to spent Caustic water degasser 05-VV-016.

Spent caustic draining from the bottom of the vessel 05-VV-009 is done manually.

Independent low level alarm switches are provided in the vessel. On actuation of level

alarm low in the vessel is indicated by LALL-2003, SDV-2001 provided on spent caustic

outlet line shall close. This feature shall prevent escaping of fresh caustic solution with

spent caustic during spent caustic draining.

During Caustic make up, normally caustic circulation should not be stopped and strength

of spent caustic solution should be increased by gradual draining and equivalent make up.

Quantity of caustic make up is indicated by FI-2003B.

PSV 2001/2002 are provided on 05-VV-009 top, whose discharge is routed to flare


with LAH/LAL has been provided for measuring the level of the vessel 05-VV-009

always operates with full of liquid, without any vapor space.

Spent caustic degasser 05-VV-016 is a vertical vessel connected with flare. It receives

caustic from LPG caustic wash, hydrocarbons vapors disengaged from caustic solution

escape to flare and spent caustic is pumped out to ETP by spent caustic pumps 05-PA-

043A/B. LI-1911 with LA/LAH has been provided for measuring level in the vessel.

Independent low level alarm switches are provided in the vessel.

On actuation of level alarm low in the vessel is indicated by LALL-1914, SDV-1904

provided on spent caustic degasser outlet line shall close. This feature shall prevent

escaping of hydrocarbon vapors with spent caustic during pumping.

75

3.12.2.B LIGHT NAPHTHA WATER WASH SYSTEM

Caustic washed naphtha carries with it fine droplets of caustic solution, which can make

product corrosive if stored as such. Therefore these caustic solution traces need to be

removed from naphtha before sending it to storage. For this purpose, through water wash

is given to Naphtha. Naphtha water wash vessel 05-VV-010 is provided for this purpose.

Light Naphtha water circulation pump 05-PA-020A/B takes suction from 05-VV-010

bottom and discharges water back to vessel through HV-2002. Circulating water flow

measure through FI-2002B in DCS.

Water mixing with Naphtha in HV-2002 results in its water saturation. An inter phase of

alkaline water and water washed naphtha is formed in 05-VV-010. LI-2008B with

LAL/LAH shows the level of the vessel. Water washed naphtha from the top of the

vessel (caustic free) is routed to light naphtha storage by Light Naphtha Product pump

05-PA-041A/B under flow control of FIC-2004 through FV-2004. Stabilizer bottom level

controller LIC-1702 can also be cascaded with this flow controller to maintain level in

the stabilizer bottom.

Water entering with Naphtha settles down in lower portion of 05-VV-010. This alkaline

water draining from bottom of the vessel 05-VV-010 is done manually. Independent low

level alarms switches are provided in the vessel. On actuation of level alarm low in the

vessel is Indicated by LALL-2007, SDV-2002 provided on alkaline water line to spent

caustic water degasser shall close. This feature shall prevent escaping of washed naphtha

with spent caustic during water draining. Quantity of water make up to 05-VV-010 is

indicated by FI-2005B.



liquid, without any vapor space.

3.12.3.A KERO/ATF CAUSTIC WASH SYSTEM

Kero/ATF from Kero/ATF cooler 05-EE-024 / 23C is routed for caustic water wash.

76

Kero/ATF is admitted in Kero/ATF caustic wash vessel 05-VV-013 through a mixing

valve HIC/HV-2201. Kero/ATF Caustic circulation pumps 05-PA-023A/B, taking

suction from bottom of 05-VV-013 and discharging into 05-VV-013 through mixing

valve HV-2201 are provided. 10-vol% caustic solution is circulated by these pumps

where it is mixed with Kero/ATF. Mixing in the valves results in conversion and transfer

of H2S, phenols, mercaptans & other chemicals to caustic solution. Depending on

efficiency of mixing in the mixing valve, reduction of above chemical shall take place.

Mixing of the two streams can be improved by throttling the mixing valve with the help

of HIC-2201. Reduced port opening of the mixing valve increases stream velocity

through the valve, resulting in better energy transfer to streams for mixing. However,

impact of additional pressure drop due to mixing valve throttling on rundown control

valve and upstream system should be carefully evaluated and monitored. Hydrocarbon

phase separates out from caustic in 05-VV-013 due to adequate availability of residence

time. Kero/ATF overflows form top of 05-VV-013 to water wash vessel 05-VV-014

through another mixing valve HIC-2202/HV-2202. Caustic solution settled in 05-VV-013

bottom is re-circulated again. On repeated circulations, strength of caustic goes down to

less than 75% of its initial strength due to picking up of compounds mentioned above.

This is called spent caustic and is drained out through 2” line to spent Caustic/water

degasser 05-VV-016. LI-2202B measures the level in the Kero/ATF Caustic Wash drum

05-VV-013. Spent Caustic draining from the bottom of the vessel 05-VV-013 is done

manually. Independent low level alarm switches are provide in the vessel. On actuation

of level alarm low in the vessel is indicated by LALL-2203, SDV-2201 provided on spot

caustic outlet line shall close. This feature shall prevent escaping of hydrocarbons with

spent caustic during spent caustic draining. During Caustic make up, normally caustic

circulation should not be stopped and strength of spent caustic solution should be

increased by gradual draining and equivalent make up. Quantity of caustic make up is

indicated by FI-2201B.

PSV 2201/2202 are provided on 05-VV-013 top, whose discharge is routed to flare


with LAL has been provided for measuring the level of the vessel. 05-VV-013 always

operates with full of liquid without any vapor space.

77

Spent Caustic degasser 05-VV-016 is a vertical vessel connected with flare. It receives

caustic from LPG caustic wash, Light Naphtha, Kero/ATF vapors disengaged from

caustic solution escape to flare and spent caustic is pumped out to ETP by spent caustic

pumps 05-PA-043A/B. LI-1911 with LAL/LAH has been provided for measuring level in

the vessel. Independent low level alarm switches are provided in the vessel. On actuation

of level alarm low in the vessel is indicated by LALL-1914, SDV-1904 provided on spent

caustic degasser outlet line shall close. This feature shall prevent escaping of

hydrocarbon vapours with spent during pumping to ETP.

3.12.3.B KERO/ATF WATER WASH SYSTEM

Caustic washed Kero/ATF carries with it fine droplets of caustic solution, which can

make product corrosive if stored as such. Therefore these caustic solution traces need to

be removed from Kero/ATF water wash is given to Kero/ATF. Kero/ATF water wash

vessel 05-VV-014 is provided for this purpose. Kero/ATF water circulation pump 05-PA-

024A/B takes suction from 05-VV-014 bottoms and discharges water back to vessel

through HV-2202. Circulating water flow measures through FI-2203 B in DCS.

Water mixing with Kero/ATF in HV-2202 results in its water saturation. An inter phase

of alkaline water and water washed Kero/ATF is formed in 05-VV-014. LI-2205B with

LAL shows the level of the vessel. Water washed Kero/ATF floats on top of water in the

vessel. Water saturated with caustic free from Kero/ATF settles down in lower portion of

05-VV-014. This alkaline water draining from the bottom of the vessel 05-VV-014 is

done manually. Independent low level alarm switches are provided in the vessel. On

actuation of level alarm low in the vessel is indicated by LALL-2206, SDV-2202

provided on alkaline water line to Spent Caustic/water degasser shall close. This feature

shall prevent escaping of washed Kero/ATF with spent caustic during spent caustic

draining. Quantity of water make up to 05-VV-014 is indicated by FI-2204 B.



liquid without any vapour space.

From the Kero/ATF water wash vessel (05-VV-014) the top portion is sent to Kero/ATF

Coalescer. Kero/ATF Caolser 05-VV-015 is provided for reducing water content in

78

Kero/ATF 0.2 wt% to 100ppm. Coalescer element is provided inside the vessel to meet

the above-mentioned parameter. Retention time is 4 hours for enabling water droplets in

coalescer and separate efficiently from Kero/ATF. LI-2210 B shows the coalescer level

in DCS. From the coalescer, the product has sent to Kero/ATF storage under flow control

of FIC-2206 through FV-2206. in the common product line, product tapping for

Kero/ATF to Gas oil rundown has provided. FI-2205 measures net Kero/ATF quantity

from coalescer to storage.

Water collected in the boot of 05-VV-015, is sent to OWS under level control. Water



feature shall prevent escaping of product with during water draining. Two PSVs

2205/2206 set at 15 Kg/cm2 are provided on the coalescer 05-VV-015, whose discharge

is routed to flare header. It prevents vessel from getting over pressurized in case of

external fire. 2” line connecting flare header with upstream of PSVs has been provided to

depressurize the vessel to flare.

3.13 CHEMICAL INJECTION FACILITIES

Refer P&ID No: 3551-05-020-41-0124 Rev.5

Hydrochloric acid from the salt in the crude and hydrogen sulphide dissolved in the crude

(or formed from the dissociation of heavy Sulphur compounds present in crude)

concentrates in the overhead system. Both form of acid solutions, which are corrosive.

Measures must be taken to over come their effects. The overhead system including

condensers and reflux drum is made of carbon steel. In order to protect this section,

caustic solution, ammonia solution and corrosion inhibitors are added at various points.

The purpose of injection caustic at the outlet of desalter is to achieve better mixing of

these chemicals with crude and neutralize the acids and salts, mainly HCL and H2S as

soon as they are formed (at a temp. Of 120 C and above) the reaction products i.e. sodium

and ammonia salts go along with reduced crude. The balance acids and acid gases if any

will go up to the overhead system where ammonia is injected in the overhead vapor line

to neutralize. Amount of ammonia should be controlled in such a way that pH of reflux

drum water remains at 6.5+0.2.

79

Injection of caustic at the outlet of desalter should be maintained in such a way that the

salt formation should be low in the overhead circuit, which might scale up the overhead

condenser tubes.

A slightly acidic condition of the overhead system is desirable to keep ammonium salts in

solution, which if precipitates would foul and plug the condensers. Corrosion against

slightly acidic conditions is minimized by adding corrosion inhibitors in the overhead

vapor line. The inhibitor is also added in reflux line. Top section of the column is also

benefited from the injection of corrosion inhibitors mainly in the reflux line. These

inhibitors are high boiling compounds and can perform satisfactorily at higher column

top temperature also.

The amount of inhibitor injected depends upon the type of inhibitor used and generally

specified by the vendor. However slight adjustment is made by operating personal

depending upon iron content in the reflux drum water. These inhibitors are filming

organic compounds, which cover entire metal surface of the system with a thin film. This

prevents contact of corrosive water with metal surface.

Various points of chemical injections are listed below:

3. 13.1 CAUSTIC INJECTION

Caustic solution having strength of 47% is received from off sites through 3” header. It is

diluted to two different strengths for use in unit. Five caustic tanks are provided within

battery limit. One strong tank 05-TT-001 stores strong caustic solution with strength of

47% two tanks 05-TT-002A/B provided to store weak caustic solution with strength of 10

%.& two tanks, 05-TT-006A/B provided to store weak caustic solution with strength of

3.5% Each strong tank is provided with DM water connection for dilution purpose. LI”s

and overflow lines are provided on each tank. Care should be taken to ensure that tanks

are not pressurized due to inadequate relieving of air through tank vent.

Strong Caustic solution from 05-TT-001 is pumped by caustic make up pump 05-PA-033

to 10% caustic dilution tank 05-TT-002A/B from 05-TT-002A/B is pumped by caustic

make up pump 05-PA-032A/B to following destinations.

To Kero/ATF caustic wash

To LPG Caustic wash

80

To Light Naphtha Caustic wash

Dilute caustic solution from 05-TT-006A/B is pumped by Caustic injection pumps 05-

PA-031A/B to following destination:

To suction of Crude charge pumps 05-PA-001A/B/C/D/E

To Caustic Mixer (05-JV-001) connected from discharge of desalter outlet to desalter

crude pumps 05-PA-002A/B/C

To upstream of desalters 05-VV-001A/B

3.13.2 AMMONIA SOLUTION INJECTION

Ammonia gas drawn from ammonia cylinder, brought from out side agency, is injected at

reduced pressure into ammonia solution vessel 05-VV-018A/B. DM water connection is

provided on ammonia vessel for preparing solution. Ammonia solution vessel is a vertical

vessel with a water seal on its vent to prevent escaping of ammonia while preparing

solution. Water seal will blow off during excess pressure build up in the vessel. Finally

prepared ammonia solution is injected by ammonia solution injection pumps 05-PA-

026A/B to Crude column overhead line. FI-2411 measures the net quality of ammonia to

crude column overhead.

3.13.3 DEMULSIFIER INJECTION

Dissolved demulsifier chemical is pumped out by 05-PA-027A/B and is injected to the

following destinations FI-2405 measures the net quality of demulsifier from 05-PA-

027A/B for consumption.

To suction of crude charge pump 05-PA-001A/B/C/D/E

To upstream of desalters 05-VV-001A/B

3.13.4 CORROSION INHIBITOR/AHURALAN SOLUTION INJECTION

Corrosion inhibitor (Ahuralan) is received in drums and transferred to ahuralan solution

making drum 05-VV-019A/B, and it is diluted with heavy naphtha. 05-VV-019A/B is

vertical drum operates at atmospheric pressure. Local level gauge, Sample point and

draining arrangements to OWS/CBD are also provided on vessel. Corrosion inhibitor

chemical is unloaded into 05-VV-019A/B with the help of hand pump. Diluted ahularan

81

is pumped out by 05-PA-029A/B and is injected into crude column overhead lines and

stabilizer overhead lines. FI-2406 measures the quantity of Ahuralan consumed at crude

column, FI-2407 measures the quantity of Ahuralan consumed at Naphtha Stabilizer

overhead lines.

3.13.5 WASH WATER SYSTEM

DM Water is received and stored at Wash water make up tank 05-TT-005. LI-2408 with

LAH/LAL and overflow lines is provided in the vessel. From 05-TT-005 wash water is

pumped by wash water makeup pumps 05-PA-040A/B to the following destinations for

water wash purpose.

Light Naphtha water wash vessel

LPG Water wash vessel

Kero/ATF water wash vessel

3.14 EFFECTS OF OPERATING VARIABLES

It is important that the operation of process units should be conducted to produce

products of desired quantity. At the same time appropriate controls should be exercised

on certain parameters to prolong the length of continuous run and life of the equipment.

The effect of varying operating variables should be evaluated in totality, particularly for a

complex operating system like fractionation. The effect of a particular operating variable

may not remain limited to only those aspects as discussed below, but usually has a

cascading effect on other operating variables and other aspects of operation, however the

significance of only major changes caused by variation in operating parameters are

discussed here.

In following discussion, it is assumed that operating variable under reference only is

varied, keeping all other parameters unchanged in real situation it may not be possible to

change a variable in isolation. The effect of operating variables is indicative only.

The following general guidelines describe effect of the process variables and measures to

be taken to achieve desired results:

82

3.14.1 DESALTER OPERATING VARIABLES

Only operating experience with desalter can determine optimum operating conditions. No

two crude behave alike at the same desalting conditions, but all are affected similarly by

change in desalting conditions.

3.14.1.A WATER INJECTION & PRESSURE DROP

Water injection should be started only after the crude temp. reaches specified desalting

value and power is switched onto the grid. Initially the injection rate should be limited

between 2-6% of crude flow rate and point of injection should be just upstream of the

mixing valve. If crude is Napthenic, water injection should be considered upstream of

preheat trains.

The pressure drop across mixing valve should be adjusted to give the required degree of

desalting. The higher the total pressure drop (inclusive of mixing valve and desalter), the

more efficient the contact between the salt in the crude and the injection water. Too high-

pressure drop will result in excessive emulsification and poor separation of oil and water,

resulting in carry over of water in the desalted crude. A pressure drop between 1 to 2

Kg/cm2 is normally sufficient, which can be adjusted by manipulating mixing valves at

desalter inlet.

Optimum water injection rate and pressure drop across mixing valve should be

established to get the desired desalting of crude. Once this is done, the conditions should

be maintained steady and should be varied only for changes in feed rate and feed

quantities.

3.14.1.B OIL/WATER INTERPHASE LEVEL

The oil-water interface level should be maintained below the centre line of the desalter

vessels to avoid escaping of water and sludge along with the crude, if sudden pressure

surge takes place. Incorrect operation of the interface level controller can result in more

water in desalted crude due to less hold uptime available for oil(high interface level) and

more oil carry over in brine water due to less hold uptime available for water (low water

83

level). Also too high an interface level may push battery mixture up between the

electrodes and cause them to short circuit.

3.14.1.C DESALTER VESSEL PRESSURE

The normal pressure in the vessel should be maintained at about 13 Kg/cm2g or as

specified by desalter vendor. A low pressure may cause vaporization of crude fractions at

prevailing desalting temp. High pressure may result in popping of the safety valve on the

desalter.

3.14.1.D DESALTER TEMPERATURE

Desalting temperature is another important variable, which affects oil water separation in

Desalter. Most crude oils have an optimum-operating temp. range of around 127 C for

Kero case and 123.5 for ATF case. Lower the temp. higher the viscosity of the oil that

slows down the separation rate. As crude conductivity and solubility of crude in water

increases with temperature operating beyond this range will lead to drop in grid voltage

and high amperage which imposes limitation on good separation. Excessive amperage

will eventually cause the circuit breaker to open, tripping the electric grid and rendering

the electrical system inoperable until the thermal relay is closed. Very high temp may

lead to vaporization of crude in the desalter.

3.14.1.E DEMULSIFIER INJECTION

Tight crude water emulsions can be broken by use of demulsifying chemicals. The

amount of chemicals required to break the emulsion dependents on the nature of the

emulsion, type of crude and other operating conditions like residence time, temp. etc.

Required emulsification chemical injection rate should be established empirically for

optimum operation of desalting unit. Demulsifier soluble in Kerosene has been

considered for use in the unit.

3.14.1.F VOLTAGE AND AMPERAGE

The desalter electrical panel typically houses pilot lights, a voltmeter and ammeter. The

voltmeter gives the voltage across the primary circuit of the transformer. The ammeter

84

gives the current flow. These meters give an indication of the performance of the grids

inside the desalter. In case, crude water emulsion is too tightly bound or if the interface

level is too high there will be flickering of the pilot light, the amperage will increase and

the voltage will drop. Take corrective action to break the emulsion or reduce the interface

level.

For more details about the operation of desalter the vendors operating and maintenance

manual should be referred.

3.14.2 HEATER COIL OUTLET TEMPERATURE (COT) AND OVER FLASH

The quantity of crude oil vaporized during its passage through the atmospheric heater

depends on transfer temperature and the pressure at the flash zone of the column. In order

to achieve proper separation i.e. desired recovery of distillates a little over flash is

maintained by keeping the transfer temperature slightly on higher side. This quantity is

measured by FI-1504 and at normal capacity the flow is about 25/20 M3/hr (about 6 to

9% vol. on crude charge feed). This also indicates the presence of liquid level in the

trays down below the GO draw off section. Dry operation of these trays should be

avoided to minimize coke-forming tendency. Maintaining excessive over flash flow will

result in more consumption of energy without any advantage & more RCO generation.

Lower heater coil outlet temperature will effect product quality more in lower section of

the column e.g. gas oils & below (by making then off spec due to carry of heavier

components from LR) and lowering down recovery as well as LR will contain more

lighter components. Yield & quality of products drawn from upper section of the column

may not be affected much.

Higher than normal coil outlet temperature enhance crude cracking possibility inside

heater tubes, leading to coke deposition and higher pressure drop. This may reduce

overall run length of the unit and may force a planned shut down. At the same time

specification of heavy products may not met and higher recovery may be experienced at a

given temp.

3.14.3 MAIN FRACTIONATING COLUMN PRESSURE

85

The effect of column top pressure is more pronounced on lighter streams. Lower column

top pressure aids in greater vaporization of all streams, particularly lighter streams.

Column operation with lower top pressure will make all side draw products and top

stream slightly heavier. There will be more load on overhead condensers and loss of

lighter components may take place from reflux drum to maintain normal operating

pressure. Higher than normal top pressure will have reverse effects.

Increase in column top pressure will increase column flash zone pressure also. Increased

flash zone pressure will result in lower product yield of all side off streams. The effect

will be reflected in LR also (bottom most stream) which will become lighter.

It is important to note that column pressure is largely dependent upon equilibrium

conditions in reflux drum. Efforts should be made to operate the column at the intended

design pressure only, depending upon type of crude. During normal operation total

condensation of overhead stream is expected and thus both the control valves of split

range pressure controller (on FG make up side as well as flare side) shall remain shut.

3.14.4 MAIN FRACTIONATING COLUMN TOP TEMPERATURE

The column top temperature is controlled by regulating amount of overhead reflux

through FC-1505 cascaded with TIC-1501. Increasing the top temp. at same operating

pressure will result in increase of FBP and make of light naphtha will increase. IBP of

HN shall also increase. Similarly reduction of top temp. will reduce FBP and yield of

light Naphtha. IBP of first side draw off (Heavy Naphtha) shall also come down. To

overcome effect of change in top temp. HN draw off should be suitable adjusted to

maintain its draw off temp.

Too low top temp. will start steam condensation at the top section of the column, which

may increase rate of corrosion in the top section of the column.

3.14.5 CIRCULATING REFLUXES FLOW

The circulating Reflux mainly removes heat form the column and reduces the vapour

load in the particular section of the distillation column. The flows of the three circulating

refluxes: Heavy Naphtha CR, Kero, CR and GO CR are controlled by respective duty

86

controllers respectively. Increase of circulating reflux flows will result in higher crude

preheat temp. by greater heat recovery in heat exchanger train.

Even through various CR return temperature will be governed by functioning of

respective duty controllers, these may be maintained by operating the bypass of

respective exchangers also. Any change in circulating reflux affects quality and quantity

of its own product and those products, which are immediately above and below it. The

effect of change of CR variation on other streams is not discussed, as it is not that much

pronounced.

A higher than normal Heavy Naphtha CR flow will remove more heat from column in

HN CR zone. When this heat removal becomes excessive, column top temp. shall also

show a tendency of decline, requiring lower top reflux flow. This will cause lower liquid

transport between top tray and HN draw off, causing poor fractionation between

overhead and HN. It will come down, as there will be less overhead product to condense.

The kerosene cut will be correspondingly lighter.

High GO CR flow will tend to lower the temp. resulting in lighter product on this tray.

Thus GO will be lighter and Kerosene will also be lighter.

Likewise a high GO CR will tend to lower the draw off temp. of GO product, making GO

and LR lighter.

3.14.6 PRODUCT WITHDRAWL TEMPERATURE

The withdrawal (Draw off) temperature of the products is controlled by withdrawal rate

of the streams. Increase in product withdrawal temperature makes it heavy. An increase

in withdrawal rate of one side stream increases the withdrawal temperature and boiling

ranges of all side streams down below in the column unless their withdrawal rates from

the column are also reduced correspondingly.

For example, if kerosene product withdrawal rate is increased, the internal reflux in the

trays below the draw off tray will be reduced. Thus end point of kerosene is increased.

Increased kero draw off will have a tendency of lowering availability of material on GO

tray, requiring corresponding reduction in GO draw off to maintain same FBP. If GO

withdrawal rate is not reduced to maintain its draw off temp. its boiling range will shift

upwards.

87

Similarly reverse action takes place when withdrawal temp. is lowered by reducing the

quantity of withdrawal.

3.14.7 STRIPPING STEAM

3.14.7.A STRIPPING STEAM IN FRACTIONATING COLUMN

Super heated MP steam is used to strip kero/ATF and GO at the bottom of the crude

column. The stipulated bottom steam rate should be maintained by FIC-1508 & FIC-1509

for economical stripping and normally it should not be varied. Lowering the steam rate

below the specified optimum value may leave some GO in the LR and this is undesirable.

Exceeding the design steam rate might cause entrainment of LR into the GO because of

excessive vapour velocity. Also it will ultimately overloads the overhead condenser

system.

3.14.7.B STRIPPING STEAM IN STRIPPERS

The flash points (IBP to some extent) of Kero/ATF and GO products can be controlled by

varying the stripping steam rate to respective strippers.

It is advisable not to exceed the steam/ vapour flow rate beyond the design value in any

of product strippers viz. HN, kero and GO strippers as this will tend to lift some of the

high boiling material into atmospheric column. If the desired flash point could not be

obtained by designed rate of stripping steam, the draw off of product just above it may be

increased to enhance its IBP. Use of MP steam in any of the strippers shall cause

reduction of partial pressure of hydrocarbon and may result in evaporation of lighter

components from the stock. This may also be reflected in terms of flash point of the

product.

Stabilizer removes the majority of butane and lighter hydrocarbons from the naphtha

stream. These are recovered as overhead fuel gas product. High stabilizer top temp. will

make overhead product heavy; even C5, C6 components may be carried into fuel gas and

condensing in the distribution line after wards. Lower top temp. attained by increasing

top reflux will reduce heavier ends in fuel gas.

88

RVP of LPG may go up on account increased presence of C3 and lower components. To

correct the situation, stabilizer top pressure should be lowered a bit. Too low bottom

temp. may result in higher than allowable vapour pressure (RVP) of naphtha and at the

same time it will reduce yields of overhead streams.

Low stabilizer top pressure in the column will cause higher amount of hydrocarbon

compounds (C3 and C4) to escape into overhead system. This has got similar effect as

that of higher temp. in the column.

3.15 NORMAL OPERATING CONDITIONS

CURDE TYPE LS

NIGERIAN

HIGH

SULPHUR

BH FARCADOS

Total Flow

m3/hr

510 520 510 530

Tput: MT/D 10500 10800 10500 10800

CIT 263 274 264 263

COT 365 375 365 351

COT Maintained 365 375 360 370

Furnace (FF-01)

FC-1401 M3/Hr 141 150 141 154

FC-1402 M3/Hr 151 161 153 151

FC-1403 M3/Hr 150.3 153 151 156

FC-1404 M3/Hr 141.3 144 141 147

Top Press

Kg/Cm2

2.3 2.3 2.3 2.3

TOP Temp 0C 114 111 114 113

Withdrawal

Temp

HN 156 150 154 157

SKO 208 210 208 211

GO 304 311 304 302

89

Withdrawal

Rate

HN 30 25 30 36

SKO 120 95 110 74

GO 125 111 120 177

CC-05 TOP

TEMP. 0C

64 67 65

CC-05 Top Pres.

Kg/Cm2

10.5 10.5 10.5 10.5

3.16 CRITICAL OPERATING PARAMETERS AND INSTRUMENTS

Sl.No

Equipment Critical Parameter

Instrument Provided

Remarks

1 Furnace Pass flow

80-140 m3/hr

FRC 1)Ensure flow above low alarm limit 2)Ensure equal pass flow through all pa passes

2 Furnace COT 365 – 3750C TC cascaded with PC on oil or PC on gas

1)Ensure steady oil temp. 2)Ensure steady oil pressure. 3)Ensure steady gas pressure 4)Ensure steady atomizing

steam pressure. 5)Ensure healthy burner

condition3 Column top

Pressure2.3 Kg/Cm2 PC split

range between FG & Flare

1)Ensure controller tuning 2)Ensure good desalter

operation 3)Ensure steady top temp. 4)Ensure boot water level

4 Column (CC-01) top Temperature

108-1200C TC cascaded with top reflux

1)Ensure controller tuning 2)Ensure normal reflux temp. 3)Ensure steady top pressure 4)Ensure boot water level

5 Over Flash 15-20 m3/hr FI Maintain Over flash flow of 5-6 vol% by adjusting Gas Oil draw as per HSD recovery / pour point

6 Column Bottom Level

40-50% LI / LCV cascaded with bottom R/D flow

1)Maintain 40-50% level 2)High level may colour gas oil 3)Low level may vapor lock bottom pump. In some column SDV is provided, which cutoff bottom draw at

90

low level.7 Furnace O2 02-03% O2 analyser 1)2 to 3% excess air

requirement should be maintained 2)More excess air means

energy loss 3)Less than required air will

lead to smoky burner & burner tip coke up.

Sl.No

Equipment Critical Parameter

Instrument Provided

Remarks

8 Furnace arch pressure

-5 to +2 mmwc

PI 1)Chance of back fire is there in case of high arch pressure

2)Inter lock is provided to cut off furnace in case STD does not open at high arch pressure.

3)Open more ID suction vane 4)Reduce Excess air 5)Open STD

9 Furnace arch temperature

850 to 9000C

TI 1)Adjust burner flame height. 2)Adjust air requirement 3)If required reduce T’put

10 Furnace stack temperature

< 2500C TI 1)Ensure furnace is not hard fired 2)Arrange for APH cleaning

11 Desalter Inter-phase Level

30 to 40% LDIC 1)Ensure that 30-40% level is maintained

2)At high level desalter load will increase, resulting poor desalter operation

3)At low level chance of crude draining along with brine is there

12 Desalter Amps

< 5 amps Ammeter 1)Higher amps means higher desalter load. May be due to high inter-phase level, high water emulsion in crude oil or Due to sludge carry over with crude.

2)Increase demulsifier rate & reduce mixing valve pressure drop.

13 Desalter Pressure

11.5 to 12.5 PG / PC on pre desalter crude pump discharge line.

1)Ensure controller tuning 2)Ensure that pressure is well

below PSV set point 3)Ensure furnace pass flows

are steady.

91

14 Reflux drum boot level

40 to 50% LCV 1)Ensure 30-40% level. 2)At low-level naptha may

drain along with sour water. 3)At high-level water will

carry over with reflux, resulting column condition upset.

4)Ensure desalter good operation

15 Caustic / water wash vessel’s inter phase level

40 to 50% LCV 1)Ensure 30-40% level 2)At low-level objective will

not solve. Feed H2S may not get removed

3)At high-level caustic solution will be carried over to storage tank & wll result in failure of Cu-corrosion test.

16 Boot Water Chloride content

Fe content

High

High

1)Increase caustic dozing & adjust ammonia to maintain boot water PH of 6-6.5 & Cl_ of < 3 ppm

2)For control Fe content < 2 ppm increase corrosion inhibitor dozing

92

93

CHAPTER-4

UTILITIES SYSTEM

UTILITIES SYSTEM

4.1 INTRODUCTION

Please refer following P & IDs for major utility distribution description:

3551-05-02-41-0141 Rev.2 LP steam, SW, PA System

3551-05-02-41-0142 Rev.2 CW, DMW Distribution Systems

3551-05-02-41-0143 Rev.2 Instrument Air, Fuel oil, Fuel Gas distribution system

3551-05-02-41-0144 Rev.1 MP Steam/HP Steam/BFW system

3551-05-02-41-0145 Rev.2 Flare System

3551-05-02-41-0146 Rev.2 CBD System

3551-05-02-41-0147 Rev.1 Flushing Oil Distribution

3551-05-02-41-0148 Rev.2 Amine Drain Distribution System

The utility system consists of Instrument Air (IA), Plant Air (PA), Cooling Water (WC),

Service Water (WS), DM Water, Boiler Feed Water, LP Steam, MP Steam, HP steam,

Fuel Oil, Fuel Gas & Flushing Oil.

Closed Blow Down (CBD), Flare and Oily Water Sewer (OWS) system are provided

within unit.

4.2 INSTRUMENT AIR

Refer P & ID No. 3551-05-02-41-0143 Rev.2

A 4” instrument air header supplies instrument air to the unit. This header is provided

with an isolation valve and a spectacle blind at unit battery limit. PI-4306 indicates the

pressure of instrument air at the battery limit, in DCS. A local pressure gauge is also

provided on this line. Instrument air consumption rate in unit is indicated by FI-4302 in

DCS. Various instrument air tapping are taken from this header. Instrument air is used as

motive force for pneumatically operated control valves.

94

4.3 PLANT AIR

Refer P & ID No.3551-05-02-41-0141 Rev.2

A 4” plant air header supplies plant air to the unit. The header is provided with an

isolation valve and a spectacle blind at the unit battery limit. The pressure of the PA at

the battery limit is indicated by PI-4104. FI-4102 indicates PA flow to unit. A number of

utility Hose stations are provided for plant from this 4” header. For decoking of crude

furnace separate 4” tapping are taken from main header. 1” size plant air tapping is

provided to seal pot.

4.4 COOLING WATER

Refer P & ID No.3551-05-02-41-0142 Rev.2

24” supply and return cooling water headers to the unit are tapped from underground

headers running on the side of the unit. Isolation valves with down stream spectacle blind

have been provided at the battery limit of the unit, on the both the headers. The CW

supply line is provided with PI-4202, FI-4201 & TI-4202 to indicate pressure, flow &

temp. at battery limit. Local pressure/temp. Indicators are provided on CW (supply &

return) lines. TI-4402 & PI-4207 are also provided on CW (Return) line.

Cooling water header serves following equipment in AU-5 unit:

05-EE-020 Hy. Naphtha Cooler

05-EE-019 Light Naphtha Cooler

05-EE-022A/B/C/D LR cooler II

05-EE-021 LR cooler II

05-EE-111A/B LR cooler I

05-EE-023A/B/C Gas oil cooler

05-EE-024 Kero/ATF cooler

05-EE-016A/B/C Atm. Column OVHD trim condensers

05-EE-017A/B/C Stabilizer OVHD condensers

95

05-VV-038 Pump Coolant pump

05-VV-030 CBD Drum

05-FF-001 & APH SECTION Furnace

05-EE-019B LN cooler

05-EE-016A/B/C/D/E/F CC-01 O/H Trim condensers

05-EE-017A/B/C/D CC-05 O/H condenser

05-EE-110A/B LGO coolers

05-EE-109 Kero – I cooler

05-EE-13A/B Brine cooler

4.5 SERVICE WATER

Please Refer P & ID No.3551-05-02-41-0141 Rev.2

A 4” service water header supplies service water to the unit. It is provided with isolation

valves and spectacle blind along with a local pressure gauge at the battery limit. A flow

indicator FI-4103 has been provided in DCS. The service water header supplies water to

various hose sections in the plans. Service water connections have been provide for

cleaning of lines through the suction of the pumps. These pumps are listed below:

05-PA-031A/B Caustic Injection pump

05-PA-032A/B Caustic Circulation pump

05-PA-005A CC-01 Reflux pump

05-PA-014A CC-05 Reflux pump

Service water serves the following equipments in AU-5

05-VV-030 CBD Drum

05-VV-034 Brine Degasser

05-FD-001 For APH washing

05-FD-002 For APH washing

4.6 DM WATER

Refer P & ID No.3551-05-02-41-0142 Rev.1

A 4” Dm water header supplies DM water to the unit form off sites. It is provided with an

isolation valve & spectacle blind, a local pressure gauge, temp. gauge and flow indicator

96

FI-4202 at the battery limit. From this header tapping have been taken to 05-EA-001 A-H

(Atmospheric Overhead Condensers), 05-VV-018A/B (Ammonia Vessels), Caustic

Vessels (05-TT-002A/B, 05-TT-006A/B, 05-TT-005) and 05-VV-005 (Desalting Water

Drum).

4.7 BOILER FEED WATER

Refer P & ID No.3551-05-02-41-0144 Rev.1

Boiler feed water (WB or BFW) is supplied to unit through a 2” line. It is used for

pressure reduction of HP steam at Super-heater. TG-4405 indicates BFW temperature at

battery limit FI-4403/PI-4405 indicates BFW flow & pressure battery limit. Boiler feed

water is routed to desalted crude outlet line from desalter.

4.8 LP STEAM

Refer P & ID No.3551-05-02-41-0141 Rev.2

Low Pressure steam header of 14” size has been provided to the unit with isolation valves

and spectacle blinds at battery limit. Local pressure, temperature & flow checking

element is provided in the battery limit of the unit. Following major headers are branched

off from the 14” main header:-

To 05-VV-029/05-EE-29 To LP Steam heating coil

To 05-VV-001A Sample point purge steam

To 05-VV-001B Sample point purge steam

To 05-CC-001 Body steam for steam out






To 05-PA-051A/B/C As quench steam for pump mech. Seal

To 05-PA-011A/B As quench steam for pump mech. Seal

To 05-PA-007A/B As quench steam for pump mech. Seal


97


To 05-PA-002A/B/C/D/E As quench steam for pump mech. Seal

05-FF-001 As snuffing steam

To Air Pre-heaters

05-VV-035

05-VV-030

05-VV-026

Steam for tracing of process line

Steam for utility hose stations

4.9 MP STEAM

Refer P & ID No. 3551-05-02-41-0144 Rev.2

A 12” Medium pressure steam MP steam header to the unit is provided with isolation

valve, spectacle blind & local pressure temperature gauges at battery limit PI-4401, TI-

4401 & FI-4401 are provided to indicate pressure temp. & flow of MP steam to unit.

16” size Mp steam header serves following equipment.

To Crude charge heater 05-FF-001 as:

Emergency steam to coils

Soot blowing steam

Decoking steam

Atomizing steam

TO 05-CC-001, 05-CC-003/-004/-005 as stripping steams.

4.10 HP STEAM

Refer P & ID No. 3551-05-02-41-0144 Rev.2

A 6” High-pressure steam MP steam header to the unit is provided with isolation valve,

spectacle blind & local pressure temp. gauges at battery limit. PI-4403, TI-4403 & FI-

4402 are provided to indicate pressure temp. & flow of HP steam to unit.

6” size HP steam header serves following equipment: -

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4” HP Steam to de-superheat by Boiler Feed Water injection in steam de-super-

heater 05-MD-001. The TIC-4406 maintains MP Steam temperature at de-super-

heater outlet by manipulating BFW injection into de-super-heater.

To 05-EE-028A/B/C/D (HP steam/FO heat exchanger) for heating media.

4.11 FUEL GAS

Refer P & ID No. 3551-05-02-41-0143 Rev.2

Sour fuel gas from various units i.e. from 05-VV-002 column over head reflux drum, 05-

VV-003 stabilizer reflux drum and 05-VV-020 LPG Surge drum is admitted into fuel gas

knock out drum (KOD) 05-VV-028. When no FG is being produced in unit or during first

start-up LPG can be backed to the LPG vaporizer from off sites through run down line.

LPG can be vaporized in LPG vaporizer 05-VV-029 with the help of LP steam to

produce FG. LPG flow to 05-VV-029 is indicated by FI-3202. It is admitted into

vaporizer under level control LIC-3202. Independent high & low-level alarms are also

provided on LPG vaporizer. LPG vaporizer pressure is maintained by 05-PIC-3202 by

manipulating PV-3202 on LP steam flow to vaporizer. Vaporized LPG is admitted into

fuel gas KOD 05-VV-028. FG from combined FG header is also being routed directly

into 05-VV-028 for condensate de-entertainment. FG from this KOD is taken out for

distribution through a 12” header under pressure control PIC-3204. PSV-3201 & PSV-

3202 are provided to protect 05-VV-029 & PSV-3203/3204 is provided to protect 05-

VV-028 from over pressurization. Drain of 05-VV-029 & 05-VV-028 are normally

routed to flare due to flashing nature of streams handled.

FG consumption in AU-V is indicated by FI-4304. PI-4304 measures pressure of the FG

header at battery limit. Local pressure & temperature gauge have been provided at battery

limit. Fuel gas is delivered to crude charge heater (05-FF-001) as fuel and Atmospheric

Column reflux drum (05-VV-002) & fuel oil surge drum (05-VV-026) to maintain

pressure. It is also connected as purge to flare header.

Modification is made to use AU5 LPG vaporizer to cater the requirement of GR Fuel gas

system. Its flow is maintained by 5FCV 257A. A new line has also been laid out to cater

the fuel gas requirement of MSQ plant during commissioning via 5PCV0204.

99

4.12 FUEL OIL

Refer P & ID No. 3551-03-02-41-0143 Rev.2

IFO from battery limit along with 2” Long Residue from 05-EE-004 is sent to fuel oil

surge drum 05-VV-026 under level control of LV-3103. FI-3103A measures the

combined stream flow to 05-VV-026. MP steam is used for heating medium in05-VV-

026. Fuel oil from surge drum is filtrated and is sent to FO high pressure steam heater 05-

EE-028A/B/C/D through 05-PA-045A/B. Provision to divert IFO to slop header from PA

045A/B is also there. From heater FO is again sent to filters 05-GN-002A/B. Filtered

fuel oil is sent to fuel oil supply header of AU-5 for distribution. Fuel oil is supplied to

fire heater of the unit through a 4” header. Local pressure gauge and temperature gauges

have been provided near respective heaters. Fuel oil flow to heaters is measured by flow

meter on respective FO (supply) header. A return fuel oil line has been provided from

furnace. Return line has been provided with a globe valve, shut down valve & flow

meters. About 50% of the supply fuel oil allowed to return through this line. This

circulation of fuel oil to atmospheric furnace is recorded by flow differential recorder.

Fuel oil return header with bypass has been provided from supply line to allow

independent FO circulation for the furnace.

4.13 FLUSHING OIL

Refer P & ID No. 3551-05-02-41-0147 Rev.2

Flushing oil is normally light oil with boiling range & properties comparing well with

diesel oil. It is used at flushing medium for displacing heavy, congealing & viscous

material from equipment piping sections during unit shutdown or for other maintenance

job requiring freeing of equipment from such hydrocarbons. Flushing oil to unit is

received from off sites through a 4” header. Provision to divert unit gas oil R/D to

flushing header is also there. 4” size combined flushing oil from unit & off site runs

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through out pipe rack of unit & supplies FLO to following equipment shown in P & ID’s

listed below: -

a) 05-FF-001

b) 05-PA-051A/B/C Suction line

c) 05-EE-022A/B/C/D Shell side

d) 05-EE-021 Shell side

e) 05-EE-010A/B/C/D Shell & Tube side

f) 05-EE-009A/B Shell side

g) 05-EE-007A/B/C Shell & Tube side

h) 05-EE-006A/B Shell side

i) 05-EE-001 Shell side

j) 05-EE-002 Shell side

k) 05-EE-003 Shell & Tube side

l) 05-EE-004 Shell & Tube side

m) 05-EE-005 Shell side

n) 05-EE-028A/B/C/D Shell side

o) 05-PA-002A/B/C/D/E Suction line

p) 05-PA-001A/B/C/D/E Suction line

q) 05-PA-045A/B Suction line

r) 05-EE-102A/B Shell side

s) 05-EE-103A/B Shell & Tube side

t) 05-EE-103C Shell & Tube side

u) 05-EE-104A/B Tube side

v) 05-EE-105A/B Shell & Tube side

w) 05-EE-105C/D Shell & Tube side

x) 05-EE-105E Shell & Tube side

y) 05-EE-106A/B Shell side

z) 05-EE-106C/D Shell side

aa) 05-EE-107A/B Shell & Tube side

bb) 05-EE-107C/D Shell & Tube side

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cc) 05-EE-108A/B Tube side

dd) CBD End cover

4.14 ELECTRIC SYSTEM

Electrical load for AU-5 is anticipated as 3220 KW. In the event of power failure back up

Emergency power supply arrangements has provided. Electrical system of AU-5

compromises of a Number of sub-systems. They are briefly described as under.

4.14.1 ELECTRICAL POWER FOR PUMPS

Motors above 160 KW ratings are fed with 6.6 KV switchboards.

Following pump motors are fed by High Tension feeder at 6.6± 10% KV AC from Unit

substation, individually for each of following motors:

05-PA-001A/B/C/D/E Crude charge pumps

05-PA-002A/B/C/D/E Desalted crude pumps

05-PA-51A/B/C RCO pumps

Above motors are termed as HT motors. Remaining all other motors are fed by low-

tension feeder at 415± 5%V, and 230± 5%V, 3 phase, AC power.

Motor start/stop push buttons and local Ammeters are provided at local control station for

motors in field. However, local Ammeters are provided only for motors with rating 55

KW and above. All LT motors feed through switch fuse contractor are provided with

240V AC control supply. 110 V DC control supply is provided for all HT motors &

motor having rating exceeding 75 KW, & power motor control centre. Running status

lamps for pump are provided on control room auxiliary console panels as per P & ID for

critical motors with potential free contacts, similar to control room instruments.

4.14.2 PLANT ILLUMINATION

All plant lightings are provided with 230± 10% V AC power. For maintaining emergency

lighting, emergency lighting fixtures are fed with 110 V DC power feeder, so that in the

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event of power failure, minimum light in critical areas such as control room, sub-station

escape route etc. are sustained.

4.14.3 INSTRUMENTATION POWER SYSTEM

Main features of electrical instrumentation power system are described below:

Through a battery bank in main unit sub-station, 110 V DC supply is available to

all solenoid valve infield and auxiliary consoles in Control Room. On auxiliary

consoles are mounted Push Buttons, Running Status, Lamps & Selector Switches

to PLC interlocks etc. few spare outlets of 110 V DC supply are also provided in

control room to carry out miscellaneous testing jobs etc. battery back up will

remain available for a period of 1 hour for UPS & other Instrument requirements.

110 V AC power supply (uninterrupted) is available to all Hard Wire Alarms,

Hooters, Multipoint. Digital Temp. indicators (TJI), Density Analyzers,

Supervisory Computers, Printer, Video Hot copier, DCS monitor (CRT) & hand

indicator controllers.

In the event of power failure, 110 V AC supply will remain available for a

maximum period of 60 min to above instrument to facilitate safe shut down of

process units. If power from main feeder is still not resumed plant instrument will

assume safe shut down position according to logic built in PLC. After power is

resumed DCS system and supervisory computer should be booted before reverting

back to normal operations.

4.15 EFFLUENT SYSTEM

All off-spec. hydrocarbon streams contaminated with water, water contaminated with

hydrocarbons/chemicals and such liquid streams that can not be disposed off directly are

collected & treated either for recovery of hydrocarbons or to render them harmless to

receiving stream or for both the purpose. For this purpose, slop system, CBD system,

OWS system, Sewer Water (SWS) and Amine drain system are provided.

These systems are described sequentially as under:

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4.15.1 SLOP

Those off-spec. hydrocarbon streams that are not contaminated with water and need to be

disposed off are termed as dry slop. 10” size slop header is provided in the unit to collect

slop from AU-5 that can be routed to GRE /OMS slop tank.

4.15.2 CLOSED BLOW DOWN (CBD)

Refer P & ID No. 3551-05-02-41-0133 Rev.2

3551-05-02-41-0146 Rev.1

Those Hydrocarbon Streams that are either free of water or only slightly contaminated

with water are received in closed Blow Down (CBD) vessel, 05-VV-030. Such

Hydrocarbon streams are generated especially during shut down periods when equipment

& systems are drained under gravity to clear hold up oil. The hydrocarbon in the CBD

vessel should be received at a temp. Well below flash point of lightest component present

inside.

Closed Blow Down network helps reducing amount of hydrocarbon finding its way to

effluent treating facility via OWS during equipment draining. Uncontaminated

hydrocarbons from equipment draining is collected & routed to CBD vessel via CBD

system covering entire unit equipment.

Two 6”line closed blow down headers run across plot AU-5. These are provided with

clean out pit at header ends with Flushing oil connection to flush heavy congealing

hydrocarbon material accumulated in header, if any. One utility connection is also

provided on each CBD header end, close to FLO connection to flush CBD headers with

any other utility. However, care should be taken to avoid steaming of CBD header, as line

is not designed for steam out conditions due to absence of expansion provisions.

05-VV-030 is provided within AU-5 battery limit. CBD drum is a horizontal drum

located underground in a pit. The drum is provided with a coil through which cooling

water or LP steam can be passed. Hydrocarbons mixed with slight water are allowed to

enter in this drum from where Hydrocarbon is pumped out by CBD pump 05-PA-046 to

existing crude/slop header. LAH-3302 and LAL-3302 are provided to auto start and auto

stop the CBD pump. LI-3301B indicates the level of the drum. TI-3301 & PI-3301

indicates the temp. of the contents in the CBD drum & pressure inside drum. Under

104

normal condition, it is expected to remain at atmospheric pressure. A small purge of

steam is provided at the vent of the drum to guard against lighting and static electricity

hazards.

One coil is provided inside CBD drum through which either cooling water can be

circulated or LP steam can be introduced. Cooling water shall be introduced to bring

down temp. of hot material drained & accumulated inside vessel while LP steam can be

introduce in the same coil after isolating cooling water to decongeal/heat-up accumulated

heavy material inside vessel & bring it to pump-able viscosity. TI-3302 indicates temp. of

contents going out of CBD vessel.

4.15.3 OILY WATER SEWER (OWS)

This system is also called OWS system is mainly to collect water contaminated with

hydrocarbon oils. Such streams are usually generated during equipment draining &

flushing during routing operation. Streams suitable for OWS are also generated as a result

of floor washing, cleaning of spilled oils etc. Streams suitable for OWS should never be

routed to CBD as it may ultimately lead to receipt of lot of water in slop tanks. Drained

streams at ambient temperature received through OWS fennels etc. are routed to ETP

through a combined header. All equipments having CBD connections are normally

provided with OWS/SWS connection on following basis:

All continuous draining (HC bearing streams) having CBD connections are

provided an additional connection to OWS.

All intermittent draining (HC bearing streams) are provided a CBD connection

and connections to OWS.

All non-HC streams are connected to OWS.

Pump base plates, TSV discharges and floor washing are also routed to OWS. Care

should be taken that at no time any spark reaches vapour space of OWS fennels. This

may result in explosion immediately there or elsewhere in network wherever explosive

mixture of Air & Hydrocarbon vapours is present is appropriate for explosion.

4.15.4 SEWER WATER SYSTEM

105

SWS are similar to OWS and are routed to ETP separately through underground piping.

AT ETP provision to route SWS to OWS is also provided. The SWS thus shares the

OWS load as & when necessary.

Those effluent streams that contain only traces of hydrocarbon or are completely free of

oil should be diverted to SWS.

Storm channel around the plant is an open channel. As streams of storm channel leave the

plant without any separation or treatment, free Hydrocarbons should not be allowed to

escape in storm channel. Elaborate arrangement exists to handle oil free effluent of unit.

Effluent finally escaping through storm sewer without any treatment must meet statutory

specifications for safe disposal.

4.15.5 AMINE DRAIN SYSTEM

Refer P & ID No. 3551-05-02-41-0148 Rev.2

Drained Amine streams from amine absorber (05-CC-006) and Amine

Settler (05-VV-004) that is either free of water or oil or slightly contaminated with water

is received in 05-VV-033 (Amine Sump). Amine sump is provided within AU-5 battery

limit. Accumulated / drained amine is pumped out by Amine pump 05-PA-048A to

Amine Regeneration unit. LI-4801 with LAL/LAH indicates the level of the sump. TG-

4802 shows the temperatures of the contents in the amine sump.

One coil is provided inside amine pump through LP steam can be introduced to boil out

the contaminated water in amine. TG-4801 and PG-4801 indicates the temp. and pressure

of contents going out of Amine drain sump.

4.15.6 FLARE SYSTEM

Refer P & ID No. 3551-05-02-41-0133 Rev.2, 3551-05-02-41-0145 Rev.1.

In the event of abnormal operating conditions/emergencies, the hydrocarbon operating

system may get pressurized. In order to prevent this pressure form shooting up and

crossing design valves of respective system/equipment and causing accident and/or

equipment damage, it may become necessary to relieve some amount of non-condensable

hydrocarbon vapors to system that renders them harmless. For this purpose, a network of

106

flare headers is provided for collection of vapors in unit to which all relevant equipments

are connected.

Flare lines should be tested pneumatically because of line support considerations. Entry

of steam and condensate in flare headers should be avoided as it may lead to

extinguishing of main flare

The combined flare header enters flare knock out drum 05-VV-032 for de-entrainment of

condensate droplets. Local instrument is provided on 05-VV-032. LI-032 with LAH/LAL

is provided on flare KOD to indicate high and low condensate level. LSHH/LAHH-3308

also provided in the vessel. It will open SDV-3310 on vessel bottom outlet. Similarly,

LALL-3307 will close SDV-3301 & avoid vapor break through it. CBD vessel requires

manual draining. One isolation valve with a spectacle blind in between has been provided

on flare header at battery limit of the unit. A 2” fuel gas connection has been given to the

flare header for purging purpose RO-4502 is provided on FG purge line to flare to

maintain & control FG pressure entering flare header. The FG purge is provided in flare

header to prevent vacuum formation due to condensation of condensable hydrocarbons

on account of to weather temperature change, chilling etc. & to maintain certain

minimum velocity inside flare header.

One 24” flare header serves to collect the pressure relief valve discharges form the AU-5

equipment & certain piping in Hydrocarbon services. Following equipment PSV are

connected with this flare header: -

Spent Caustic degasser 05-VV-016

LPG Surge drum 05-VV-020

FO surge drum 05-VV-026

Kero/ATF water wash vessel 05-VV-014

Kero/ATF caustic wash vessel 05-VV-013

Kero/ATF Coalescer 05-VV-015

LPG Coalescer 05-VV-008

LPG water wash vessel 05-VV-007

LPG caustic wash vessel 05-VV-006

Heavy Naphtha coalescer 05-VV-025

107

Light Naphtha water wash vessel 05-VV-010

LPG drum 05-VV-029

Fuel Gas KOD 05-VV-028

Light Naphtha caustic wash vessel 05-VV-009

Atm. Distillation column 05-CC-001

Naphtha stabilizer 05-CC-005

LPG Amine Absorber 05-CC-006

Atm. Column Reflux drum 05-VV-002

Stabilizer Reflux drum 05-VV-003

Following equipments of AU-5 are also connected with same 24” flare header:

Stabilizer OVHD Condensers 05-EE-017A/B/C/D

Atm. Column Reflux pumps 05-PA-005A/B/C

Stabilizer feed pumps 05-PA-006A/B/C

Stabilizer OVHD pumps 05-PA-014A/B

Heavy Naphtha product pumps 05-PA-008A/B

Light Naphtha product pump 05-PA-041A/B

108

CHAPTER-5

NORMAL START-UP PROCEDURE

109

NORMAL START – UP PROCEDURE

5.1 INTRODUCTION

Start up and shut down are the most critical periods in operation of any process unit. It is

then that the hazardous possibilities for fire and explosion are highest. Start up and

normal operating procedures of all the units are described in this section.

The hazards encountered most frequently in start up and shut down of units are

accidental mixing of air and hydrocarbons and contacting of water with hot oil. Other

hazards primarily associated with start up are excessive pressure, vacuum and

thermal/mechanical shocks. These can result in flares, explosions, destructive pressure

surges and other damages to unit as well as injury to personal.

Fires occur when oxygen and fuel vapor or mists are mixed in flammable proportions and

come in contact with an ignition source. They may run out of control or touch off

devastating explosive. 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 explosive bursts lines or

vessels. Following are the highlights of the operation of AU-5. Operating conditions

given here are for AM crude case. Suitable changes in operating conditions should be

made as per operating conditions given in sec. 5.6.1 for specific of operation.

5.2 BRIEF START-UP PROCEDURE

Start up summary for various process sections is given in following pages to develop a

quick comprehension of start up strategy to be adopted. After mechanical completion of

the unit, it is steam purged for expelling air and kept under fuel gas pressure. After water

draining, cold crude circulation is established and water in the system is swept out. Crude

Charge Heater 05-FF-001 is fired. About 50% of normal flow is maintained through

heater coils. Transfer temp. is raised insteps to 120 C at a rate of 400 C/hr. The COT is

maintained for about four hours to remove residual water from the system by

evaporation. The transfer temperature is then further raised to 2500 C at 300 C/hr. Hot

110

bolting of flanges and manhole covers likely to remain in hot service is carried out at this

stage by holding the temperature at around 2500 C during this activity.

Top temp. of the column will gradually rise. When the column top temp. reaches more

than 100° C steam will escape from the column and condense in overhead naphtha

condensers. As top temperature rises further, column pressure is slowly raised to its

normal value. Higher pressure will help in better condensation of vapors. As level starts

building up in atmospheric column reflux drum, refluxing can be started after draining

water.

05-FF001 COT is then further raised to 300 C. The column top temperature and pressure

are maintained constant. When naphtha make increases that is indicated by rising level in

crude column overhead reflux drum V-02, it can be routed to the naphtha stabilizer

column or else it can be slopped. Stripping steam to crude column is admitted at this

stage and unit is brought out of circulation. When levels appear in the crude column side

stream strippers, line up circulating reflux circuits, and maintain strippers levels at about

50%. Water is to be drained before starting the circulating reflux pumps. 05-FF-001 COT

is then further raised to normal value of 375 C. Flow and temp. of all CR streams are

adjusted to maintain proper temp. Profile in the column. Line up all product circuits up to

battery limit. Start respective product pumps when level appears in the strippers. Route

all products to slop header initially.

Start diverting un-stabilized naphtha-to-naphtha stabilizer column. Once sufficient level

(about 70%) is built up in stabilizer column bottom, stabilizer column will be brought on

stream by gradually cutting in the heating medium (gas oil CR) in re-boiler. As

temperature of the stabilizer column rises, pressure will increase and level will appear in

the stabilizer reflux drum. When level appears in the stabilizer reflux drum, start

refluxing. Stabilized naphtha from stabilizer bottom is routed to storage tanks through

naphtha coolers. & LPG from stabilizer top is routed to Horton sphere after amine &

caustic wash.

LR at outlet of atmospheric column bottom is routed to slop header/ storage via product

cooler. When the normal transfer temp. of 375 C has been attained at normal crude feed

rate make necessary adjustments and normalize the operating conditions in atmospheric

section.

111

5.3 DETAILED START-UP PROCEDURE (AFTER M&I SHUT DOWN)

Preparation for start-up needs a complete review of the start-up procedure by the

operating crew. Activities of atmospheric Unit V should be co-ordinate with off sites,

utilities and other units.

Start up of the unit involves the following consecutive phases.

Preliminary Preparation of the unit

Removal of air for the process systems

Tightness testing to prevent leakage

Fuel gas backup to prevent air ingress

Crude & RCO circuit fill up.

Cold circulation for removal of water

Hot circulation

Bringing the unit on stream

Unit start-up steps are described below:

5.3.1 PRELIMINARY PREPARATION

Prior to actual commissioning of the plant, it should be established that all preparatory

works have been successfully completed and all instrument/equipment are ready to

function. It is to be ensured that:

Blinds are installed as per master blind list. Each removal and insertion of a blind

should be noted and installed by the in-charge.

All vessels, piping, equipment are pressure tested, flushed and ready for service.

All rating equipment such as pumps, motors etc. have undergone functional test

successfully.

All instruments have been checked and calibrated. Controls should be kept on

manual as far as possible.

Instrument loop checking is done.

112

All safety valves are in position after setting lock open position. Spare valves

should be kept isolated as per P & ID stipulation.

All utility headers are charged.

Flare, amine drain, closed blow down, sewer and flushing oil systems are in

operable condition.

All related units are informed of the start-up plan (RSM / OMS/TPS/Water block)

All pre-commissioning activities are completed.

Fuel oil and fuel gas blinds are removed and both headers charged.

Tracing stream flow to the lines is established.

Tightness, vacuum test and heater refractory dry out will form part of pre-commissioning

activities for the first start-up. For subsequent start-ups the tightness test and vacuum test

can be done in conjunction with the step of elimination of air.

Procedure of commissioning of Utilities / FO / FG / FLARE

1. STEAM

Deblind Battery valve limit U/S flange.

Line all steam trap & its bypass

Slowly open battery limit valve, two thread

Drain out all condensate.

Check for any hammering sound. If it is there reduce steam in take.

When dry steam starts coming from trap bypass, increase battery limit valve

opening.

Close trap bypass.

Keep all the coolers & condensers isolated.

Open battery limit I/L valve.

Open vent of return line.

When total air is displaced, close the vent.

Line up I/L & O/L valve fully.

Commission by the same procedure all coolers & condensers after displacing air.

113

2. FUEL OIL

This is to be commissioned after FG & Flare header is commissioned.

Check for completeness of all the job.

Keep all the isolation & bypass valves of V26 split range pressure C/V.

Provide steam hose connection at (1) V26 LG drain.(2) at P 45 A/B discharge PG

(3) at furnace IFO PG point Drain.

Line up total IFO circuit.

Close individual FO burner valve.

Bypass Low pressure inter lock.

Open I/L & O/L SOV. & PIC.

Start steaming total circuit & the surge vessel.

Drain condensate from all LPDs and Vent through all HPVs & Vessel vent.

Steam for at least 4 hr to displace air/ maintain system pressure @ 1 kg/cm2

Check for any leak & fix it.

Back up gas in the system by opening V26 make up PIC bypass valve, at the same

time stop steam injection & close all vent & drains.

Bring system pressure to 1.5 Kg/Cm2

Drain water from all LPDs of the circuit & from V26.

Commission V26 PIC.

Take Gas oil in V26.

Establish IFO circulation & continue for 2 hrs.

Drain out water from all LPDs.

Blind/cap all LPDs/HPVS

Stop circulation. Allow to settle water for 2 hr. Drain V26 to minimum level.

Receive VR in V26.

Establish circulation.

Commission HP steam heater & maintain temperature as required.

114

3. FG COMMISSIONING

Deblind FG In / Out line battery limit valve.

Furnace FG should remain blinded.

All line connected to FG header should be kept isolated by valve.

Provide steam hose connection at LG drain of VV28 FG KOD & of VV29 LPG

drum.

Provide steam hose connection at V26 PIC bleeder.

Start steaming through the all above points. Drain & vent from all available LPDs

& HPVs, & from filter drain.

Steam for 4 hr to displace air / maintain system pressure @ 1 kg/cm2

Check for any leak & fix it.

Back up gas in the system by opening battery limit valve at the same time stop

steam injection & close all vent & drains.

Bring system pressure to 1.5 Kg/Cm2

Drain water from all LPDs of the circuit & from V28/V29

Blind/cap all LPDs/HPVS

4. FLARE COMMISSIONING

Provide steam connection if is not there at the furthest end of the system

Isolate all PSV/ lines connected to flare header.

Introduce steam & purge the system to flare for 2 hrs, drain condensate from

KOD drain, from B/L valve U/S flange W/O & U/S bleeder.

Maintain pressure 0.5 Kg/Cm2. Check & fix if any leakage is there.

Reduce steaming to minimum & get the B/L valve deblinded

Increase steaming rate & continue for 4 hrs.

Stop steaming & back up gas by opening battery limit valve.

Isolate all drains & vents and get it blinded/capped

Drain water from KOD.

115

5.3.2 AIR REMOVAL FROM THE PROCESS SYSTEM

Air from various equipment piping etc. is eliminated by steaming of various sections of

the unit can be carried out simultaneously or in a convenient sequence. The following

basic points should be taken care during steaming of the equipment systems.:

Cooling water to the condensers and product coolers to be isolated and water

should be drained out from the condensers, coolers etc.

Keep waterside vents and drains of condensers/cooler opened.

Keep instrument tapping like PT, FT etc. isolated from main process piping.

Electric supply to the desalter should remain cut off.

For the purpose of air removal unit is divided into following circuits for steaming: -

1. Crude Preheat Train I Circuit Before Desalter

1a) Old preheat train I before desalter consisting of

PA-01 5HC5001 EE-01 EE-02 EE-03 EE-04EE-05Desalter

1b) New preheat train I section before desalter consisting of

EE-103A/B/C

5HC5002 --EE-102A/B Desalter

EE-104A/B

2. Crude Preheat Train II Circuit After Desalter

2a) Old preheat train II after desalter consisting of

Desalter PA-02 5HC5005 --- EE-06A/B EE-07A/B/C EE-08A/B EE-

09A/B E-10A/B/C/DFurnaceColumn

2b) New preheat train II after Desalter consisting of

EE-105A/B/C/D/E EE-108A/B

PA-025HC5006 F01 C01

EE-106A/B/C/D EE-107A/B/C/D

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3. CC-01 OVERHEAD CIRCUIT

CC-01 EA001A-H EE16A-F V V-02 PA05- 5FC1505 CC-01

PA6 -FC1701-EE18A-D-C05

4. COLUMN CR CIRCUIT

4a) Top CR Circuit

CC-01 PA-07 EE-02 5FC1501CC-01

4b) SKO CR Old Circuit

CC-01 PA-10 EE-06A/B EE-05A/B - 5FC1502 -- CC-01

5TC1116 is between EE-06A/B and EE-05A/B. This loop also to be steam flushed to

expel air.

4c) SKO CR New Circuit

CC-01 PA-102 EE-104A/B - 5FC5008 CC-01

4d) HSD CR Old Circuit

CC-01PA-12 EE-09A/B 5TC1707 (5FC1704) EE-14 5TC1538(5FC1507)

EE-155FC1503 CC-01.

Both TC 1538/1704 loop flushing to be ensured.

4e) HSD CR new Circuit

CC-01 - PA-104A/B -- EE-108A/B 5FC5010 CC-01

5) PRODUCT RUNDOWN AND SLOP CIRCUIT

5a) LN Product circuit

EE-18A/B

LN from C-5 Bottom5TC1702 EE-19A/B**

EE-18C/D

↑ FC 5106 AU1 rerun Section ↓HN to LN

**SOV1701HC2001BVV-09HC2002BVV-10PA041A/B 5FC2004

↓ LN R/D

5TC1702 loop flushing also is to be ensured.

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VV-09 and VV-10 bypass lines also to be steam flushed to expel air

5b) Hy. Naphtha Product Circuit

C1LC1506C2PA-08A/B 5FC5001 EE-102A/B GO R/D (new circuit)

PA-08A/BEE-20VV-25 5FC1807 -HSD OM&S r/d.

5FC2011 SKO r/d.

5PC2011 LN r/d.

HN r/d to Slop.

5c) SKO Product Circuit

C1LC1508C3PA-09EE-01EE-24/23C-HC2201V13**

**HC2202V14 V15 5FC2206 Salt DryerSKO/LABFS/ATF

FC1809HSD

LR

(While steaming SKO circuit SKO drier to be by passed. SKO drier I/L and O/L B/V to

be thoroughly closed)

5d) HSD Product Circuit

HSD Product Old Circuit HN / SKO

C1LC1510C4PA11EE-08A/BEE-03EE-23A/B/C 5FC1804

HSD Product new Circuit

C1LC1510C4PA-103EE-106A/B 5FC5009 EE-102A/B- EE-110A/B

coalescer

Coalescer FC 5003 BS2 header

DHDS feed tank

GHC R/D

PC 5003 Euro-III

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5e) LR Product Circuit

Old Circuit

PA-51 EE-10 A/B/C/D EE-07A/B/C EE-04 EE-21

New Circuit

PA-51EE-107A/B/C/DEE-105A/B/C/D/EEE-103A/B/C E111A/B

New & old joins together FC1805 hot RCO R/D

SKO / Hy.HSD ex FPU2

E22A/B/C/D FC1806 cold LR R/D

Unit circulation

6) STABILIZER FEED CIRCUIT

EE-18 A/B **

PA-06 5FC1701 CC-05

EE-18 C/D

** CRU drag stream, DHDS / Lab / MSQ unit wild Naphtha are joining at D/S of

Fc1701.

9) LPG PRODUCT CIRCUIT

LPG circuit is divided into following circuits

C5 top HIC 1701 E17 A-D V3

V03 top PRC 1701 FG system

V03 bottom PA-14A/B FC1703 C5 reflux

AU4 LPG

V03 bottom PA-14A/B - 5FC2503 SDV2501 VV-20

V20 top PC2501 FG

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VV-20 Bottom PA-50 5FC2502 VV-20 (min. cir)

5FC2502 CC-06

C6 top VV-04 VV-06 VV-07 VV-08 5PC1912 LPG r/d

FI 3202 Vaporizer

Amine to and from C06 line steaming is also steamed.

The condenser bypass line through HIC 1701 also to be made air-free.

LP system connections are given at appropriate places on piping & equipment to

introduce LP steam in above sections. Before introducing steam, water to all coolers and

condensers should be isolated and drained. This is to avoid condensation of steam in

large quantity in these equipment due to flow of cooling media, i.e. cooling water. It may

lead to frequent hammering in unit equipment. LP steam from hose stations can also be

used to boost up external steam supply. Initially there may be condensation of steam

inside unit equipment due to cold equipment internals. In such conditions, LP steam

supply may need augmentation of small quantity of MP steam through heater pass flows

and other available points. Care should be exercised while using MP steam for steaming

to ensure that none of equipment is subjected to operating conditions exceeding their

design parameters. The low point drains of pipes and equipment should be kept open to

remove condensate. During initial steaming, line rust etc. may frequently keep coming

and chocking the drains may be rather frequent. Special care should be taken to ensure

that none of the drain points are chocked due to accumulation of foreign material. High

point vent should also be opened for air removal. Once system warms up, less steam will

condense in the system and few steam points may be pinched. Steaming is done till clear

steam stars coming out from all vents. Clear steam venting for at least four hours shall be

an indication of fairly good air removal. Excessively high steaming rate may dislodge

column internals and cause damage. Hence it is a good practice to keep a watch on steam

consumption during steaming.

No steam condensate should be allowed to get accumulated inside unit equipment.

Vigorous steam venting from various points of the unit is described below till be

continued for about 4 hours. It is expected that oxygen will be eliminated at the end of

this period. Samples may be checked from different locations to check that 02 content is

less than 1%.

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During the period of steaming, systems should also be checked for leakage. Attend the

leaks by depressurizing the system. Reset and purge as applicable.

When sufficient steam comes out from all the vents and drains reduce steam inlet to

maintain positive pressure.

Following major points may be followed for steaming out of the unit:

a) Admit steam into the feed system by connecting temporary hoses to the crude oil

feed line at the battery limit of unit.

b) Open steam slowly into the system and allow piping and equipment to gradually

warm up. Drain condensate frequently from low points. Steaming should be done

up to crude charge pump suction. Eliminate air through all exchanger vent points

and drain out condensate from all exchanger low points. Flushing oil header

should also be streamed out.

c) A steam hose connection should be provided at the discharge of crude charge

pump for steaming the preheat section up to desalter.

d) Introduce steam into preheat train I/II connection using 2” LP steam downstream

of crude charge pump. Keep watch on desalter pressure, which should be

maintained around 0.5 Kg/cm2 g. If necessary, throttle steam purge desalter safety

valve inlet lines also. Air should be completely purged out from both inlet and out

let lines of each safety valve. Desalter water circuit should not be included for

steaming out. However lines up to mixing valve, and chemical injection lines up

to first isolation valve from desalter should be included for steaming. Allow steam

to vent from desalter top and other high point vents.

e) Line up atmospheric column overhead condensers, and atmospheric column

reflux drum with the column. Ensure water to condensers is isolated and water is

drained out. Open vents of overhead naphtha reflux drum and crude column. Line

up heavy naphtha, Kero, GO strippers and product circuit, and circulating reflux

circuits up to the respective pumps. Keep pump suction and discharge valves

closed for same reasons reason as explained above. Introduce LP steam in the

circuit from permanent steam connections as well as Stripping steam at a

controlled rate to warm up the system.

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f) Slowly open some MP steam also into all the passes of atmospheric heater coils

through emergency steam connections (provided at down stream of pass flow

control valves) and in crude column bottom. Also open steam to the crude column

bottom and side strippers via strippers steam lines. MP steam is used as

augmenting stream to adequately carry out steam out. Too high a flow rate of

steam may dislodge the column internals and damage them.

g) Vigorously steam for at least 4 hours and then shut off crude column vent. Allow

steam to vent from atmospheric column reflux drum.

h) Maintain 1.0-1.5 Kg/cm2g pressure in column flash zone by regulating the

quantity of steam being introduced into the system. Drain condensate from low

points and allow system to warm up. Regulate the steam flow to heat up the

system gradually. Continue purging till steam comes out from the top of the crude

column, crude column reflux drum and side stripper vent connections. For

steaming out heavy Naphtha and Kero side strippers, back-up steam form crude

column and vent through 2” utility connection in these strippers. Release

condensates through pump suction strainer flanges, wherever applicable.

i) Back – up steam from atmospheric column to preheat train I/II. LP steam from

hose stations can also be connected in desalted crude pump discharge circuit to

boost up external steam supply. Back-up steam from charge heater to preheat

trains-II. Increasing C-001 pressure slightly if required. LP steam from hose

stations can also be connected to pre-flashed crude pump discharge to augment

external steam supply.

j) Line up stabilizer overhead condenser and reflux drum to stabilizer column. Open

vent valves of stabilizer column and its reflux drum, and other high point vents in

piping. De-blind utility LP steam connection at the stabilizer column bottom.

Admit steam slowly by connecting a steam hose. Drain condensate from low

points and allow the system to worm up.

k) When steam comes out from stabilizer top vigorously steam for about half an

hour. Then shut off this vent and allow steam to come out of reflux drum vent.

l) Maintain stabilizer column pressure at 1.0-1.5 Kg/cm2g by regulating the quantity

or steam. Open the pressure control valve and globe valve on its by-pass line.

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Steam for about half an hour then shut off the control valve and the globe valve

mentioned above. Back-up steam into the reflux line and vent from the bleeder

valve up stream of flow control valve.

m) Purge feed line by backing up steam stabilizer column and vent from the bleeder

valve, up stream of feed control valve. LP steam should be backed in stabilizer

feed line up to NRV by connecting a temporary steam hose connection at

conveniently available low point and by by-passing minimum flow control valve

of stabilizer feed pump. During stabilizer purging do steaming of wild DHDS /

LAB naphtha and CRU drag stream up to battery limit by backing from the

column keeping battery valve closed, drain condensate from the bleeder present at

the D/S of battery limit valve.

n) Purge stabilizer bottom outlet circuit up to battery limit.

o) Purge all product and pump around circulating reflux circuits by backing up steam

from respective column. Steam the product circuit up to battery limit and vent

through sample points or any convenient low point drains. It may be necessary to

augment steam supply at the discharge of product pump by connecting temporary

hoses to vent so drain points in the lines. Battery limit valve flange may be wedge

opened for good steaming. Box up the flange under slight steam pressure.

p) Excessive condensation of steam in cold circuits and problems of removing steam

condensate from heater coils, in particular may cause hammering during

steaming. In such cases, it may become necessary to fire the heater at the time of

steaming itself for evaporating water. Commission flare header and fuel gas

header to furnace after removing battery limit blind. Fire the heater at a small rate.

Heater is fired to avoid condensation in tubes and subsequent hammering when

steam is introduced in cold tubes. Maintain firebox temp. at about 250° C. Pilot

burners will be lighted initially. Main burners can be lighted afterwards, if

required. Keep open the vents at crude column top and crude column reflux drum.

q) Steam out LR circuit and all LR product lines up to isolation valve at the battery

limit.

r) Air elimination from product run down circuits in off sites should be done by

filling water in line and displacing the same by products when the same are

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available except for water sensitive products like ATF whose run down temp. is

high.

s) Air elimination from water circuits and chemical dosing circuits need not be

carried out except up to first isolation valve where these lines may be subjected to

hydrocarbons.

5.3.3 TIGHTNESS/PRESSURE TEST

For leak testing, tightness test is to be done. Ensure that all piping & equipment vents and

drains closed. Pressurize the system up to 1.0 Kg/cm2 g with LP steam or air and check

for any leak through the flanges / instruments.

Usually for a very big system, pressurization by steam for tightness test proves

convenient. Limitations posed by design pressure design temp. should be strictly adhered.

The leakage identification is normally done visually when steam is used and by soap

bubble test when air is used.

Liquid soap solution may be sprayed poured on all the joints one by one and check for

any bubble formation. If a bubble is formed on joint or flange, there is an air leakage.

Leaks are to be attended after depressurizing. Big leaks can also be identified by pressure

drop identification. In view of large number of joints requiring leak test by soap

solution, it is suggested that only those systems should be taken up for tightness test by

air which should not be subjected to steaming or are likely to get exposed to vacuum

during vacuum test & normal operation.

Tightness of other systems may be done along with steam purging & pressurizing by

steam. Thus tightness test by air and steam purging tightness test by steam can be carried

out almost parallel, depending on availability of manpower & ease of monitoring.

5.3.4 FUEL GAS BACKUP

Fuel gas is available from off sites for start-up of the unit. Purpose of fuel gas backing

into the system is to drain steam condensate from unit equipment as well as replace steam

with fuel gas. It the absence of fuel gas, condensation of steam may result in vacuum

formation inside unit equipment; most of which may not be designed for such full

vacuum or part vacuum conditions.

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I. Steam in system is cut-off slowly and fuel gas is backed in. cutting off steam

results in condensation of steam inside unit equipment due to heat loss from bare

piping and equipment surface. Fuel gas can be backed from separate headers into

atmospheric column, stabilizer. It is advisable to back in fuel gas section wise.

This helps in better monitoring of operation and excessive withdrawal of fuel gas

from FG pool. Adjust gas-backing rate in such a way that fuel gas system is not

disturbed resulting in low fuel gas pressure due to excessive withdrawal during

this operation. Pressure surges during fuel gas backing-up should be avoided.

Ensure that all vents are closed and properly capped / blinded before FG back up.

II. Open the low point drain one by one and drain out condensate completely. Check

list to be prepared to ensure that all drains are made free of condensate. A log

should be kept for drain check showing the time of check, absence of condensate

and initials of the person who made the final check on the drain. Each drain must

be closed and capped / blinded as soon as gas issues form it.

III. Build up pressure in the columns @ 0.5 Kg/Cm2

IV. Back-up gas from column to all the product run down lines through internal and

circulating reflux lines from the column.

V. Drain out water from the following points:

a. Preheat exchangers

b. Transfer line

c. Pump around and reflux lines

d. All product circuits up to battery limit

e. All pumps

f. All exchangers and coolers

VI. Repeat draining operation every half an hour till no more condensate is drained.

Maintain the whole system at 0.5 Kg/cm2g fuel gas pressure. Ensure all vents are

closed and capped off. Shut all drain points and cap off.

VII. After all the sections have been floated on fuel gas, water is drained from low

point drains. Positive pressure in the system will facilitate draining residual water.

VIII. Air from all the hydrocarbon system must be removed thoroughly before

proceeding for fuel gas back up.

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IX. Before backing in fuel gas into the system, flare header inside the unit should be

charged and flare should be activated. Fuel gas purge to flare header should be

established. Fuel gas into furnace fuel piping should be charged at this stage only

if proper monitoring is available. Cooling water circulation is started through all

coolers and condensers.

X. Removal of water from the system is an important step for smooth start-up.

XI. Before admitting fuel gas into the system, all vents and drains in hydrocarbon

service will be closed. Steam entering the system is throttled slowly. Furnace fire

are cut off. Cooling water is commissioned to the overhead condensers and

coolers and air coolers started. During gas backing ensure that vacuum is not

formed in the system due to condensation of steam.

XII. As the system cools, condensate will accumulate. The drain at each low point is

opened and the condensate is drained. Never leave open drains unattended. Each

drain, which is opened and checked, should be listed in the start-up procedure. A

log should be kept for the draining activities showing time of check and absence

of condensate. Each drain must be closed as soon as gas issue out from it. When

the draining is complete the system is ready to take crude oil.

Major steps for fuel gas backing into the systems are as under:

i) Reduce steam to the various points in all the columns,

furnace coils & at points receiving steam through

temporary hoses. Close all drains and vents except any

one vent at a convenient point to approach and operate

for venting steam to maintain system pressure.

ii) Close all the vents one by one. Adjust steam inlet rate to

maintain system pressure about 0.5 Kg/cm2g cap off all

vents properly to avoid leakage of gas through these

points. Throttle the drain valves to allow only condensate

to flow to keep the system hot. Keep watch on the system

pressure. Adjust steam inlet if necessary.

iii) Commission flare header and flare header should now be

lined up to various equipment.

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iv) Open any of the pressure control valves at FG lines on

atmospheric column reflux drum, stabilize reflux drum, in

normal mode to admit fuel gas into the system. Excess

FG pressure may be released to flare as and when

required by operating the control valve to flare. Close the

vent valve which was kept open to a convenient point as

selected and described at point (I) above to maintain

system pressure and let out non condensable.

v) Maintain the pressure in the system around 0.5/1.0

Kg/cm2g.

5.3.5 COLD CIRCULATION

The purpose of cold circulation is further water removal from piping network and bottom

of equipment, which could not be removed during water draining. Cold oil carries liquid

water into low points of the circuit. During circulation drain at low points (preferably

from desalter and column bottom pump) must be opened frequently to ensure that no

more free water is drained. The circulation rate must be sufficiently high to sweep the

water and not merely flow over it. All plugged drains must be cleared for draining during

circulation. While draining water, unnecessary loss of oil to OWS should be avoided for

reasons of safety and economy. Normally one hour of settling time is allowed after every

four hours of circulation. Settling time may be reduced progressively at advanced stages

of cold circulation. Cold oil circulation gives further opportunity of trying out various

pumps and control systems prior to going up on temp. in sequence of start up. All

instruments should be commissioned during cold crude oil circulation. It should be

ensured that flow rate during cold circulation remains well above minimum continuous

flow through various pumps involved, as suggested by pump vendors. Similarly flow

through control valve should be maintained above minimum flow stipulated in control

valve data sheets to avoid possible chattering.

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5.3.5.1 Crude Distillation Unit

For atmospheric crude distillation unit, crude oil is used for cold oil circulation. Crude

oil flow in the equipment and piping carries away free water with it from crude as

elaborated ahead. Water carried away by crude can be separated from crude in crude

tank.

Following major points may be followed for cold circulation in the CDU section:

(a) Receiving crude in the Unit

Crude tank that will feed the unit will be prepared in advance by through draining of

water. Sample will be analyzed and dips will be taken. It will then be lined up to the unit.

i) Open suction & discharge valves of off sites crude

transfer pumps and crude charge pumps

05-PA-001A/B/C/D/E.

ii) Slowly charge crude from the crude tanks.

iii) Crude will begin to flow under gravity into the line and

displace gas. This gas is vented out from the crude pump

vents and other high point vents of piping in off sites

between crude tank outlet & crude pump suction.

iv) In subsequent start-ups this operation may not be

required, as offsite crude line up to the battery limit will

always remain full.

v) Make sure that electrical supply to desalter is cut off.

Open the discharge valve of crude charge pump and

allow the crude to flow to the desalter.

vi) Alternatively, desalter can be kept filled with gas and oil

by passed. Desalter shall be commissioned separately.

vii) Fill the circuit up to crude charge heater via crude preheat

trains and desalted crude pumps. Vent the trapped gas

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from each of the crude preheat exchangers through hose

connected to the vents on the heat exchangers.

viii) When flow of crude oil in off sites piping is no longer

possible under gravity, start off site crude transfer pump,

crude charge pump and then the desalted crude pump.

Continue charging crude oil at a slow rate to atmospheric

column bottom via atmospheric heater.

ix) Regulate the crude flow through heater coil in such a way

that crude flow to unit. Also divide the flow equally

through all crude pre heat exchanger trains by operating

respective FV & HV.

x) Release displace fuel gas into the flare from atmospheric

column reflux drum, and do not exceed column pressure

beyond 1.0 Kg/cm2g. Operation all the pumps above their

respective minimum continuous flows is essential.

xi) If desalter is included in circulation, care fully operate

desalter (second stage) pressure controller PIC-1206 on

manual and build up a pressure of 8 to 9 Kg/cm2g in the

second stage desalter outlet line.

(b) Establishing Cold Circulation

Once level in the crude column has been built up, establish cold circulation as per the

lineup given below.

Crude Tank --->Crude Booster Pump in Offsite ---- Crude Pump in Unit PA-01 -->

Crude Preheat Train Circuit Before Desalter (including both New and Old Preheat Train)

----> Desalter ----> Crude Preheat Train Circuit After Desalter (including both New and

Old Preheat Train) -----> Furnace -----> Column -----> Column Bottom Pump PA-

51RCO R/D circuit Crude Pump suction

i. Stabilize the second stage desalter pressure at around 9.5-11.5

Kg/cm2g and put PIC-1206 on auto. Observe the performance of

all control valves in the circuit. Crude oil will gradually displace

fuel gas and build up level in crude column. Crude oil passes

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through crude preheat train I, desalter, crude preheat train II,

atmospheric furnaces and then to atmospheric column bottom.

ii) Long Residue pumps take suction from material

accumulated in atmospheric column bottom. When

sufficient level is built up in the column bottom open

suction and discharge valves of LR pumps. Fill up all the

LR circuit exchangers by crude with gravity displacing

the trapped gas from each of the LR exchangers through

hose connected to the vents on the heat exchangers.

iii) Line up LR rundown circuit up to R/D Control valve.

Keeping battery limit side valve closed, line up for

circulation (To P01 pump suction line). Start LR pump,

circulation should be continued for at least 6-8 hours to

displace free water. Ensure that there is no flow of crude

oil to LR storage.

iv) Keep watch on crude column level and maintain it around

50% by adjusting the LR pump discharge flow rate.

Crude stream flow can be controlled by manipulating

flow and level control valves falling on presently selected

crude circulating circuit.

v) Maintain crude column top pressure between 0.5 to 1.0

Kg/cm2g during cold circulation. By operating PIC-1504

(05-CC-001 top pressure controller) acting on incoming

FG line to reflux drum and outgoing flare line from reflux

drum, column top pressure can be maintained to desired

valve. Displaced FG will be released to flare form reflux

drum.

vi) Desalter and few heat exchangers can be bypasses during

initial commissioning.

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vii) Active exchanger by passes & control valve by passes

also to displace free water trapped in these sections.

viii) After establishing and maintaining cold crude oil

circulation for 4-6 hrs. Stop all pumps in circulation

service and allow settling for 2-4 hours. Carry out water

draining from all the low points in the system including

column and exchangers. Restart cold crude circulation.

Repeat the operation till all the free water in the system is

removed. This operation of circulation, stopping, settling

and draining will be repeated till no further water

separates out. A check of water content of circulating

crude oil is useful information.

5.3.6 HOT CIRCULATION

Line up CDU for the hot circulation as per the following.

5.3.6.1 Atmospheric Section

CDU commissioning can be accomplished by completing following steps once cold

circulation has been established and units are ready for hot circulation.

Firing the Heater

Raising Temperature to 120 C

Raising Temperature to 250 C

Raising Temperature to normal COT

Commissioning of Desalter

(a) Firing the Heater

When the cold circulation has been well established and water in the atmospheric system

has been thoroughly drained out, 05-FF-001 firing will be done as per recommended

procedure spelt out in heater operating manual

Following to be ensured again which pertains primarily to commissioning of utilities and

proper lining up of unit before firing the header:

i) Cooling water flow is established in all product coolers. Cooling

water flow to overhead condensers should be done gradually to

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avoid sudden condensation of fuel gas leading to subsequent

depressurization of column/strippers etc. Fuel gas purge to be

augmented if required.

ii) Tracing steam is commissioned. Before warming up the stand-by

pump of any hot service through the 3/4” warm-up line across

NRV of stand-by pump, it is to be ensured that suction valve of

stand by pump is kept crack open or fully open. This is to avoid

pressurization of the pump and its suction line to the discharge

pressure of running pump. This operation ensures flow of hot fluid

back to pump suction, thus attaining good warm-up of pump body.

iii) Set level controllers of HN, Kerosene, GO strippers in auto mode.

Check that level control valves remain open, as there is no level in

the strippers.

iv) All safety valve isolation is kept lock opened. Spare to be kept

isolated as per P & ID stipulations.

v) Charge atomizing steam header to the heater. Commission fuel oil

supply and return lines and establish FO circulation.

vi) All safety interlocks/trips on combustion air circuits, heater pass

flow and heater body should be made operation. However, few

selective trips may be bypassed appropriately for short duration

only to achieve steady operating condition. The bypassed trips

should again be taken inline at earlier opportunity. Proper

recording and communication should b e maintained regarding

bypassed or in effective trips.

vii) Exchangers subjected to hot crude shall have TSV protection; it is

better to keep isolation valves on other heating media open to

allow thermal relief to liquid still not in operation.

(b) Raising Temperature to 120 C

i) Fire the pilot burners of atmospheric heater one by one as

per heater start up procedure. After warming up the

heater, main FO or FG burners can be lit up. The rate of

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increase of transfer line temperature will be restricted to

30 C per hour. When the transfer line temperature reaches

120 C at heater outlet hold firing rate to maintain this

temperature for four hours. At this COT, column bottom

temperature shall be around 90-100 C.

ii) Bring down column pressure to 0.5 Kg/cm2g or less to

facilitate water removal as steam hydrocarbon vapor

mixture from the column overhead. Keep watch on

column pressure. The excess pressure will be released to

flare. Higher column pressure may interface with

evaporation of hydrocarbons and water vapor. Monitor all

flow, temp. and pressure readings of atmospheric column

and heater.

iii) While raising the temp. it will be observed that crude

passing through preheat train I, II is gaining heat from the

LR. Check for presence of water in product and

circulating pumps suction and drain out according to

requirement.

iv) Watch performance of LR pump as its performance may

become unsteady initially with rise in crude oil temp.

v) Maintain crude column level by matching LR pump

discharge rate with crude in take to the unit crude flow to

be maintained at about 50% to 60% of normal through

put.

vi) At the end of four hours, carry out test for water content

in circulating crude oil. Water content equal to or less

than that of tank sample is indication of good water

removal. A value of about 0.2% wt. of water content is

often obtained at this stage of hot circulation & is

acceptable.

133

c) Raising Temperature to 250° C

i) Purpose of raising the temp. to 250° C and holding at this value is to

try out all equipment, instruments and controls in actually hot service

and rectify the faults if any. After holding the temp. at 120° C for four

hours, transfer temp. will be further raised at a rate of 30° C/hr to 150°

C and held at this temp. for four hours with column top pressure held

at 0.5 Kg/cm2g. Most of water in circulating crude shall be evaporated

during this period. Then raise COT to 250° C at a rate of 30° C/hr.

ii) Closely watch all instrument reading and check their performance. Re-

calibration of few of the instruments may be necessary.

iii) Hold crude column at about 50% bottom level. Vary LR pump

discharge rate if necessary to maintain bottom level.

iv) Top temp. of the column will rise gradually. When it reaches more

than 100 C steam in the atmospheric column will not condensate and

will escape from column top. It will finally condensate in the column

overhead condensers and accumulate in reflux drum.

v) When level appears in the reflux drum check for presence of water and

drain it out. Local check for levels must be made.

vi) As top temp. Rises further, slowly raise column pressure a little at a

time to its normal valve of 1.5/2.14 Kg/cm2g. After steadying out

column top pressure, put pressure controller PIC-1504 on auto to

maintain this pressure. Higher pressure will help in condensation of

vapor that would otherwise escape to flare. Increase of column top

pressure will result in increase of top temp. due to increase in boiling

point and dew point temp. of the vapors, provided all other parameters

are constant.

vii) Check for appearance of oil level in atmospheric column reflux drum.

Start total top refluxing when oil level builds up. Watch water and oil

levels in column reflux drum. Commission water and oil level

controller LIC-1602 and LIC-1606 and put them on auto to hold about

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50% level in vessel and boot respectively. Watch performance of these

instruments closely.

viii) Care is to be taken so that water does not go in the top reflux stream.

Refluxing will be started at a small rate.

ix) Start hot bolting in the transfer line, LR circuit, column bottom

manhole and other flanges in hot service which were disturbed during

S/D where normal operating temp. exceeds 200 C.

x) Cap off all drains securely that were used to drain water.

(d) Raising Temperature to 300° C/Normal COT

i. When hot bolting of the portion where temp. reaches to 200° C is

over, start raising the transfer temp. at 30° C/hr and continue hot

bolting in other areas where temp. touches 200° C. Hold the

column bottom temp. around 280° C till hot bolting in all the

flanges is over.

ii) Regulate top refluxing to maintain a column top temp. at 110° C.

When naphtha make increases as indicated by rising oil level in

reflux drum, route this product to slop till stabilizer column is

commissioned.

iii) See column top temp. and pressure reaches its normal value, line

up all circulating reflux circuit, starting from HN to GO CR in

descending order. Ensure that there is no water in any of

circulating reflux circuits by draining. Start refluxing at minimum

flow rate after draining water from pump drain. This operation

shall gradually stream line temp. profile in the column.

iv) When level appears in inside strippers, drain water from respective

pump suction and line up product pump discharge (HN, Kerosene,

GO) to slop header. Heating medium (GO CR) to stabilizer re-

boiler 05-EE-014 should not be commissioned. When sufficient

level is built up in the side strippers (about 40%) start withdrawing

off spec. products to slop header through respective product

coolers, which is ultimately lined up to crude storage tank. When

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flows stabilize, all level control loops in HN, Kerosene, GO (LIC-

1506/1508/1510) CR’s can be put on auto.

v) At the time of commissioning circulating reflux flows, hot media

will be flowing through the heat exchangers of crude preheat train

I, II This will necessitate the flow adjustment of crude flow

through preheat trains I, II to bring parity between outlet temp. of

both the sections of same train.

vi) Activate atmospheric column bottom stripping steam header by

draining condensate from drain points provided.

vii) 100 % compliance to ensure condensate is properly

drained from the stripping steam headers.

viii) When crude column bottom temp reaches 300° C admit stripping

steam, about 250 Kg/hr in each step and bring unit out of

circulation.

ix) With the introduction of stripping steam, amount of vapor flowing

to the upper section will go up. Adjust cooling water to overhead

condenser to maintain reflux temp. at about 45° C. Introduction of

stripping steam at crude column bottom will establish proper mass

transfer profile. Sour water circuit from reflux drum needs to be

rechecked for its heating at this point of time. Steam to product

strippers can also be introduced.

x) LR should be finally cooled in 05-EE-021 & 05-EE-022A/B/C/D

before sending to storage. Divert all other side products to slop

tank through the slop header.

xi) Watch column top pressure and temp. read just circulating refluxes

and top reflux if necessary. Raise the circulating reflux by

adjusting to 60-70% of its normal flow rate. Adjust return temp. of

top reflux, top CR, kerosene CR, GO CR at 40,94/95,140.6/138.4

and 71.1/170.7 C respectively by manipulating respective

exchanger by pass valves. Various duty controllers should not be

136

put in operation till steady state operating conditions are

established.

xii) Start adjusting withdrawal rate of HN, Kerosene/ATF, GO by

regulating FIC-1507, FIC-1508, FIC-1509 for maintain proper

draw off temp. of HN, Kerosene and GO respectively.

xiii) When the coil outlet temp. reaches its normal value 375 C, put

TIC-1416 on auto/cascade with fuel oil / gas firing controller and

make all operating conditions steady. Commission hot medium to

HN stripper re-boiler. Normalize stripping steam flow to

Kero/ATF and GO stripper. Ensure that condensate is already

drained before allowing steam flow to the strippers.

xiv) The HN liquid is stripped off its lighter by GO product stream as

re-boiling medium and its flow is regulated by FIC-1507.

xv) Adjust cooling water, if necessary to all product coolers to

maintain run-down temp. of HN, Kerosene, GO at around 40 C.

Care should be taken to ensure that combined slop temp. ex CDU

does not exceed 60C while leaving the unit or else it can lead to

boil over in crude tank.

5.3.7 COMMISSIONING OF DESALTERS

Desalter can be brought into service at this stage. Stabilize desalter pressure at about 9.5-

11.5 Kg/cm2g by PIC-1206. Control the desalter temp. at about 130 C by adjusting the all

hot medium streams passing through preheat train I. Variation in Hy. Naphtha CR,

Kero/ATF CR GO temp. Due to above adjustments by way of operation of exchanger

bypass will be taken care of by respective product coolers.

i) Check oil water interface level through the try lines and

check for any presence of vapour

ii) Switch on the power supply to desalters. Voltmeters and

ammeters should indicate high voltage and low amperage

respectively.

137

iii) Line up service water/stripped water injection at desalter

inlet and start injection at about 4% (by volume) of crude

throughput or as per specification of desalter vendor.

Also line up effluent water circuit.

iv) Start caustic injection pumps and inject caustic solution

into the crude fed to CDU, to maintain a pH of about 7 in

the effluent brine from the desalters.

v) Start Demulsifier injection pump and inject Demulsifier

at crude feed to CDU at the rate of about 1.5 to 2 ppm on

crude charge. The rate of injection to be

confirmed/readjusted based on actual operating data.

vi) Commission desalter level controllers ILIC-1201 and

ILIC-1202 and route desalter water to effluent treatment

plant via brine coolers.

vii) Take samples of crude before and after desalter for

getting following performance:

a) Salt content as NaCl at the outlet should be <0.5 ptb of

salt content of raw crude whichever is greater.

b) The insoluble water content in desalted crude should

be less than 0.2% (max) by volume and the effluent

brine should have oil content less than 200 ppm.

5.3.8 NORMALIZATION OF OPERATING CONDITIONS

At this stage normal operating conditions are established for atmospheric section at turn

down capacity of normal throughput of the plant. All products are routed to their

respective storage tanks/down stream plants.

Feed rate of the plant is to be raised to its normal capacity in steps as outlined below.

i) When the atmospheric heater transfer line temp. of 375 C

has been attained maintain this temp. and make further

adjustments. Adjust heater firing to maintain 375 C at

heater outlet at turn down operating conditions.

138

ii) Increase stripping steam to side stream by adjusting

individuals FICs to achieve designed ratio of steam to

hydrocarbons. Make adjustment in the stripping steam

flow to the atmospheric column bottom also.

iii) Adjust draw off flows of HN, Kerosene and GO to

maintain respective draw off temperatures. Raise

circulating refluxes proportionately to maintain column

temp. profile.

iv) When conditions have become steady take all remaining

controls on auto one by one. Particular care should be

taken in case of heater control. Safety shutdown system

for low fuel gas pressure (which was on bypass initially)

should be made operative.

v) Make adjustment on operating parameters to bring the

products on spec. check samples of all products. Check

for normal product run down temp.

vi) When products are on spec. rout them to respective tank

own stream units as per agreed routings with off sites

section. These routings should be recoded meticulously

and should be known to unit operators. If any product

goes off spec. divert it to slop tank (except LPG) and

make adjustments as detailed under operating variables to

bring the product to specification.

vii) Raise the throughput further only when all products are

on spec. raise the throughput in steps in accordance with

the procedure outlined. Establish steady operating

conditions in each step. Increase the throughput to normal

rate, as per requirement and maintain the parameters as

given in the section. Steady out transfer temp. of

atmospheric furnace at 375 C check all furnace controls

139

for proper functioning raise the feed to atmospheric

furnaces by 25 M3/hr.

viii) Check local temp. pressure , flow and level of different

equipment and streams please keep watch on running

equipment such as pumps, heaters and other equipment .

Look for leaks, hot spot and any other abnormalities.

ix) Record and analyses two hourly log readings and report

any abnormal conditions to the next higher decision-

making supervisor immediately.

5.3.9 BRINGING UP NAPHTHA STABILISER SYSTEM

Commission PIC-1701 (stabilizer top pressure) on auto, with set point at about 9

Kg/cm2g. PIC-1701 being controller with characteristics so selected that initially the

control valve PV-1701 will remain full closed. If pressure increase still persists, PV-1701

shall also start opening and go to full open condition to relieve maximum fuel gas from

stabilizer reflux drum.

i) Start admitting naphtha form crude column reflux drum into

Naphtha Stabilizer bottom with the help of stabilizer feed pumps.

Build up about 75% level in stabilizer bottom through FIC-1701. It

can be cascaded with LIC-1606 (reflux drum level controller) once

steady operating conditions are achieved in stabilizer section.

ii) To commission stabilizer re-boiler divert some quantity of GO CR

slowly to raise the temp. gradually at the rate of 10-150 C/hr

through stabilizer re-boiler 05-EE-014 by adjusting FV-1704 this

shall increase stabilizer bottom temp. gradually. Do not exceed rise

in temp. beyond 20 C/hr.

iii) Stabilizer pressure will tend to rise as the bottom stream gets

heated by GO CR. When normal stabilizer pressure (8/12 Kg/cm2g

at PIC-1701) is reached, normal working of the column will be

established. During the process of heating up, stabilizer bottom

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level will fall if rate of heating is too fast. Necessary make up

should be done through FIC-1701.

iv) Raise gradually stabilizer trey temp. by adjusting TIC-1703/FIC-

1704. When tray temp. stabilizes at around 170 C put TIC-1703 on

auto. Sudden increase of temp. and pressure will destabilize the

column making heavy fraction to go to the top, requiring longer

time to stabilize. So increase or decrease of temp. or pressure of

stabilizer shall be done gradually.

v) When level appears in stabilizer reflux drum, drain water from

boot and stabilizer reflux/LPG pump’s suction. Start total refluxing

to the column keeping FIC-1703 on manual control. Maintain top

temp. at about 85 C.(Top Temperature to be maintained depending

on LPG weathering).Start diverting LPG when there is excess

accumulation in reflux drum to caustic wash system.

vi) Divert stabilizer column bottom to storage/slops via stabilizer

feed/stabilizer bottom exchanger, Naphtha stabilizer cooler. Till

caustic and water circulation is established properly, Naphtha

stream from stabilizer bottom remains routed to slop or other

destinations bypassing the wash facilities.

vii) Slowly divert naphtha to caustic wash and water wash vessels.

Complete filling of the vessel, without leave in any vapor space,

shall be indicated by LI-2004B followed by sharp rise in pressure.

Care should be taken to avoid popping of the PSV on the vessel.

Receive 10% solution caustic & water up to 25 to 30 % level in

respective wash vessel.. Quantity of caustic make up in the vessel

should be verified with flow indication FI-2001B on make up line.

viii) Caustic circulation in the vessel is established by operating caustic

circulation pumps 05-PA-019A/B through FI-2001B. HV-2001 at

vessel inlet should be kept to full open position by operating HIC-

2001.

141

ix) Similarly water circulation is established in water wash vessel 05-

VV-010.

x) Naphtha stream from light naphtha cooler is routed to 05-VV-009

and 05-VV-010 by operating HIC-2001/HIC-2002. Specifications

of outgoing naphtha should be compared with specified stream

properties to establish efficiency of washing.

xi) When caustic strength goes down to less than 1% spent caustic

should be drained to spent caustic drum VV-16 and fresh caustic

should be made up.

xii) Water from water wash vessel shall also be drained to spent caustic

drum VV-16. However draining of wash water to this vessel shall

be indicated in inter-phase level LI-2008B on the water wash

vessel. Quantity of water drained should be made up by running

water make up pumps 05-PA-040A/B. Streams collected in the

degasser vessel after degassing shall be sent to ETP by spent

caustic pumps 05-PA-043A/B.

5.4 STEPS INVOLVED IN START UP FROM BOTTLED UP CONDITION

1. Inform RSM/OMS/TPS & other units about start up.

2. Check & line up for close crude circulation

PA-01 5HC5001 EE-01 EE-02 EE-03 EE-04EE-05Desalter

EE-103A/B/C

5HC5002 --EE-102A/B Desalter

EE-104A/B

DesalterPA-025HC5005EE-06A/BEE-07A/B/CEE-08A/BEE-

09A/BEE10A/B/C/DFF-01CC-01

142

PA-025HC5006 EE-105A/B/C/D EE-108A/B FF-01CC-01

EE-106A/B/C/D EE-107A/B/C/D

PA-51 EE-10 A/B/C/D EE-07A/B/C EE-04 EE-21

PA-51EE-107A/B/C/DEE-105A/B/C/D/EEE-103A/B/C E111A/B

New & Old joins together FC1805 hot RCO R/D

E22A/B/C/D FC1806 cold LR R/D

Unit circulation

3. Establish circulation & maintain crude flow @ 6000mt/day

4. Maintain desalter pressure 8 – 9 kg/cm2 by operating PC 1206

5. Prepare/ top up chemical solution (NaOH, Ahuralan, Demulsifier, Ammonia)

6. Check & isolate all FO/FG/Pilot burner valve.

7. Establish IFO circulation.

8. Take low pass flow inter lock in line.

9. Check for any leak / abnormality in plant, fix it.

10. Deblind FG.

11. Fully open STD.

12. Purge heater box with steam & bring negative draft inside.

13. Start FD fan.

14. Light all pilot burner one by one. If the first one does not light in first shot, isolate

gas & purge box with steam again.

15. light gas & FO burner as per requirement & raise COT @ 40 0C/hr.

16. Raise temp. to 1200C. Hold for 2 hrs to strip off water to over head reflux drum.

17. Raise temperature to 2500C.

18. With the increase of temperature column top pressure will increase. Maintain top

pressure 1.5/2.14 Kg/cm2g by PIC-1504.

19. Switch on desalter, Drain out accumulated water fro desalter.

20. Adjust RCO cooler O/L temp to 50-600C

21. When level builds up in V02, Drain water & start reflux pump.

143

22. Maintain top temperature.

23. Check & get hot bolting done the leaky/smoky flanges.

24. Raise temperature to get 3000C C01 bottom.

25. Drain condensate & introduce stripping steam to C01/C03/C04.

26. Bring unit out of circulation by routing RCO to R/D. Adjust RCO cooler to get

required R/D temperature.

27. Rout V02 sour water to SRU.

28. Start CR pumps when level appears in stripper & adjust column condition.

29. Start product pump & rout initially to off spec. tank. Adjust draw temperature.

30. Diver V2 gasoline to stabilizer.

31. Introduce slowly heat to Stabilizer & HN stripper Reboiler.

32. Adjust column condition.

33. Commission Amine wash system.

34. Commission LPG / Naphtha & SKO naphtha caustic wash system.

35. Rout LPG through amine & caustic wash system to Horton sphere.

36. Rout LN / SKO through caustic wash system.

37. Send product sample to laboratory. When certified rout to on grade R/D tank.

38. Take all inter locks in line.

39. Slowly increase T’Put as per requirement.

40. Start Stripped sour water injection to desalter.

41. Start all chemical injection. Maintain PH

42. Start ID fan. When it’s suction exceeds 1600C, close STD as required.

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5.5 CHECK LIST FOR UNIT NORMAL START UP FROM BOTTLED UP

CONDITION

Sl.No Description Action by DoneYES/NO

Remarks

1 InformRSM/OMS/TPS/Water Block/Laboratory about Start up

S/I

2 Check & rectify all furnace igniter Field Opr3 Check & commission all utilities, if

decommissioned.Panel/Field

Opr.4 Check all FG and FO burner valves. These

should tight shut.Field Opr

5 Bypass IFO low pressure inter lock & establish IFO circulation through furnace by opening IFO C/V & return BPC.Adjust to obtain IFO required temperature.

Panel/Field Opr

6 Establish IFO circulation, first with RCO then switch over to VR.

Panel/Field Opr

7 Prepare / top up chemical solution Ahuralan Ammonia Ammonical caustic Demulsifier

Field Opr

8 Check all motors for power supply Pump/Field Opr.

9. Establish cold circulation with BH/NIG crude at 50% T’put

Panel/Field Opr

10. Purge F01 with steam for 20 minutes. Check / confirm about negative draft inside furnace

Panel/Field Opr.

11 Deblind furnace FG line. S/I12 Stop purging steam & start FD fan Panel/Field

Opr13 Light up all pilot burners with the help of

igniterField Opr

14 Bypass low FG pressure inter lock & Light gas burner & heat up to 120 deg C @ 30 to 40 deg C / Hrs

Panel/Field Opr.

15 Switch on desalter Field Opr16 Take low pass flow inter lock in line Panel Opr.17 Drain water from all stagnant line LPDs. Field Opr18 Have a round in the unit to check for any

leakage & fix it, if any.S/I/Field

Opr.19 Raise temperature to 250 deg C @ 40 deg

C/Hrs. Panel/ Field

Opr

145


Remarks

20 Get hot bolting done on Smoky / Leaky flanges, if any

S/I

21 Maintain RCO cooler O/L temp. @ 50 – 600

CPanel/Field

Opr.22 Take oil burner in line as per requirement Field Opr.23 Raise Coil Outlet Temp. to 300 deg C @ 400

C /hrsPanel/Field

Opr.24 Introduce stripping steam & take the unit out

of circulationPanel/Field

Opr.25 Raise COT, as per requirement to normalize

the unit.Panel/Field

Opr.26 Flush circulation line Field Opr.27 Start Chemical injection Field Opr.28 Start DM water injection to desalter and

demulsifier dosing IField Opr.

29 When level build up in V2 Drain water completely.

Pump/Field Opr.

30 Start sour water pump. Divert it to SRU. Commission inter-phase level controller

Pump/Field Opr

31 Start reflux pump / Maintain top temperature Pump/Panel Opr

32 Start product & CR pump when level appears in stripper

Pump Opr

33 Establish column condition Panel Opr.34 inform to GRE S/I and route all products to

off grade tank to GRE Slop tanksS/I/

Field Opr.35 Divert V2 gasoline to C5. Build up level in

C5. Introduce Heating media to bottom reboiler & bring up slowly bottom temperature up to required one. Adjust Stabilizer operating condition.

Panel/Pump Opr.

36 When level builds up in V03, drain out water completely.

Field Opr.

37 Start reflux pump & establish stabilizer condition

Pump/Panel Opr

38 Commission LPG caustic wash system & route LPG to Horton sphere.

Panel /Field /Pump

Opr.

39 Commission Naptha caustic wash system & route Naptha to R/D ( GN tank)

Panel /Field /Pump

Opr.

146

40 Commission Amine ( C6) system, co-coordinating with SRU shift In charge.

S/I/Panel/Field Opr.

41 Start ID fan & bring furnace on balanced draft mode.

Panel /Field Opr.

42 Adjust T’Put as per requirement Panel Opr.43 Sent all product samples to Laboratory. If

certified, route as per RSMPanel/Pump

Opr.44 Take all inter locks in line Panel Opr.

147

CHAPTER-6

NORMAL SHUTDOWN PROCEDURE

NORMAL SHUT DOWN PROCEDURE

148

NORMAL SHUTDOWN PROCEDURE

6.1 GENERAL

In this section, procedure for planned shut down is discussed. While shutting down all

process units simultaneously or any section of the process unit, care should be taken not

to admit air into the system until all hydrocarbon vapors have been removed.

It is important that process unit operates involved in shut down understand the purpose

and effect of each activity. In particular, operators should make sure that their actions will

not result in creation of hazardous conditions either because actions taken were wrong or

these were taken at wrong time.

Rate of temperature drop in process unit equipment should not be very sharp to induce

thermal stresses in piping and equipment. All related process units, utilities and of sites

should be kept informed well in advance about the shut down plan. It is to be ensured that

a slop tank and one crude tank having sufficient space is available to receive the slops/off

spec material. Closed blow down drum should be emptied out and should be kept ready

to receive hydrocarbons draining/flushing from equipment. Flushing oil should be made

available in adequate quantity and adequate pressure. Adequate ullage should be ensured

in off sites slop tank.

6.2 BRIEF SHUT DOWN PROCEDURE

The throughout to CDU will be gradually reduced to about 50% of normal capacity or

turn down capacity of the unit and all other flow rates shall be reduced on pro data basis

wherever applicable to be suitable for operation of the unit on reduced capacity.

149

Necessary adjustment will be done in reflux rates withdrawal rates in all the sections of

the unit to keep the product on specification.

Number of burners will be reduced in the CDU, furnaces if necessary. Chemical injection

will be discontinued.

Adjustment will be done in stabilizer column operation to stop production of LPG, which

will be released to fuel gas system. All caustic wash sections will be bypassed. Desalter

will be taken out of service.

COT of atmospheric section will be gradually reduced to 300 C . Divert product to slop

when they become off spec. Cut off column bottom stripping steam. Re-circulate LR

along with other product through slop header. Back up FG when pressure tends to

become low. Cut off fire in atmospheric heater and allow to cool down while on

circulation. When system is sufficiently cooled, empty out all equipment to slop. Flush

out fuel oil system.

Steam out columns exchangers etc. to remove hydrocarbon vapours etc. if opening of the

equipment in hydrocarbon service is planned.

6.3 DETAILED SHUT DOWN PROCEDURE

The procedure indicated below will ensure a safe and smooth shut down of the units but

is not mandatory.

Plan chemical solution preparation in advance so that very little solution is drained after

unit is shut down for M&I.

The important steps in the shutdown procedure are summarized as below:

Reduction of feed rate to all units.

Discontinue chemical Injection

Shutdown stabilizer

Decommissioning of desalters

Putting the CDU on circulation

Shut down atmospheric section

Emptying out of the units and purging/isolation

All above steps are elaborated below:-

6.3.1 THROUGHPUT REDUCTION

150

Reduce crude throughout gradually to 50% of normal feed rate step by step. Manipulate

all atmospheric heater pass flow controllers for this purpose, bypass low pass flow / low

FO / FG pressure inter lock.

Make adjustment on all operating variables in each step so that normal operating pressure

and temp. conditions are maintained.

6.3.2 DISCONTINUATION OF CHEMICAL INJECTION

Stop caustic injection pumps 05-PA-031A/B and isolate the following:

caustic injection to desalted crude

caustic injection to crude inlet line to CDU from storage.

Stop Demulsifier injection pump 05-PA-027A/B and isolate the valve near crude

inlet to CDU from storage.

Stop ammonia solution injection and isolate the following injection lines: •

Ammonia solution injection to crude column overhead vapour lines.

Stop corrosion inhibitor injection after stopping the ammonia injection.

Isolate the vessels including cylinders and drums, which contain chemicals.

Depressurize and drain pumps and lines including calibration pots.

6.3.3 SHUTDOWN OF NAPHTHA STABILISER

Control system of stabilizer column shall be changed from total condensation to partial

condensation operation. LPG down stream unit will be informed about discontinuing

LPG production.

Inform DHDS and LAB to stop wild naphtha to AU5 unit. Also inform CRU to stop drag

stream to AU5.

Reduce feed to stabilizer. De-cascade atmospheric column reflux drum level controller

from stabilizer feed flow controller. LPG-to-LPG vaporizer should remain isolated at

HIC-1901 and to Amine regeneration unit.

De-cascade stabilizer column top temp. controller TIC-1703 from reflux flow controller

FIC-1703. increase top reflux to stabilizer and cut off LPG withdrawal from reflux drum.

De-cascade stabilizer reflux drum level controller LIC-1704 from LPG product flow

151

controller FIC-2503. Bring the column to total reflux operation, by maintaining pressure

such that only sufficient vapor condenses to maintain reflux flow.

Reduce the column top pressure very gradually by operating PIC-1701. Care must be

taken to reduce the pressure very slowly to avoid lifting of heavy ends to the top and

sudden release of heavy components to fuel gas system, which may condense afterwards

in FG system.

Reducing heating medium flow (GO CR) to stabilizer re-boiler. Operate TIC-1704 first to

lower the temp. Throttling of FV-1704 by manual mode can be done for this operation.

Pump out stabilizer top reflux drum liquid to stabilizer till reflux pump looses suction.

Keep receiving feed to stabilizer till atmospheric column starts operating on total reflux

in source of shut down and then cut off feed to the stabilizer. Close the isolation valve in

the stabilizer feed line.

By utilizing the available pressure, empty out the stabilizer bottom to slops storage tank

and maintain stabilizer bottom level. Keep a watch on rundown stream, as it may contain

lighter components, which may create problem in slop tank.

To facilitate emptying out, top pressure control valve of the column may be closed.

Heating up bottom contents can also be done if necessary to build up pressure for this

purpose. Care must be exercised to prevent gas break through from stabilizer column to

storage tank due to sudden loss of level in stabilizer bottom while emptying out.

Bypassing the caustic wash system should be done prior to shut down of the system. As

soon as caustic wash system is bypassed both the caustic circulation pump and water

circulation pump to be stopped.

Reduction in stabilizer column pressure, naphtha flow and stabilizer bottom level will

all indicate completion of the emptying out of the column. After emptying out, isolate the

column by shutting off valve on the inlet and outlet streams and then depressurize slowly

by releasing to flare through depressurizing valve.

After depressurizing, residual liquid in column, piping exchanger will be drained to CBD

or OWS. LPG should not be drained to CBD or OWS in large quantity, as it may flash in

the way.

6.3.4 DECOMMISSIONING OF DESALTERS

152

Switch off power to both desalters and then stop desalting water to both the units.

However crude flow through desalters can be maintained.

Shut off desalter effluent water (brine) lines after ensuring the water level is lowered to

minimum.

Wide open the mixing valves at desalter inlet by manual operating MV-1201 & MV-1202

the pressure control system of the desalters should to work so that steady desalted crude

pump suction pressure is ensured.

When CDU is on hot circulation, as elaborated ahead, desalter can be bypassed after

opening PV-1206 at desalter inlet fully in manual mode. Drain desalter content into close

blow down (CBD) system. Desalter can be kept filled with gas oil and be isolated after

draining. Keep desalter pressure around 0.3 Kg/cm2g when it is idle.

6.3.5 NORMAL SHUTDOWN

CDU is still running with around 50% of normal capacity with LR routed to slop and the

side draw off products from atmospheric column are going to respective product tanks.

Start reducing atmospheric furnace COT by TIC-1416 at 30° C per hour.

As temp. of crude oil drops, there will be less of distillate product and column pressure

will tend to fall. Admit fuel gas into the reflux drum through pressure controlled PV-

1504B if fuel gas is available from else where.

As column temperature start dropping, quantity of products will go off spec. Divert the

off spec distillate products to slop at the battery limit. Inform related units about the

rerouting.

At a column bottom temperature of around 300° C cut off stripping steam to column

bottom. Keep striping steam to side strippers also to be discontinues as and when side

draw off products are diverted to slop. Also GO CR to HN reboiler to be stopped.

With a drop in column top temperature, the overhead product yield will gradually come

down. Stop withdrawing naphtha product and resort to total top refluxing. Liquid in

reflux drum will be emptied out into crude column slowly.

Gradually stop product withdrawal and stop product pumps, when they give unsteady

performance on continuous operation.

153

Reduce CR rates. Stop all CR pumps one by one, starting from HN CR pump as and

when they loose suction.

With lowering of heater COT, LR yield will increase and its viscosity will come down.

Line up LR R/D to pre-desalter crude pump suction and establish close circulation of LR,

as was done during hot circulation at the time of start up.

Isolate the crude feed line from the unit battery limit.

Hot circulation circuit :

PA-1 -->Crude Preheat Train Circuit Before Desalter (including both New and Old

Preheat Train) ----> Desalter ----> Crude Preheat Train Circuit After Desalter (including

both New and Old Preheat Train) -----> Furnace -----> Column -----> PA-51 ------>RCO

circuit. ----> P1 suction.

When heater box temperature drops to about 200° C, cut off all furnace fire. Purge out

burners and firebox and get FG line blinded. Continue IFO circulation.

Continue crude circulation till system gets cooler down sufficiently to about 100° C at

the column bottom. After this, stop all crude pumps. Discontinue RCO pump discharge

from crude tanks and line up LR pump discharge to slop tank. Stop LR pumps also when

they loose suction. Stop ID / FD fan

6.3.6 SHUTDOWN OF ATMOSPHERIC SECTION FOR M&I

Take flushing oil to the atmospheric column through RCO pump suction. Build up about

80% level at the bottom of the column.

Line up circuit again through LR circuit and crude charge pump and complete the

circulation block up to column.

PA-1 -->Crude Preheat Train Circuit Before Desalter (including both New and Old

Preheat Train) ----> Desalter ----> Crude Preheat Train Circuit After Desalter (including

both New and Old Preheat Train) -----> Furnace -----> Column----->PA-51------>RCO

circuit ------>PA-1

Flash out heavy stuff from all exchangers/control valve bypasses by operating

them one by one.

154

Continue circulation till entire circuit is flushed out check consistency of

circulating stream. When it is sufficiently thin, stop circulation and pump out the

material to slop tank. The flushing operation may have to be repeated more than

once.

Deblind & line up service water connection at P01 suction. Start P01 & push the

line material (Both new & old circuit) to column via desalter. When desalter inter-

phase level raises to 100% bypass & drain desalter content to CBD &

subsequently pump out CBD content to slop tank. Continue water flushing to

C01& pump out C01 to slop header through RCO circuit.

After water flushing is over, isolate & bypass all RCO & Crude Heat Exchangers

& drain all the exchangers to CBD.

Slowly open steam to the discharger of crude charge pumps and flush the lines

and equipment into the C01 bypassing desalter. Steam crude preheat exchangers

and displace the material into the column. Open emergency steam to all the passes

of the furnace to expedite the displacement (this is suggested in view of large hold

up of hydrocarbon in piping which remain stagnated).

Pump out the material collected at crude column bottom to slop tank. Run LR

pump as and when necessary.

Depressurize crude column to flare. After depressurization, close all valves

releasing to flare. Close cooling water B/Vs at plant battery limit and drain out

water from condensers and product coolers.

Steam out discharge of RCO pump and route the material into slop header. Care

should be taken to avoid steaming beyond battery limit.

Isolate fuel gas header from all the reflux drums.

6.3.7 EMPTYING OUT OF THE UNITS AND PURGING/ISOLATION

After maximum quantity of hydrocarbon material has been removed from the unit, drain

all equipment and lines to CBD one by on. Drain Amine settler bottom to amine drain.

Reverse blinds on CBD lines from various equipment to open position. Drain all the oil in

the CBD. Ensure adequate ullage in CBD drum by pumping out CBD drum contents to

slop. Rise in CBD drum level should be watched periodically while draining.

155

Decommission FG header to flare header & purge with steam. Isolate flare header at

battery limit. Reverse the blind to close position of the fuel gas header in the plant battery

limit, if FG is not required by ARU. Decommission LPG vaporizer. Blind off fuel gas

line. Isolate all inlet and outlet lines at the battery limit.

Flush out fuel oil header by taking flushing oil at unit battery limit. Drain out oil to CBD.

Open vent at top of equipment, other high point vents and reflux drum vents etc. before

steaming. The step of steaming can be taken up only after shutdown of the rest of the unit

so that cooling water can be isolated for effective steaming. Steam out for a period of

about four hours, after which it will be discontinued. Allow the system to cool down with

vent valves full open. Stop steaming the equipment when steam enters CBD system.

Start steaming crude column, stabilizer column, desalter, furnace coils and exchanger

trains etc. as detailed under the section of start up procedures. Continue steaming till all

hydrocarbon vapours are removed from the system. Ensure that column vents are opened

to atmosphere to avoid vacuum formation. During steaming care should be taken so that

system pressure does not exceed operating pressure. Then stop steaming and let the

equipment to get cooled. Connect steam hoses to the utility connection point of all

equipment and start steaming.

Steam out the headers in hydrocarbon service till clear steam comes out from all high

point vents and all hydrocarbons are eliminated.

Shut off steam to the lines.

Carry out insertion of blinds as per the master blind list for isolating the unit for

maintenance.

After positive isolation is over start again steaming followed by hot water wash by

introducing water from top of the column by reflux pump. At least 4-hour hot water

wash to be done followed by cold-water wash to cool down the columns.

Blind steam out point & open column manholes.

During steam purging ensure that dry steam has come out from all LPDs & HPVs & no

trapped hydrocarbon is left inside.

6.3.8 CHECK LIST FOR UNIT NORMAL SHUTDOWN FOR BOTTLED UP CONDITION

156


Remarks

1 InformRSM/OMS/TPS/Water Block/Laboratory about S/D

S/I

2 Ensure flushing oil availability in GHC S/I3 Ensure slop tank at GRE has sufficient

ullageS/I/Panel

Opr.4 Check CBD pump is in healthy condition Pump.Opr


Remarks

5 Inform RSM / P&C/OMS for availability of LS crude tank

S/I

6 If the S/D is for longer period, stop VR receiving in IFO drum & Receive RCO ex EE4 to it at least 12 hours before the unit is schedule to S/D. Accordingly reduce / adjust IFO temperature.

Panel/Field Opr.

7. Stop / divert CRU drag stream / DHDS & LAB wild naphtha processing. Inform CRU / LAB plant / DHDS shift in-charge.

S/I/Field Opr.

8. Thru’ put reductiona) Switch over to total LS crude

processing (4 Hrs before T’Put reduction)b) Reduce T’put to 8000 Mt/Day level.c) Bypass low FG pressure & low FO

pressure inter lock

Panel Opr.

9. a)Route ATF / SKO to HSD poolb)Route LN to GN pool

Panel/Field Opr.

10. Stop water & demulsifier injection to desalter

Field Opr.

11 Reduce F1 COT @ 30deg C Panel/Field Opr.

12. Stop all chemical injection & desalter desludging pump

Field Opr.

13. At 250 deg C (Column bottom temp.) cut off stripping steam to column / strippers & put unit on hot circulation

Panel/Field Opr

14 Adjust RCO cooler to maintain 50-60 deg cooler O/L temp.

Panel/Field Opr

15. Reduce temperature to 120 deg C @ 40 deg C/Hrs by cutting off all oil burners one by one & flush it with steam.

Panel/Field Opr

16 At 120 deg C cut off furnace by closing main FG isolation valve & purge box with purging steam.

Field Opr

157

17 Insert blind in FG line and stop furnace box purging.

S/I

18 Switch off desalter. Field Opr19 Stop all product pump when stripper level

is lowPanel/

pump Opr20 Stop all reflux pumps Pump Opr.21 Stop ID / FD Panel/Field

Opr


Remarks

22 If the S/D is for longer period carry out flushing

Bring down C1 level to lowest possible level by diverting it to RCO tank.

Receive FLO at Crude pump suction. Build up C1 level to 80%.

Initially route C1 bottom product to RCO tank for 20 minutes.. Than establish close circulation

Check RCO sample at B/L. If it is light Stop circulation pump, if not repeat point a to d.

Panel/Field /Pump Opr.

23 Flush all RCO R/D lines with FLO to individual units / tanks

Field Opr.

24 Isolate RCO to IFO drum I/L valve. Empty out IFO drum to slop header to lowest possible level. Take gas oil in the vessel. Continue IFO circulation. Repeat this sequence for 2 to 3 times. Check sample. If it is light, stop circulation.

Panel/Field Opr

25 Decommission LPG caustic wash system if not in use (for other units)

Field Opr

26 Decommission naphtha & ATF caustic wash system

Field Opr

27 Isolate all R/D battery limit valves. Panel/Field Opr

28 Keep C1 /C5 floating with FG system on positive pressure.

Panel Opr

29 Stop crude circulation when the column (CC-01) bottom temp. comes down to 100 deg C.

Panel/Field /Pump Opr.

158

CHAPTER-7

EMERGENCY PROCEDURES

159

EMERGENCY PROCEDURES

7.1 GENERAL GUIDELINES

An emergency in the unit means a serious up set in the unit operating conditions resulting

in products going off, and damage to equipment (if proper actions are not taken promptly

and so warrants quick decision and quick actions.

Under emergency conditions, action is to be taken promptly as per the guidelines given

below:

The product inside the heater coil should not get excessively heated, to avoid

coke formation.

Heater coils should not run dry.

Cut off oil firing and gas firing before putting off the pilot gas burners. Close the

unit limit gas and unit B/V and depressurize the gas line to flare line.

Firebox purging steam should be opened immediately after cutting off pilot gas

burner.

Heater coil pressure must be lower than available steam pressure, when coil-

purging steam is opened.

If coil purging in F-1becomes necessary, no condensation of steam inside the

coils is permitted, since the last tubes are of stainless steel.

160

The passivation solution should be prepared at the earliest, since the same may be

needed for passivation of F-1 coils.

Steam flushing of individual oil burners, is required to keep the tips free for

subsequent light up.

Fuel oil BPC bypass valve is required to be opened in time, so that BPC pressure

does not exceed 10.0 kg/cm2.

No excessive pressure surge or level build up in columns, vessels etc. are to be

allowed. Attempt is to be made to avoid any safety valve popping.

No off grade materials is to be allowed to go into on grade tanks. Hence, timely

closing of rundown valves or diverting product rundowns should be ensured. Inform

concerned sections about stopping/diversion.

Crude feed line battery limit isolation valve is to be closed before establishing

circulation.

While on hot circulation, RCO cooler rundown temperature should not

exceed 50-55OC, to avoid feed pump losing suction. (Temp. is to be controlled by

pinching water to LSHS/RCO coolers)

While pumping out any material from the unit pump out temperature has to be

low enough.

Timely closing of stripping steam isolation valves must be ensured, to avoid

pressure surges in the column or product backing up into steam line. Keep bleeders on

the steam lines, mainly on 3 Ata steam line opened to avoid back up of product.

Crude oil circuit must be flushed with diesel at the earliest convenient time to

avoid congealing.

Proper vigilance in the plant to be observed by operating personnel to avoid

near fire or fire likes situations. Timely actions like blanketing by opening steam

lancers may help avoiding near fire situation to develop into a fire situation.

The major emergencies encountered are:

Power failure

Steam failure

Water failure

Instrument air failure

161

Crude feed failure

All utilities failure

Failure of heater coils

Failure of heater interlocks

110V DC supply failure

24V DC supply failure

UPS failure

DCS failure

Fire in the plant

7.2 POWER FAILURE IN UNIT:

A power dip of eve 2/3 seconds is enough to trip a motor. If on the other hand, due to

malfunctioning of a transformer in the sub-station or some cable faults or power shedding

etc. there is a partial/total failure of power supply to the unit, then unit will have to be

shutdown depending on the resumption of power supply to the unit. The pumps will not

be transferring liquid from one place to other because the motors have stopped.

Power failure may be of 3 types

1) HT POWER FAILURE

2) LT POWER FAILURE

3) TOTAL POWER FAILURE

EFFECTS OF POWER FAILURE:

Following are the effects of power failure:

All the motors will stop.

No flows through heater coils.

No reflux to columns.

Exchangers will get a thermal shock.

Columns top temperature will start shooting up and pressure will also shoot up.

162

For sometimes the vapors will continue to come from column overheads and

condense in condensers and then go to vessels. So, vessels will become full. Since

there is no material going out of the vessels, vessel safety may pop.

No illumination in the plant and no alarm signals will work.

There are chances of fire in the plant due to thermal shocks and leaks.

Heater refractory may get a thermal shock. Hence there are chances of bricks

falling down.

1) HT POWER FAILURE

In case of HT power failure only Crude pump will trip. Furnace will cut off on Low pass

flow inter lock.

Sl.No JOB DESCRIPTION Action

by

Done

YES/NO

Remarks

1 Inform RSM/TPS/OMS/SPNM S/I

2 Furnace should trip on inter lock. Close FG

& FO C/V from panel.

Panel

Opr.

3 Isolate individual oil & gas burners valves

and flush the burner oil guns with steam.

Field

Opr.

4 Isolate main FG line B/V. Field

Opr.

5 Pilot burners should be in line, otherwise

isolate them & purge the heater with steam.

Field

Opr.

6 Close the discharge valves of the pumps,

which were running.

Pump

Opr.

7 Route ATF / SKO to HSD & Naptha to GN

pool.

Panel/

Field

163

Opr.

If power clearance is obtained from TPS

immediately

1 Start stand by pumps & establish flow

through heater coils.

Panel/

Pump

Opr.

2 Take low pass flow inter lock in line. Panel

Opr

3 Purge heater box with steam if pilot burners

are off.

Field

Opr.

4 Start FD fan after bypassing its inter lock.

Ensure negative draft.

Panel/

Field

Opr.

5 Light all pilot burners. Take FG & FO

burner in line.

Field opr.

6 Raise temperature @ 40 deg / hr. Panel/

Field

Opr.

7 Stabilize unit condition. Panel

Opr.

8 Take ID fan in line. Panel/

Field

Opr.

9 Take all inter locks in line. Panel

Opr.

10 Check product colour. Pump

Opr.

11 Send sample to Lab. S/I

If power clearance is not obtained/power

is not resumed within few minutes,

164

1 Inform RSM/SPNM/CPNM about the

situation.

S/I

2 Start coil purging steam & displace the oil

contents of oil to column (while purging the

coil with steam, care should be taken that

column operating pressures should not

exceed)

Panel/

Field

Opr.

3 Cut off striping stream c/vs. of CC-01/CC-

03/CC-04 from the panel.

Panel

Opr.

4 Close CC-001/3/4 stripping steam control

valve block valves and bypass valves.

Bleeder of these c/vs. to be opened.

Field

Opr.

5 Put unit on close circulation. Panel/

Field

Opr.

6 Adjust RCO cooler O/L temperature to

about 50-60 deg C.

Panel/

Field

Opr.

7 Stop ID fan & switch over furnace to forced

draft mode.

Panel/

Field

Opr.

8 Run FD till Column cools down / Column

pressure comes under control.

Panel

Opr.

9 Route product to off grade tank. S/I/

Panel/

Field

Opr.

10 Stop all chemical injection pump. Field

Opr.

11 Stop dm water to desalter. Field Opr

12 Stop all product & reflux pump when Panel/

165

stripper / vessel level comes down. Pump

Opr.

13 Decommission Naphtha / SKO caustic wash

system.

Field Opr

14 Decommission LPG wash system, if other

unit LPG is not washed here.

Field Opr

15 Switch off desalter. Field Opr

16 Inform OMS to line up crude tank for

gravity line up.

S/I

17 Isolate all product battery limit valve. Field

Opr.

ON RESUMPTION OF HT POWER

1 Ensure coil-purging steam valves are closed

and establish cold circulation.

Field

Opr.

2 Adjust RCO cooler CW flow to have 40 –50

deg O/L temperature.

Panel/

field Opr.

3 Purge heater box with steam & establish

negative draft if pilot burners are not in line.

Field

Opr.

4 Start FD fan, if stopped. Panel/

Field

Opr.

5 Light all pilot burners. Field

Opr.

6 Light gas burner. Field

Opr.

7 Increase temperature @ 40 deg. C/hr. Panel/

Field

Opr.

8 Ensure low feed pass flow in line. Panel

Opr

166

9 Check the unit for any leak. Fix it if so. S/I/Field

Opr.

10 Take oil burner. Field Opr

11 At 300 Deg C cut off feed by introducing

stripping steam in C01 & putting unit out of

circulation.

Panel/

Field Opr

12 Introduce stripping steam to strippers. Panel/

Field Opr

13 Increase temp. as required. Panel/

Field Opr

14 Start top reflux pump when level appears.

( Drain water completely).

Pump/

Field

Opr.

15 Start sour water pump & rout to SRU. Pump/

Field Opr

16 Maintain required top temp. Panel

Opr

17 Start CR / Product pump, when level appears

in stripper.

Pump

Opr

18 Adjust column condition. Panel

Opr

19 Heat up stabilizer bottom . Panel

Opr

20 Drain water from V3 when level appears &

start reflux pump& adjust column condition.

Pump/

Field Opr

21 Route LPG & Naptha to R/D after

commissioning caustic wash system.

Panel/

Field Opr

22 Route all products to off grade tank. Pump/

Field Opr

23 Sent sample to lab. S/I

167

24 If certified, divert product to on grade tank. Panel/

Field Opr

25 Take all inter locks in line. Panel

Opr

2) LT POWER FAILURE:

Following are the effects of LT power failure:

EFFECTS:

All the motors except Crude pump and Desalted crude pump will stop.

ACTIONS TO BE TAKEN:

In case of LT power failure to the unit (but steam being available) following actions

should be taken:

Sl

No

JOB DESCRIPTION Action by Done

YES/NO

Remarks

1 Inform RSM/TPS/CGP/OMS/SPNM S/I

2 With the LT power failure, fuel oil pumps

will also automatically stop but gas firing will

continue.

3 Shut FO C/V from panel. Panel Opr/

4 Isolate all FO burners & flush with steam. Field Opr.

5 Confirm if the failure is partial, and if power

is available in standby pumps, start all stand

by pumps one by one & stabilize the unit by

temporarily increasing FG firing.

Pump Opr.

6 Establish IFO circulation. Take oil burners in

line.

Panel/Field

Opr.

7 Stabilize unit condition. Panel opr.

8 Take IFO inter lock in line. Panel Opr.

If the failure is total & does not resume in

168

short time

1 Inform

RSM/SPNM/CPNM/OMS/GRE/GRSPF/SRU

S/I

2 Cut-off gas firing in the heaters by closing

individual burner block valve. Isolate main

FG isolation valve also.

Field Opr.

3 Purge the heater box with steam. Field Opr.

4 Cut off striping stream c/vs. of CC-01/CC-

03/CC-04 from the panel.

Panel Opr.

5 Close CC-001/3/4 stripping steam control

valve block valves and bypass valves.

Bleeder of these c/vs to be opened.

Field Opr.

6 Isolate all pump discharges, which were

running.

Pump Opr.

7 Switch off desalter. Field Opr.

8 Establish close circulation. Panel/Field

Opr.

9 Keep watch on pressures of vessel / column

and release the same into flare by opening

PIC or PSV bypass if required.

Panel Opr.

10 Close all the R/D valves. Panel/Field

Opr.

On resumption of power start the unit as per

normal start-up procedure.

Sl

No


YES/NO

Remarks

1 Inform RSM/SPNM/CPNM S/I

2 Purge the heater box with steam. (15 to 20

minutes).

Field Opr.

3 Start FD fan. Panel/Field

169

Opr.

4 Check furnace draft. Ignite all pilot burner

one by one.

Field Opr.

5 Take FG & FO burner in line. Field Opr.

6 Raise COT @ 40 deg C /hrs. Panel/field

Opr.

7 Feed cut at 300 deg c by introducing stripping

steam in the column & taking out of

circulation.

Panel/Field

Opr.

8 Increase COT as per requirement. Panel/Field

Opr.

9 Take frequent round around the plant. Fix any

leak / smoky flange if observed.

S/I/Field

Opr.

10 Start reflux pump when level appears in O/H

vessel & maintain top temperature. Divert

excess naphtha to stabilizer

Pump Opr.

11 Start CR & Product pumps when level

appears in strippers.

Pump Opr.

12 Adjust unit condition. Panel Opr.

13 Initially route products to off grade product

tank.

Panel/Field

Opr.

14 Slowly increase stabilizer bottom

temperature.

Panel Opr.

15 Drain water from V3 when level appears &

start reflux pump& adjust column condition.

Field opr.

16 Commission LPG / Naptha / SKO caustic

wash system.

Field Opr.

17 Send R/D sample to lab. S/I

18 If certified divert R/D to on grade tank. Panel/Field

Opr.

170

19 Take all inter lock in line. Panel Opr.

3) TOTAL POWER FAILURE:

EFFECTS

Following are the effects of Total power failure:

There will be no power to run Ht / LT motors.

There will be no CW / Air / Steam / No illumination.

There are chances of fire in the plant due to thermal shocks and leaks.


In case of power failure to the unit, following actions should be taken:

Sl.No JOB DESCRIPTION Action by Done

YES/NO

Remarks

1 Inform

TPS/CGP/RSM/SPNM/OMS

S/I

2 Cut off furnace from panel by

closing FG & FO C/V.

Panel Opr

3 Isolate individual oil & gas burners

valves and flush the burner oil guns

with steam if available.

Field Opr.

4 Isolate main FG line B/V. Field Opr.

5 Purge the heater with steam, if

available.

Field Opr.


YES/NO

Remarks

6 Cut off striping stream c/vs of CC-

01/CC-03/CC-04 from the panel.

Panel Opr.

7 Close CC-001/3/4 stripping steam

control valve block valves and

bypass valves. Bleeder of these c/v

Field Opr.

171

s to be opened.

8 Close all discharge valves of the

pumps which were running.

Pump Opr.

9 Keep close watch on system /

vessels pressure. If it soot’s up

release to flare by opening PSV /

PIC bypass.

Panel Opr.

10 Take frequent round around of the

plant. Fix any leak / smoky flange

if observed.

S/I/field opr.

11 Isolate all steam battery limit valve. Panel/Field Opr.

On obtaining clearance for

power / steam / CW / AIR start up

unit as follows:

1 Inform RSM/SPNM/CPNM/OMS S/I

2 Commission steam: open all steam

header condensate drain trap

bypass. Slowly creak open battery

limit valve & drain out condensate.

When dry steam started coming out

of trap bypass, slowly open battery

limit valve. Close trap bypass.

Panel/Field Opr.

3 Check instrument air pressure Panel/Field Opr.


YES/NO

Remarks

4 Check cooling water pressure /

flow

Panel Opr.

5 Physically check total unit for

possible leakage. Attend it if any

S/I/Field Opr.

6 Purge all FO burner with steam. Field Opr.

172

7 Purge heater box with steam. Field Opr.

8 Start IFO pump & establish

circulation after bypassing inter

lock.

Panel/Field Opr.

9 Line up for & establish crude close

circulation.

Field Opr.

10 Check furnace draft. Field Opr

11 Start FD fan after bypassing inter

lock.

Panel/Field opr.

12 Light up all pilot burners. Field Opr.

13 Bypass FG low-pressure interlock

& take FG burners in line.

Panel/Field Opr.

14 Raise temperature @ 40 deg C / hr.

Take FO burner if required.

Panel/Field Opr.

15 Feed cut in at 300 deg c by

introducing stripping steam in the

column & taking out of circulation.

Panel/Field Opr.

16 Increase COT as per requirement. Panel/Field Opr.

17 Take frequent round around the

plant. Fix any leak / smoky flange

if observed.

S/I/Field Opr.

18 Start reflux pump when level

appears in O/H vessel & maintain

top temperature. Divert excess

naphtha to stabilizer.

Panel/Pump Opr.

19 Start CR & Product pumps when

level appears in strippers.

Pump Opr

20 Adjust unit condition. Panel Opr.

21 Initially route products to off grade

product tank.

Field Opr.

173

22 Slowly increase stabilizer bottom

temperature.

Panel Opr.

23 Drain water from V3 when level

appears & start reflux pump&

adjust column condition.

Panel/Field/Pump

Opr

24 Commission LPG / Naptha / SKO

caustic wash system.

Field Opr.

25 Send R/D sample to lab. S/I

26 If certified divert R/D to on grade

tank.

Panel/Field Opr.

27 Take all inter lock in line. Panel Opr.

7.3 STEAM FAILURE

STEAM FAILURE:-

Steam Failure may be of three types.

1. HP Steam

2. MP steam

3. LP Steam

1) MP STEAM FAILURE:

EFFECTS:

Following are the effects of MP steam failure:

Atomizing steam to oil burners will not be available. Hence no atomization, and

no proper combustion. Heaters will be sprayed with oil, later on burn on the

surface of tubes.

Stripping steam to CC-001/3/4 will not be available. Chances of product backing

up into steam line are more, if b/vs are not closed immediately. So it may be

observed that unit cannot run without steam and shutdown is a must.

Fire fighting steam will not be available.

ACTION TO BE TAKEN:

Following actions are required immediately in case of MP steam failure.

174

Sl

No


YES/NO

Remarks

1 Inform

TPS/CGP/RSM/SPNM/OMS

S/I



Panel Opr.

2 Isolate individual oil & gas

burners valves and flush the burner

oil guns with steam if available.

Field Opr.


4 Purge the heater with steam, if

available.

Field Opr.

5 Cut off striping stream c/vs of

CC-01/CC-03/CC-04 from the

panel

Panel Opr



bypass valves. Bleeder of these c/v

s to be opened.

Field Opr.

7 Put unit on close circulation. Panel/Field

Opr.

8 Adjust RCO cooler O/L

temperature to about 50-60 deg C.

Panel/Field

Opr.

9 Cut off gas burners if gas is not

available.

Field

Opr.

Sl

No


YES/NO

Remarks

10 Isolate FG main isolation valve. Field Opr.

11 Route product to off grade tank. Panel/Field Opr.

175

12 Stop all chemical injection pump. Field Opr.

13 Stop all product & reflux pump

when stripper / vessel level looses.

Panel/Field Opr.

14 Decommission LPG / Naphtha /

SKO caustic wash system.

Field Opr.


16 Inform OMS to line up crude tank

for gravity line up.

S/I/Panel Opr.

ON RESUMPTION OF STEAM

1Inform RSM/SPNM/CPNM/OMS

S/I

2Purge oil burners.

Field Opr.

3Purge heater box with steam & establish negative draft.

Field Opr.

4Start FD fan.

Panel/Field Opr.

5Light all pilot burners.

Field Opr.

6Light gas burner.

Field Opr.

7Increase temperature @ 40 deg. C/hr.

Panel/Field Opr.

8Ensure feed pass flow low in line.

Panel Opr.

9Check the unit for any leak. Fix it if so.

S/I/Field Opr.

Sl

No


YES/NO

Remarks

10At 300 Deg C cut off feed and introduce stripping steam in C01 & putting unit out of circulation.

Panel/Field Opr.

11Increase temperature as required.

Panel/Field Opr.

176

12Start top reflux pump when level appears (Drain water completely).

Pump Opr.

13Start sour water pump & route to SRU.

Pump/Field Opr.

14Maintain required top temp.

Panel Opr.

15Start CR / Product pump, when level appears in stripper.

Panel/Pump Opr.

16 Adjust column condition. Panel Opr.

17 Heat up stabilizer bottom & adjust

column condition.

Panel Opr.




Panel/Field/Pump

Opr.

19 Route LPG & Naphtha to R/D

after commissioning caustic wash

system.

Field Opr.

20 Route all products to off grade

tank.

Panel/Field Opr.


22 If certified, divert product to on

grade tank.

Panel/Field Opr.

23 Take all interlocks in line. Panel Opr.

2) HP STEAM FAILURE

i) Only IFO / VR heating system will affect.

ii) Monitor IFO temperature.

iii) If HP Steam temperature is falling below 160 deg.C,

Stop VR receiving from GHP ( inform GHP) .

iv) Take RCO from D/S of EE4 in VR drum.

177

v) Adjust furnace firing .

3) LP STEAM FAILURE

i) Utility steam will not be available. Care should be taken to

the smoky flanges where steam lancers are provided.

ii) Hot pump seal quenching steam will not be available.

iii) Fire fighting steam will not be available.

UNIT TO BE SHUT DOWN AS PER THE PROCEDURE MENTIONED FOR MP

STEAM FAILURE.

7.4 COOLING WATER FAILURE

EFFECTS:

No water to condensers and coolers. No water to pumps.

Hence in the absence of cooling medium, there will not be any condensation and

all columns pressure will shoot up very fast.

Pumps glands may be burnt and lube oil temp. will increase. Gland will start

leaking.

Pumps will have to be stopped.

If cooling water failure is only partial, it can be tackled by reducing throughput

and throttling water to coolers/condensers proportionally.

ACTION TO BE TAKEN:


YES/NO

Remarks

1 Inform Cooling

tower/RSM/SPNM

S/I



Panel Opr.


burners valves and flush the

Field Opr.

178

burner oil guns with steam


5 Pilot burners should be in line,

otherwise isolate them & purge

the heater with steam.

Field Opr.



panel.

Panel Opr.

7 Close CC-001/3/4 stripping

steam control valve block valves

and bypass valves. Bleeder of

these c/v s to be opened.

Field Opr.

8 Put unit on close circulation. Panel/Field Opr.


temperature to about 50-60 deg

C.

Panel/Field Opr.

10 Stop ID fan & switch over

furnace to forced draft mode.

Panel/Field Opr.

11 Run FD till Column cools

down/Column pressure comes

under control.

Panel/Field Opr.

12 Route products to off grade tank. Panel/Field Opr.

13 Stop all chemical injection

pump.

Field Opr.


when stripper / vessel level

looses.

Panel/Pump Opr.

14 Decommission LPG / Naphtha /

SKO caustic wash system.

Field Opr.


179

16 Inform OMS to line up crude

tank for gravity line up.

S/I/Panel Opr.

ON RESUMPTION OF CW

1 Inform

RSM/SPNM/CPNM/OMS

S/I

2 Check CW flow / pressure Panel/Field Opr.

3 Line up & establish cold

circulation.

Panel/Field Opr.

4 Take low pass flow inter lock in

line.

Panel Opr.

5 Purge heater box with steam &

establish negative draft if pilot

burners are not in line.

Field Opr.

6 Start FD fan, if stopped. Panel/Field Opr.

7 Light up all pilot burners. Field Opr.

8 Light up gas burner. Field Opr.

9 Increase temperature @ 40 deg.

C/hr.

Panel/Field Opr.

10 Check the unit for any leak. Fix

it if so.

S/I/Field Opr.

11 At 300 Deg C cut off feed by

introducing stripping steam in

C01 & putting unit out of

circulation.

Panel/Field Opr

12 Introduce stripping steam to

strippers.

Panel/Field Opr.

13 Increase temp. as required. Panel/Field Opr.

14 Start top reflux pump when level

appears.( Drain water

completely).

Panel/Pump Opr.

180

15 Start sour water pump & rout to

SRU.

Pump/Field Opr.

16 Maintain required top temp. Panel Opr.

17 Start CR / Product pump, when

level appears in stripper

Panel/Pump Opr.


19 Heat up stabilizer bottom . Panel Opr.




Panel/Pump/Field

Opr.


after commissioning caustic

wash system.

Field Opr.


tank.

Panel Opr.

23 Send sample to lab. S/I


grade tank.

Panel/Field Opr.

25 Take all inter locks in line. Panel Opr.

7.5 INSTRUMENT AIR FAILURE

Instrument air is supplied to the unit at a pressure of about 6.7 Kg/cm2g from the

compressor house. It is taken to an air receiver and from there it is taken to the unit. PC

on this line maintains the supply pressure at 3.0 Kg/cm2g in the header.

Air receiver in the unit can supply air for some time interval. If due to some reasons, air

supply cannot be restored within this period, then the supply lone header pressure will

fall below 3.0Kg/cm2g and will decline fast. The instruments will cease to function.

Control valves will remain fully open or close depending on whether the control valve is

air to close or air to open. Hence unit will have to be shutdown.

181

EFFECTS

Following are the effects of instrument air failure.

Instrument loops that are having pneumatic provision such as closed loop control

valves will stop functioning.

However open loop instruments involving electronic data transmission shall

remain.

On account of closure of FO / FG control valves, heater will trip.

Allow FD/ID fans to run as long as possible.

All the LC’s will open fully.

The PC’s of CC-001 and CC-005 will open fully leading to loss of pressure.

Atomizing control valve will go to full open position.

With the pumps running all the flows will go up. But since heater firing is

substantially reduced, temperature will fall down. Level in vessel will come

down. Reflux pumps will lose suction, and hence columns top temperature will

shoot up. So shutdown is imminent.


Sl.

No


YES/NO

Remarks

1 If Instrument air can't be

restored, Cut off furnace from

panel by closing FG & FO

C/V.

Panel Opr.



burner oil guns with steam.

Field Opr.


4 Check pilot burner, if not in

line isolate them & purge the

heater with steam.

Field Opr.



Panel Opr.

182

panel.


steam control valve block

valves and bypass valves.

Bleeder of these c/v s to be

opened.

Field Opr.



temperature to about 50-60

deg C.

Panel/Field Opr.



Panel/Field Opr.


down / Column pressure

comes under control.

Panel Opr.

11 Route product to off grade

tank.

Panel/Field Opr.


pump.

Field Opr.

13 Stop all product & reflux

pump when stripper / vessel

level comes down.

Panel/Pump Opr.

14 Decommission LPG / Naphtha

/ SKO caustic wash system.

Ensure LPG system is not used

for other unit.

Field Opr.




S/I/Panel Opr.

17 Isolate all product battery limit Field Opr.

183

valve.

ON RESUMPTION OF INSTRUMENT AIR

1Check battery limit IA pressure

Panel/Field Opr.



burners are not in line

Field Opr.


4 Light all pilot burners. Field Opr

5 Light gas burner. Field Opr

6 Increase temperature @ 40

deg. C/hr.

Panel/Field Opr.

7 Ensure low feed pass flow in

line.

Panel Opr.

8 Check the unit for any leak.

Fix it if so.

S/I/Field Opr.

9 Take oil burner. Field Opr.




circulation.

Panel/Field Opr.


strippers.

Panel/Field Opr.


13 Start top reflux pump when

level appears.( Drain water

completely).

Pump/field Opr.

14 Start sour water pump & rout

to SRU

Pump/field Opr.

184


16 Start CR / Product pump,

when level appears in stripper.

Pump/field Opr.


18 Heat up stabilizer bottom &


Panel Opr.

19 Drain water from V3 when

level appears & start reflux

pump& adjust column

condition.

Panel/Pump/field

Opr.



wash system.

Field Opr.


tank.

Field Opr.

22 Send sample to lab. S/I

23 If certified, divert product to

on grade tank.

Panel/Field Opr.


7.6 FEED FAILURE:

Crude oil is supplied to unit by booster pumps from crude control. Crude feed supply to

the unit could get interrupted due to many reasons viz. improper functioning of booster or

unit feed pumps, improper lining up and chocking of strainers & or power supply failure.

etc. Interruption in feed flow calls for immediate action.

EFFECTS

Feed pumps will lose suction

No flow to the furnace.

Rapid drop in CC-001 bottom level

185

JOB DESCRIPTION

Furnace will cut off on inter lock.

Isolate FO / FG burners & flush with steam and the purge heater box.

Duration and cause of crude failure should be found out.

If the feed supply cannot be restored immediately bring the unit to circulation, cut

off stripping steam to columns & route the products to off spec. Tanks.

If the interruption is for a longer period the unit should be shutdown as per the

normal procedure.

7.7 ALL UTILITIES FAILURE:

With the total power supply failure to the whole refinery, there will be no supply of

circulating water, industrial and instrument air, and steam i.e. supply of all the utilities

will stop. This is major emergency and unit is automatically shutdown. Following action

will have to be taken immediately:

JOB DESCRIPTION

Close the C/V block valves and bypass valve of stripping steam to CC-001/3/4

and open bleeder to prevent backing up of crude oil/products into steam line.

Open the bleeder on steam line to drain out the product, if any, which might have

backed-up into steam line from columns.

Release the pressure from the reflux vessels to flare gas as & when required.

Since condensation will not take place in condensers column pressure will shoot

up and so safety valves may pop.

Drain the flare gas knockout drum, as well as gas bullets immediately.

Since instrument air supply will also fail, no indication will be available in control

room. Hence checks for temperatures, pressures, levels etc. Will have to be made

locally.

Isolate individual FO/ FG burners. Flush with steam if steam pressure is available.

186

Line up for close circulation.

Close all battery limit R/d valves.

Keep vigil of the unit for detection of possible leakage.

7.8 FAILURE OF HEATER TUBES

Whenever tube rupture takes place, bridge wall temperature will start shooting up. Smoke

will start coming from the top of the stack. It will become dense, as leak will increase.

Sharp rise in stack temperature may also be observed. Plant operating personnel and the

supervisor have to assess the extent of leak/rupture and take recourse either to normal

shutdown or emergency shutdown. Following steps are indicated to bring down the unit

quickly in the event of a failure of heater tube.

JOB DESCRIPTION

Put off all the fires in the heater. Stop ID/FD fans.

Feed to the heater to be stopped.

Snuffing steam will be opened in radiation and convection sections.

Emergency coil steam will be opened in all the passes of the heater.

Top and CR pumps will be stopped when they lose suction.

Top refluxing will continue as long as possible.

Columns pressure will be watched for any rise due to additional amount of steam

put into the heater coils.

Stripping steam to the column CC-001 and Stripper will be stopped.

LR circuit will be flushed by taking FLO.

Stabilizer/ caustic wash section is decommissioned as per normal procedure.

Shutdown rest of the equipment as per normal procedure.

7.9 110V DC SUPPLY FAILURE

187

110V supply is used for (i) Solenoid valves operation (ii) indication bulbs on panel (iii)

limit switches for open condition. In case of failure of 110V DC, fuel oil and fuel gas

shutdown valves will get closed.


YES/NO

Remarks

1 Inform I/M,E/M,RSM,SPNM,OMS S/I

2 Close FG & FO C/V from panel. Panel/Field

Opr.



with steam.

Field opr.



otherwise isolate them & purge the

heater with steam.

Field Opr.


01/CC-03/CC-04 from the panel.

Panel Opr.



bypass valves. Bleeder of these c/v s

to be opened.

Field Opr.

8 Put unit on close circulation. Panel/Field

Opr.

9 Adjust RCO cooler O/L temperature

to about 50-60 deg C.

Panel/Field

Opr.

10 Stop ID fan & switch over furnace to

forced draft mode.

Panel/Field

Opr.

11 Run FD till Column cools down /

Column pressure comes under

control.

Panel Opr.

188

12 Route product to off grade tank. Panel/Field

Opr.

13 Stop all chemical injection pump. Field Opr.

14 Stop all product & reflux pump when

stripper / vessel level comes down.

Panel/Field

Opr

15 Decommission LPG / Naphtha / SKO

caustic wash system.

field Opr.


17 Inform OMS to line up crude tank for

gravity line up.

S/I/Panel

Opr.

18 Isolate all product battery limit valve. Field Opr.

19 Do not bypass FO / FG low pressure

inter lock.

Panel opr.

ON RESUMPTION OF 110V DC

POWER

1 Inform RSM/SPNM/CPNM S/I

2 Check SOV’s / shut down valves are

working.

Panel Opr.




Field Opr.

4 Start FD fan, if stopped. Panel/Field

Opr.

5 Light all pilot burners. Field Opr.

6 Light gas burner. Field Opr.

7 Increase temperature @ 40 deg. C/hr. Panel/Field

Opr.

8 Ensure low feed pass flow in line. Panel Opr.

9 Check the unit for any leak. Fix it if

so.

S/I/Field

Opr.

189

10 Take oil burner in line. Field Opr.


introducing stripping steam in C01 &

putting unit out of circulation.

Panel/Field

Opr.


strippers.

Panel/Field

Opr.

13 Increase temp. as required. Panel/Field

Opr.


appears.( Drain water completely).

Pump/Field

Opr.

15 Start sour water pump & route to

SRU.

Pump/Field

Opr.


17 Start CR / Product pump, when level

appears in stripper

Panel/

Pump Opr.


19 Heat up stabilizer bottom . Panel Opr.


appears & start reflux pump& adjust

column condition.

Panel/

Field/Pump

Opr.


YES/NO

Remarks

21 Route LPG & Naphtha to R/D after


Field Opr.

21 Route all products to off grade tank. Panel/Field

Opr.



grade tank.

Panel/Field

Opr.


190

CAUTION:

If FO/FG SOVs, are on bypass mode, on resumption of 110V DC supply shut-off valves

will get automatically open. To avoid this, keep FO/FG shutdown valves on interlock

mode. Low fuel pressure trip will ensure that the S/D valves do not re-open automatically

on restoration of 110V DC powers.

7.10 24V DC SUPPLY FAILURE

To supply 24V DC, 2 nos. of keltron panel and battery back up is provided. 24V Dc

supplies is used for (i) Circuit relay/logic system for interlock (ii) Pressure switch signals

(iii) Control valve limit switches for close condition. With failure of one of Keltron panel,

“Trouble in Keltron Panel” will come and the other Keltron panel will take over. On

failure of both the panels “Battery back-up on line” signal will come. If 24V DC battery

back up also fails then FO & FG SOVs will get closed and furnace shall switch over to

natural draft. Take following actions to overcome the situation.

ACTION TO BE TAKEN

Sl .No JOB DESCRIPTION Action by Done

YES/No

Remarks

1 Close FG & FO C/V from panel Panel Opr.



with steam.

Field Opr.



otherwise isolate them & purge the

heater with steam.

Field Opr.

191


01/CC-03/CC-04 from the panel

Panel opr.



bypass valves. Bleeder of these c/v s

to be opened.

Field Opr.

7 Put unit on close circulation Panel/Field

Opr

8 Adjust RCO cooler O/L temperature

to about 50-60 deg C

Panel/Field

Opr.

9 Stop ID fan & switch over furnace

to forced draft mode

Panel/Field

Opr.



control.

Panel/Field

Opr.

11 Route product to off grade tank. Field Opr.

12 Stop all chemical injection pump. Field Opr


when stripper / vessel level comes

down.

Panel/Pump

Opr.

14 Decommission LPG / Naptha / SKO

caustic wash system

Field Opr.


16 Inform OMS to line up crude tank

for gravity line up.

S/I/Panel

Opr.

17 Isolate all product battery limit

valve.

Field Opr.

18 Do not bypass FO / FG low pressure

inter lock.

Panel Opr.

19 Inform Instrument / Electrical S/I

192

people to attend the problem.

ON RESUMPTION OF 24 V POWER SUPPLY




Field Opr.

2 Start FD fan, if stopped. Panel/Field

Opr.

3 Light all pilot burners Field Opr.



C/hr.

Panel/Field

Opr.

6 Ensure low feed pass flow in line. Panel Opr.

7 Check the unit for any leak. Fix it if

so.

S/I/Field

Opr.



introducing stripping steam in C01

& putting unit out of circulation.

Panel/Field

Opr.

Sl .No JOB DESCRIPTION Action by Done

YES/No

Remarks


strippers.

Field Opr.

11 Increase temp. as required. Panel/Field

Opr.


appears.( Drain water completely).

Panel/Pump

Opr.


SRU.

Pump/Field

Opr.


193

15 Start CR / Product pump, when level

appears in stripper.

Panel/Field

Opr.


17 Heat up stabilizer bottom & adjust

column condition.

Panel Opr

18 Route LPG & Naptha to R/D after


Field Opr.

19 Route all products to off grade tank. Panel/Field

Opr.



grade tank.

Panel/Field

Opr.


7.11 UPS FAILURE:

If UPS supply failure, UPS will run through battery back up system. If battery back up

system is failed, the following effects will be noticed.

US panel is to be blank.

All SOV will be closed.

Furnace will be cut off totally.

ACTION TO BE TAKEN:

Call inst. People to energies UPS system as fast as possible.

Load US panel from HM.

Open FO & FG SOV from ladder monitor.

Light up burner in all furnaces.

194

Normalize the unit.

Sl .N

o


YES/NO

Remarks

1 Close FG & FO C/V from

panel.

Panel Opr.



burner oil guns with steam.

Field Opr.




the heater with steam.

Field Opr.



panel.

Panel Opr.


steam control valve block

valves and bypass valves.

Bleeder of these c/v s to be

opened.

Field Opr.




C

Panel/Field Opr.



Panel/Field Opr.


down / Column pressure comes

under control.

Panel Opr.

11 Route product to off grade Field Opr.

195

tank.


pump.

Field Opr.



comes down.

Panel/Pump. Opr

14 Decommission LPG /

Naphtha / sko caustic wash

system

Field Opr.




S/I/Panel Opr.


valve.

Field opr.

18 Inform i/m & e/m people to

attend the problem.

S/I

ON RESUMPTION




Field Opr.




5 Increase temperature @ 40

deg. C/hr.

Panel/Field Opr.


line.

Panel opr.

7 Check the unit for any leak.

Fix it if so.

S/I/Field Opr.

196





circulation.

Panel/Field opr.


strippers.

Panel/Field Opr.


12 Start top reflux pump when

level appears. (Drain water

completely.

Panel/Pump Opr.

13 Start sour water pump & rout

to SRU.

Pump/Field Opr.



level appears in stripper.

Panel/Pump Opr.

16 Adjust column condition. Panel opr.

17 Heat up stabilizer bottom &


Panel Opr.

Sl .N

o


YES/NO

Remarks

18 Drain water from V3 when

level appears & start reflux

pump& adjust column

condition.

Field/Pump/Panel

opr.



wash system.

Field Opr.


tank.

Field Opr.

197


22 If certified, divert product to

on grade tank.

Panel/Field Opr.

23 Take all inter locks in line Panel Opr.

7.12 DCS CONSOLE FAILURE

If DDCS CONSOLE is failed, but UPS is running, the following effects will be seen:

All screens will be turned to blank.

Unit is running but there is no control on unit.

ACTION TO BE TAKEN

Call Inst. People to load it from History module as early as possible.

Normalize the unit if anything found wrong.

Unit cannot be run long time with this problem. It is to be shut down.

Sl .N

o


YES/NO

Remarks



burner oil guns with steam

Field Opr.

2 Isolate main FG line B/V Field opr.

Sl .N

o

JOB DESCRIPTION Remarks



the heater with steam

Field Opr.


steam control valve block valves

and bypass valves. Bleeder of

these c/v s to be opened.

Field Opr.

5 Put unit on close circulation.

Open pass flow bypass if

Field Opr.

198

required.



C.

Field Opr.

7 Monitor desalter pressure from

field

Field Opr.


furnace to forced draft mode

Field Opr.



control.

Panel Opr.

10 Open Column / Vessel PIC

bypass to maintain pressure if

required. Pressure to be seen

from field.

Field Opr

11 Route product to off grade tank. Field Opr.

12 Stop all chemical injection pump Field Opr.



comes down. Level to be seen

from the field.

Pump/Field Opr

14 Decommission LPG / Naptha /

SKO caustic wash system

Field Opr.

15 Switch off desalter. Field opr.



S/I


valve.

Field Opr.

18 Inform Instrument / Electrical

people to attend the problem

S/I

199

ON RESUMPTION OF 24 V POWER SUPPLY

1Establish crude circulation

Panel/Field Opr.

2Purge heater box with steam & establish negative draft if pilot burners are not in line.

Field Opr.

3 Start FD fan, if stopped Panel/Field Opr.




C/hr .

Panel/Field Opr


line.

Panel opr.

8 Check the unit for any leak. Fix

it if so.

S/I/Field Opr.





circulation.

Panel/Field Opr.


strippers.

Panel/Field Opr.



appears.( Drain water

completely).

Field /Pump Opr.


SRU.

Pump/Field Opr.


200


level appears in stripper

Pump/Panel Opr.


18 Heat up stabilizer bottom. Panel Opr.




Field/Pump/Panel

Opr.



wash system.

Field opr.


tank.

Field Opr.



grade tank.

Panel/Field Opr.


7.13 FIRE IN THE PLANT

EFFECTS

The equipment where fire has taken place due to hydrocarbon leakages will

definitely affect the normal running of plant. Action will depend on the judicious

observation & action to be taken depending on the situation.

ACTION TO BE TAKEN:

In no way get panic as it may result in some inappropriate decisions.

Initial fire fighting is to be started by plant personnel with available fire

extinguisher & water hydrants.

Immediately call the fire people at 7333 or 6333 for help.

201

Isolate the equipment or hydrocarbon to the equipment if fire is not being

controlled.

Damage by the fire to be immediately observed & its effect to normal

running of plant.

If anything abnormal is observed, T’put reduction to be started so that unit

can be taken on circulation (Hot or cold) or shut down in short duration

depending on situation.

Product colour to be observed continuously

If fire gets extinguished immediately unit conditions to be normalized.

202

CHAPTER-8

PROCEDURES FOR EQUIPMENT HAND OVER TO

MAINTENANCE/INSPECTION

EQUIPMENT HAND OVER TO MAINTANANCE/INSPECTION

PROCEDURES FOR PREPARATION OF EQUIPMENT HANDLING OVER

203

Equipments are required to be handed over during shutdown/normal operations for

maintenance purposes. Procedures given below should be followed to ensure their safe

release and safe maintenance work.

8.1 PUMP

8.1.1 COLD PUMP

De-pressuring the pump:

Following steps are to be followed for pump de-pressuring.

Close first discharge value then suction vale. (Close MOV & MOV bypass value).

Drain pumps casing liquid in to OWS (for LPG & high RVP product service

pump casing liquid to be vented into flare and after de-pressuring the pump vent

to flare value to be closed).

When draining liquid from the casing keep the vent valve on the pump d/s open to

ensure complete draining.

If pump service is for heavy product, take FLO and drain into OWS (for flushing

the pump casing).

If pump service for Caustic, Amine, Anti-oxidant or other chemical drain pump

casing liquid into chemical drum and then flush with water two or three times.

If mech. Seal flush line is their, close seal flush line value.

If Mech. Seal and pump bearing cooling water line is there, close cooling water

line value.

Pump motor & its auxiliary motors power supply isolate from sub-station.

Now pump is already for handling over to maintenance.

Ensure that "DO NOT OPERATE, MEN AT WORK" board is put on switch.

8.1.2 HOT PUMP

De-pressuring the pump.

Following steps are to be followed for pump de-pressuring:

204

Close first discharge valve and warm-up value then suction valve

Cool pump below 200° C.

Drain pump casing liquid into OWS.

If Mech. Seal flush line is there, close seal flush line value.

If quench steam line is there, close quench steam value.

Keep the water hose running while draining.

In case of high pour point material like RCO flush casing material with FLO..

If auxiliary oil pump is there, stop oil pump after cooling the main pump below

70° C.

NOTE:

Ensure pump casing liquid free by checking drain line and setting pump

pressure gauge.

If mech. Seal and pump bearing cooling water line is there, close cooling

water line value.

Isolate pump motor and its auxiliary power supply from sub-station.

Now pump is already for handing over to maintenance.

8.2 VESSELS

The vessels used in oil refineries are mainly for light/heavy hydrocarbons and some

chemicals. When the necessity arises for a person to enter into the vessel, the following

procedures should be followed:

Equipment is to be electrically isolated and tagged wherever necessary. It should

be ensured that electrical switches are locked out and properly tagged duly signed

with date and time.

Equipment to be isolated/closed disconnected. Vessel should be completely

isolated from other equipments, in order to ensure that there should be no change

in the work environment.

Equipment is to be properly depressurized/drained.

Vessel under pressure should be depressurized after isolation.

De-pressurization to be done by opening flare line B/V.

205

Keep some pressure 0.5 Kg/cm2 if vessel has heavy hydrocarbon for proper

draining.

If vessel contains hot material (>200° C) then drain after sufficient cooling.

Vessel to be drained in closed blow down.

Watch the level and pressure of CBD during draining.

Vessel having sour water and hydrocarbon the sour water to be drained O.W.S

To ensure the complete draining open OW&S line.

De-pressurize completely to flare if there was some pressure.

Vessels containing liquid/ light hydrocarbons should be drained completely by

opening all low point drains (L.P.D) of connected pippins, level gauges and stand

pipes etc. by unplugging the L.P.D.

Caustic should be drained / pumped to GRE CETP

Amine should be pumped out to SRU

Vessel to be disconnected/blinded/wedged open

Ensure complete draining.

Inlet/outlet any injection is there to be blinded/ Wedged opened and/or

disconnected.

Vent and utility system lines to be de-blinded.

1) Vessel to be properly steamed/purged.

Open saturated steam drain B/V for condensate draining.

Charge steam to the vessel minimum and watch the pressure.

Open all high point vent and drain points.

Open steam B/V as per requirement.

Open drain (vessel) to O.W.S.

Check the condensate for oil containments

Ensure complete removal of hydrocarbon by condensate checking.

If necessary stop steaming for sometime and re-charge the steam.

Vessel containing only gas purging can be done with inert gas, nitrogen.

Ensure venting/draining of steam from all H.P.V. as L.P.D. of level gauges, stand

pipes and other pipes.

2) Vessel is to be water flushed:

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Water flushing is an effective means of cleaning and cooling.

Vessel containing liquid hydrocarbon, hot water washing to be done.

Vessels metallurgy must be considered before using water for washing.

Hot water washing to be done by using steam and water.

Ensure proper draining of the vessel.

Observe for any abnormal sound (steam hammering) in the vessel

Reduce water and open drains sufficiently, if not opened fully.

Stop the water drains the condensate and watch for any oil or small of gas etc.

Start again water & steam and repeat 3/4 times till the clear condensate is not

coming.

Ensure complete hydrocarbon/chemical washed out.

Stop the steam.

Stop water after sufficient cooling.

Open top and side man-ways.

Put exhaust fan on top/side man ways (if required).

Utility steam line & N2 to be blinded.

Water hose to be disconnected.

3) Gas/Oxygen deficiency test to be done:

Check the vessel material, hydrocarbon or mud at the bottom.

Do gas (hydrocarbons) test by explosive meter.

Oxygen deficiency by oxygen meter.

Toxic gases like hydrocarbon sulphite, carbon monoxide, and chlorine etc. test to

be done by special techniques.

No hot work shall be permitted unless the explosive meter reading is zero.

Vessel entry where no hot job is to be carried out may be permitted if combustible

gases are up to 5% of lower explosive limit (LEL)

Vessel entry with an air-supplied mask may be permitted with LEL of 50%.

The oxygen level should be at least 19.5 vol% and the concentration of toxic

gases below the threshold limit

Proper ventilation and lighting provisions:

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Where natural (sufficient) ventilation is not available, fans/ air eductor, air hose to

be provided.

Only approved reduced voltage extension (24 volts) lights are to be provided for

work inside vessels.

Flood light to be provided outside of the vessels.

Proper means of exit to be provided:

Proper means of exit to be provided if an alternate route of escape not existing.

4) Precautionary tags/boards are to be provided.

To prevent any unwarranted entry in the work area precautionary tags/boards are

to be provided such as “No Entry” or “Caution-mean at the work Inside” on the

manhole of the vessel.

Iron sulphide to be removed/Kept wet:

The vessel containing light hydrocarbon and sour water may contain pyrophoric

substance.

Vessel to be kept wet with water.

Sludge to be removed along with water and kept wet until they are removed from

the site, at safe location.

Stand by person to be provided outside the vessel (minimum-2) near the man way.

All the above activities to be competed and vessel are cleaned with proper

precautions then man entry can be given for inspection and maintenance purposes.

8.3 COLUMN S

In petroleum refineries, this equipment is more prone to deposit pyrophoric substance.

Deposits of iron sulfide are formed from corrosion products that most readily accumulate

at the trays, pump around zones and structured packing. If these pyrophoric iron sulfide

(PIS) deposits are not removed properly before the columns are opened up, there is a

greater likelihood of PIS spontaneous ignition. The trapped combustible hydrocarbons,

coke, etc. that do not get adequately removed during steaming / washing often get

ignited, leading to fires and explosions inside the equipment. These fires not only result

in equipment damage but can also prove fatal for the personnel who are performing

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inspection and maintenance work inside the columns. This is entirely avoidable if safe

procedures for column handover are followed.

The targets of these procedures should be two fold:

First, to remove all the combustibles Second, to remove or neutralize pyrophoric iron

sulfide deposits. The steps to be followed are Column to be isolated/closed/disconnected:

Column should be completely isolated from other equipments piping etc. in order to

ensure that there should be no change in the work environment.

1) Steps for column de-pressurization/draining:

Column under pressure to be de-pressurized to flare after isolation.

De-blind the drain line to closed blow down (C.B.D).

De-cap the low point drain(L.P.D) and high point vents (H.P.V) as pipelines,

level gauges, stand pipes and other tappings connected.

Drain the column material to C.B.D.

Drain the pumps suction headers of draw-off products to C.B.D if provision is

not there then in O.W.S. and drain the other connected pipelines at L.P.D. through

hose connections to C.B.D or O.W.S.

Ensure complete draining by opening O.W.S. line. Close all drain B/V and watch

the column pressure and level, if any increase then again draining to be done,

Columns containing chemicals like caustic amine etc. to be drained in chemical

blow down (C. B.D.) vessel only.

Column to be disconnected/blinded/wedged open:

Ensure complete draining. De-blind top vent and utility steam.

2) Proper steaming and water flushing (hot water flushing and cold water flushing)

of column.

a) Steaming: The steaming is done after all liquid hydrocarbons have been

drained from the column and associated piping. The objective of steaming

is to make the column and associated piping free of residual hydrocarbons.

The column vent and pump strainers in the side draw piping are de-

blinded. Keep them open. Steam is introduce from utility connection

provided at bottom of the column. Venting to be done from column top

vent & condensate draining to be done at bottom product pump suction.

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Generally, steaming is done for about 20 to 24 hrs, ensuring the column

top temperature remains more than 100 °C throughout the operation.

Observe any abnormal sound (hammering) in the column.

b) Hot Water Washing: When clear steam is observed exiting the column

vents, water washing of the column should be started. With steaming is

on, water is pumped to the column, usually via reflux line, and it is

drained through the column bottom, from all product / CR draw pump

suction (via respective strippers) & associated piping etc., Columns

metallurgy must be considered before using water types (cooling water/

D.M. water) for washing. The water flow rate should be adjusted so that

steam still comes from the vent (i.e. water should not result in condensing

of all steam before it reaches the column top). Water flow should be

stopped for 2-3 hrs and then resumed. This cycle of steaming and washing

should be repeated several times for a total of about 15 to 20 hours.

c) Blinding: When clear water is observed at side draw pump strainers, etc.

stop hot water washing & get blind inserted in all associated piping as per

master blind list.

d) After blinding is over, steam the column for 8 hr.

e) Stop steaming & start cold Water Washing for 4 hr.:

f) Open all manholes.

g) Install exhaust fan/evacuator on top of the column.

h) Blind steam out point / water

3) Gas/Oxygen deficiency test is to be done

a) Check inside through man ways e.g. safety torch for any foreign

material/hydrocarbon/coke etc.

b) Do gas (hydrocarbon) test by explosive meter.

c) Oxygen deficiency test by oxygen meter.

d) Toxic gases like hydrocarbon sulphide, carbon monoxide, and chlorine etc. test to

be done by special techniques.

e) Column entry where no hot job is to be carried out may be permitted if

combustible gases are up to 5% of lower explosive limit. (LEL).

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f) Entry with an air mask may be permitted LEL of 50%

g) The oxygen level should be at least 1.5% by volume and the concentration of

toxic gases below the threshold limit.

h) No hot job shall be permitted unless the explosive meter reading is zero.

i) After man entry get open the trays man ways for inspection.

j) Open all the man ways.

k) Make arrangement inside column of rope ladder etc.

4) Proper ventilation and lighting to be provided

a) Where natural (sufficient) ventilation is not available fan/air ejector/air hose to be

provided.

5) Proper means of exit to be provided:

a) To prevent any unwanted entry in the work area precautionary tags/boards to be

provided such as “No Entry” or “Caution- manta work inside” on the manhole of

the column.

6) Stand by persons are to be provided outside the column (minimum-2) near the

man way. If above activities are completed, then column may be handed over for

inspection and maintenance work.

8.4 EXCHANGERS/COOLERS/CONDENSERS/REBOILERS

Isolate and bypass the exchangers/coolers/condenser/reboiler

Drain the content in CBD

Flush the equipment handling heavy material with FLO to CBD. Open the OWS

valve to ensure complete draining.

Provide blinds towards the exchanger on both the tube & shell side.

Give steam connection to the top vent. Steam flushing to OWS opening to be

done till the equipment is hydrocarbon free.

Water flush the coolers and condensers, which were handling light hydrocarbons.

Clearance is to be given to hand over for cleaning/maintenance job.

8.5 TANKS

Pump out tank material to OM&S respective tank till losses suction.

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Get Water hose connection from drain or through dip hatch and build up level for

pumping out more hydrocarbons. As far as possible, hydrocarbons are to be

pumped out.

Get tank’s inlet/outlet and other connected lines (except drain) blinded.

Drain tank content to OWS.

Get sky light cover and manhole opened.

Take further water inside the tank for over flowing of rest hydrocarbon through

manhole.

Overflowing to be continued till all hydrocarbon remove.

Check by explosive mater. If OK, then water to be drained out. Leave tank for air

circulation.

Check for explosives. If OK, hand over the tank for cleaning M & I job. If

explosivity is not OK, then repeat the overflowing by water more.

8.6 FURNACE

Shut down the furnace as per procedure and blind fuel gas lines.

Open the damper and air registers fully

Isolate and flush fuel oil circuit first with FLO and then with steam till it is

hydrocarbon free and blind fuel oil lines (I/L & O/L).

Open all manholes/ inspection holes of furnace.

Blind all steam as per blind list (box purging steam, atomizing steam, emergency

steam, soot blowing steam & Decoking steam)

When the box cools down to around 50 Deg. C,

De-energize ID / FDs.

Check for hydrocarbon & oxygen content inside furnace..

Give clearance for "MAN ENTRY" and maintenance jobs.

8.7 FLARE HEADER

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Ensure that all equipments connected with flare system are depressurized after

shut down.

Provide steam connection if not there at the furthest end of the system

Isolate all PSV/ lines connected to flare header..

Introduce steam & purge the system to flare for 4-hrs. & drain condensate from

KOD drain.

Reduce steaming to minimum & close flare header battery limit valve. Open U/S

bleeder of battery limit valve.

Give clearance to provide blinds /wedge opening at U/S

Open the drains and vents of all instruments and of knockout drum,

Increase steaming rate & continue for 8 hrs.

Stop steaming

Check hydrocarbon content with explosive meter.

Give clearance for maintenance jobs.

If man entry in KOD is involved carry out water washing after steaming. Blind

its I/L & O/L flange.

The muck coming out from flare system should be separately disposed off, as it is

likely to contain pyrophoric iron.

8.8 CONTROL VALVES

Bypass the control valve

Close up-stream and down-stream b/vs.

Drain c/v loop, Ensure isolation valves are holding.

Give clearance for removing the c/v.

End blind the open flanges

8.9 SAFTEY VALVES

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Take spare safety valve in line if provided.

Isolate the safety valve.

Ensure that isolation valves are holding by depressurizing the loop through LPD.

Give clearance to open the safety valve.

End blind the open flanges.

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CHAPTER-9

PROCEDURES FOR EQUIPMENT TAKING OVER FROM MAINTENANCE

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EQUIPMENT TAKING OVER FROM MAINTENANCE

If equipments are not properly checked while taking over from maintenance it may result

in accidents or give troubles during start-ups. Check the following items while taking

over any equipment from maintenance.

9.1 PUMPS/MOTORS:

Check that electrical cable and earthing connections are complete.

Ensure mechanical completion. See that coupling guard is in position.

Ensure cooling water, quenching steam and flushing oil lines are clear.

Pressure gauges should be in position.

Ensure that shafts is free to rotate.

Check that lines are blinded / deblinded as required for normal run.

Check all vents / drains are closed and capped / blinded.

9.2 EXCHANGERS / CONDENSERS / COOLERS / FIN COOLERS /REBOILERS

Ensure the following:

Tube and shell cleaning is proper.

Leaky tubes are plugged / replaced.

Shell is painted as per inspection.

Exchanger is properly as per inspection.

Check for short bolting.

All flanges gasket that were opened during maintenance are replaced by new

gaskets.

Bull plugs, thermo wells, pressure gauge assemblies, PSV/TSV's are in position.

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Insulation is complete.

Fan belts and covers are in position, in case of Fin coolers.

All flanges are deblinded.

Electrical /earthing connections are complete.

9.3 FURNACE

Ensure the following:

Heater tubes are cleaned

All foreign material is removed from the fire box.

Skin thermocouples / oxygen analyser and other instrument are in position.

All tubes ( convection / radiation) are properly cleaned.

Man ways, explosion doors, peep holes, header box covers are boxed up.

Stack damper operation is smooth and damper's open / close position indicators

are correct.

Operation of all burner valves is satisfactory.

Burner alignment is correct.

Blinding / de-blinding is done as per the master blind list.

Steam and oil connections to the individual burner gun are correct.

Area around the furnace is cleaned.

9.4 VESSELS

While taking over vessel from maintenance check and ensure the following:

Vessel is thoroughly cleaned.

No foreign material is left inside.

Drain points and instrument tap are clear.

Vessel's internals including instrument are in their respective positions and

properly secured. Demister pads are in position.

Vessels is coated /painted as per inspection report. Take clearance from

inspection.

If all the above things are satisfactory give clearance to box up the manhole.

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Manhole should be boxed up on four bolts in presence of production staff.

Remove the blinds as per master blind list.

Connect the blinds as per master blind list.

Line-up all safety valves.

Vessel is ready for service.

Cap / blind drain / vents.

9.5 COLUMNS

Check the following:

Inspect tray man-way box up and properly bolted

The tray decks below the manhole are clean and free of foreign material.

Temporary connections are removed.

All instrument tapings drain points, distributors, down-comers, inlet and outlet

nozzles are clear.

All internals as fitted properly.

All inside fittings like distributors, thermo wells, flats of level indicator, etc are in

position.

Tray man way covers are boxed up.

Manholes are boxed up on 4 bolts while ensuring that nobody is left inside

Tray man way and manholes should be boxed up in presence of production staff.

All man way covers are boxed up as above with new gasket.

Blinding /de-blinding is complete as per master blind list.

NRV's are installed in their proper direction

Column bottom drains are connected properly & are clear.

Safety valve are installed and lined up.

The instruments are in their respective position.

The column is ready for service.

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CHAPTER-10

SAFETY

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SAFETY

10.1 FIRE PREVENTION ACTIVITIES:

Regulation for the prevention of fire:

1) Ban on carrying of a potential source of ignition, ban on lighting fires in battery area.

Ban on smoking, Ban on carrying lamps, use of spark arrestors.

2) General precautions:

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Maintain good house keeping. Follow the laid down procedure strictly. Sampling and

draining of hydrocarbon should be done under strict supervision. Do not operate

equipment unauthorized. Use only approved type of tools, anticipate the hazards during

vessel cleaning and take preventive step in advance.

10.2 FIRE PREVENTION ACTIVITIES

Fire prevention can be best achieved with the application of:

10.2.1 SOUND ENGINEERING:

Design of the plant materials used for construction means of escape etc.

10.2.2 GOOD HOUSE KEEPING:

Cleanliness of the plant, methods of storage.

Good habits: observation of fire prevention rules etc.

Common sense: No smoking near inflammable material etc.

10.2.3 INSTRUCTION TO PERSONNEL

Knowledge of job.

Safe practices.

Action in case of fire.

Knowledge of fire extinguishers etc.

10.2.4 REGULAR TRAINING OF EMPLOYEES

Induction training program.

Refresh course.

Special listed training programmes.

10.2.5 SAFETY AUDITS

1) INTERNAL 2) EXTERNAL

VARIOUDS SAFETY STUDIES:

Ex. Risk analysis hazop, hazan, etc. prior to commissioning of any plant or equipments.

COMPLIANCE OF STAUTORY REQUIREMENTS:

INSPECTIONS:

To check for proper placement and operation of fire protection equipment and seek

correction of common fire causes, such as poor housekeeping improper storage of

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flammable materials, smoking violations and excessive accumulation of dust of

flammable material.

10.2.6 FIRE EMERGENCY MOCK DRILLS

An emergency manual can be prepared to outline procedures and drills and detail

responsibilities of each individual involved.

Training

Valuable check on the adequacy and condition of exits and alarm system.

Instills a sense of security among the occupiers if careful plans are made.

Exit drills.

Plant drills (mock drills in plant area).

Mutual aid drills.

On-site/off site drills etc.

10.3 FIRE PROTECTION SYSTEM IN REFINERY

FIRE STATION:

Our refinery has two fire stations. Equipped with all modern equipments & trained man

power.

COMMUNICATION:

Ex-telephones: Fire call numbers 7333 & 63333, Hot lines for communicating mutual aid

member, P.A., paging, walkie-talkie system fire alarm: By breaking the glass of any of

the alarm located in the refinery area: At GR-62 nos. & at GHS-53 nos. Sirens 11 nos. at

various locations.

FIRE PROTECTION:

Following fire protection facilities provided depending upon/risk of the installation:

FIRE WATER SYSTEM:

Fire water storage – 22,400 M3.

Fire water pumps – 8300 M3/hr.

Distribution piping network- approx. 50 Km.

Hydrants (around 1000)

Monitor around (400)

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Water spray system (Oil tanks & hydrocarbon pump houses) LPG area as per OISD-116.

FOAM SYSTEM:

Semi fixed: Provided an oil storage tanks. Railway gantry no.6

Mobile: Foam tenders 5 Nos. & foam nurser:1

MOBILE FIRE FIGHTING EQUIPMENTS:

Foam tender: 5

DCP tender: 1

Emergency tender: 1

Foam nurser: 1

CARBONDIOXIDE PROTECTION SYSTEM:

Turbines and generators in power plants

FIRST AID FIRE FIGHTING EQUIPMENT:

First team comprising of operation/maintenance staff at site & any other refinery person

available at site this persons will handle the situation till the arrival of trained fire fighter

with the help of.

PORTABLE FIRE EXTINGUISHERS:

Dry chemical powder, foam, Water type, CO2, halon

10 Kg: 2000 Nos., 25 Kg Trolley mounted: 100 Nos. DCP Trolley mounted 75 Kg.

175 Nos. Foam type Trolley mounted 45 lts : 30 Nos.

FIRE FIGHTING TEAM:

First main team comprising of shift in-charger of fire stations & fire operators on duty

with fire fighting equipments and officers from fire and safety & CISF personnel.

Second main team: Fire operators (Re-enforcement), CISF staff(reserve as well as on

duty except for gate staff), fire fighting crew from external sources (like neighboring

industries , BMC etc.)

10.4 FIRE PROTECTION SYSTEM IN THE UNIT

A. Fire extinguisher: 200 NOS.(10 kg DCP)

B. Fire glass: 20 NOS.(25 kg DCP)

C. Fire water monitors: from all four sides.

and hydrants

D. Tower platform monitors: 3 NOS.

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E. Water sprinkler system: in pump house and at

Caustic/water vessels and on fin coolers.

F. Hydrocarbons gas detector, near P-5A/B,P-6A/B, P-14A/B, P-50A/B,

PA- 07A/B

G. Safety shower and eye washer: 2 No.

(Near caustic tank, near furnace)

H. Riser hydrant: A) at vessel platform

B) all columns.

10.5 WORK PERMIT SYSTEM

Work permit is a written document that categorically spells out

The task.

Equipment involved & its condition.

Its location.

Personnel involved.

Time limitation

Precautionary measure to be taken together with likely hazard to be encountered,

if any.

Act as a predetermined checklist for various safety precautions.

Serves as a media of information.

Instills a sense of security from accident.

Work permit system is required in the refinery as per, Sec.7(2a) SSW

OISD-105

Rule 172 of petroleum rules, 1976

OBJECTIVE:

To make the procedure of the work foolproof.

To guarantee against accidental starting of machinery or entry of

any hazardous liquid or gas into a vessel whose jobs are proposed.

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10.5.1 TYPES OF WORK PERMITS:

10.5.1.A HOT WORK PERMIT

Hot work permit is issued for an activity, which may produce enough heat to ignite a

flammable substance i.e. welding, gas, cutting etc.

10.5.1.B COLD WORK PERMIT

Cold work is an activity, which does not produce sufficient heat to ignite a flammable air

hydrocarbon mixture or a flammable substance.

10.5.1.C EXCAVATION PERMIT

For Excavation Permit clearance is required from other

departments i.e. electrical, Instrumentation & civil.

Every excavation shall have a safe access way.

No one is permitted to excavate if any equipment is working next

to the edge of expected excavated area.

If the depth of excavation is more than 1.5 meters, one ladder

shall be provided for every 20 meters of length.

Adequate number of persons should be made available outside the

pit for rescue purpose in case of any emergency.

No job is permitted in a pit after sun set.

10.5.1.D WORK AT HEIGHT PERMIT

Whenever any worker is engaged on work at a place from which he is liable to fall more

than 2 meters, he shall be provided with a safety belts equipped with life-lines, which are

secured with a minimum of stakes to a fixed structure of anyother effective means.

Helmet shall also be used.

10.5.1.D WORK AT DEPTHS

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For entry into confined spaces permit is a must. The intent of an entry permit is that all

necessary measures are taken to protect entering personnel against such hazardous as

oxygen deficiency, hazardous gases, contamination, high temperatures, fire and difficulty

in escaping etc and also to make sure that all concerned are well informed of the job in

progress so that they can avoid hazardous operations connecting to the proposed work

site.

10.5.1.F ELECTRICAL WORK PERMIT

Before issuing any permit to the Maintenance or Engineering personnel for any

maintenance work on any equipment, the shift in charge of the production department

must ensure that electrical isolation has been obtained from the concerned electrical

supervisor. No permit for the work will be issued unless the electrical isolation has been

obtained.

10.5.1.G VESSEL ENTRY PERMIT

No hot work shall be permitted unless the explosive meter shows

zero.

Vessel entry, where not hot work is to be carried out, may be

permitted if combustible gases are up to 5% of lower explosive

limit. (LEL).

Entry with an air-supplied mask may be permitted with LEL upto

50%.

The oxygen level should be at least 19.5 vol% and the

concentration of toxic gases below the threshold limit.

10.5.2 RESPONSIBILITIES OF THE PERMITTEE:

A permittee is a supervisor in charge for the particular maintenance of the equipment or a

system requiring such maintenance. He is required to ensure scruples compliance of the

instructions mentioned in the permit and make available to his person’s, fire and safety

equipment etc. required for the job.

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10.5.3 RENEWAL OF THE PERMIT:

Normally the permit is issued for seven days only. However, if the removal is required to

be taken if should be distinctly understood that renewal or revalidation has to be done by

the authority who is competent to issue of permit after ensuring all necessary checks as

for a fresh permit. The renewal is to be recorded on all the copies of the permit.

10.5.4 SURENDERING OF THE PERMIT:

After the maintenance job is over, the permittee should fill up the permit and handover

the same to the permit issuing authority (issuer) as taken of having completed the job and

surrender the permit. Permittee must also ensure that all the tools, tackles & safety and

fire fighting equipment are removed from the site and the area cleaned to avoid accidents.

10.5.5 SIGNATORIES FOR FIRE PERMITS:

For any Hot work / Vessel Entry or Excavation permit on any holiday / Sunday and

extended hours working, approval / clearance of HOD of that area along with clearance

from RSM in each shift is essential.

For any cold work on Holiday / Sunday and for extended hours working, approval /

clearance of Manger / Sectional head is essential.

For Tank Dyke cutting approval / clearance of HOD is essential.

10.5.6 COPIES OF PERMIT:

1) Following persons / department shall keep a copy of work permit.

a) Person doing the job and shall make the permit available at site.

b) Area in-charge

c) Fire Station.

2) After completion or stoppage of the job, the person to whom the permit was issued,

should throughout by check the area for clearing of debris, removal of temporary

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electrical installations etc and then sign the work permit and return it to the issuer

who in turn will keep it stored for future reference.

10.5.7 POINTS TO BE ENSURED WHILE GIVING CLEARANCE:

1) Equipment / Area inspected.

2) Surrounding area checked / cleaned.

3) Sewers, Manholes, CBD etc and hot surfaces covered.

4) Consider & ensure no hazard from other routine / non-routine operation and alters

surrounding / concerned persons.

5) Equipment electrically isolated and tagged.

6) Running water hose/ portable extinguisher provided.

7) Equipment blinded / disconnected / closed / isolated wedged open.

8) Equipment properly drained / depressurized, steamed / purged.

9) Firewater system checked for readiness.

10) Equipment water flushed.

11) Gas / oxygen deficiency test done and found OK.

12) Shield against sparks provided.

13) Proper ventilation and lighting provided.

14) Proper means of exit provided.

15) Precautionary tags / boards provided.

16) Portable equipment / Hose nozzles properly grounded.

17) Standby personnel provided for fire watch from process / maintenance /

contractor / fire and safety department.

18) Iron sulfide removal / kept wet.

19) Area cordoned off.

20) Precautions against public traffic taken.

21) Clearance obtained for excavation / road cutting from technical / fire / concerned

departments.

22) Clearance obtained for dyke cutting.

23) Checked spark arrestors on mobile equipment.

24) Checked for oil / gas trapped behind lining in equipment.

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25) Check for hot tapping.

Note: For further details refer Refinery safety manual kept in Control room.

10.5.8 ACCIDENT REPORTING PROCEDURE:

With a view to timely transmission of the information or submission of the notice of the

accident to the inspector of Factories within the stipulated time prescribed under rule 103

of Gujarat Factories Rule, 1963 the following procedure has been followed by Gujarat

Refinery.

Any accident, however, small to an employee is reported to HOD supervisor/ shift-in-

charge. When the injured is not in a position to report himself, such reports are made by

anybody present at the site of the accident.

As soon as the supervisor gets the information, he arranges for the ambulance from the

hospital and also informs the following :

Fire station

Hospital

Sectional/department head

Refinery shift Manager.

The supervisor also fills the accident from no. A-1 in triplicate. The original copy of the

form is sent along with the injured to hospital. The medical officer on duty examines the

injured employee, if the nature of the injury is such that the injured person requires rest

for more then 48 hours. A lost time accident report is prepared by the medical officer in

the form A-II and sent the same to fire and safety department. The medical officer

indicated the probable days of rest required by the injured person.

On receipt of the Medical officer report, the personal department informs the factory

inspector as required under the provisions of factories act 1948 and Gujarat factory rules

1963. After receiving form A-II from the fire and safety section in form no.21. One copy

is sent to fire and safety section and third is retain by the personal department.

Medical Fitness Certificates : Form No. A-II

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In a case the injured person is fit to resume duty immediately after first aid or after taking

rest for some time (before the end of the shift) he will be allowed to resume the duty

accordingly.

In case the injured person is likely to become disabled for 24 hrs. or more he shall be

marked as on “Accident leave” and is allowed to join duty on production of fitness

certificates form A-III to Fire & Safety section, personal Department, Time office and the

concerned section. The medical officer concerned shall send the copies of form A-III to

the fire & safety department, personal department and the concerned department. In case

the employee has developed any permanent disability the medical office assess the

disablement of the injured person on the form A-IV and sends the report to Personal

Department, Fire & Safety Section, Accounts Department and the concerned section.

The Personal Department, on receipt of the joining report of the injured person the

recommendation of the Department Head and the report of the Medical Department of

form A-IV, shall take action for the payment of leave wages and compensation if due by

issuing necessary memos to the Account Department.

FATAL INJURIES:

In case of fatal injury, the statutory obligation says that the situation when the accident

occurred should remain as far as possible undisturbed till arrival of police. Therefore,

with the exemption of removing the casualty from the scene of accident this requirement

is strictly observed and following persons are immediately informed:

General Manager/Executive Director

Chief Medical Officer

Manager (Fire & Safety)

Chief Human Resources Manager

Personal department immediately informs them relatives of the injured. Police and

Inspector of factories:

INVESTIGATION REPORT:

In case of any accident, whether minor or of lost time nature, the supervisor will arrange

to send an investigation report to the fire and safety department and the concerned

department head on form number A-V within 48 hours of the accident.

230

10.5.9 MATERIAL SAFETY DATA SHEET (MSDS)

10.5.9.1 AHURALAN

AHURALAN ESK 50

1) CHEMICAL IDENTITY

Chemical Name Corrosion Inhibitor Chemical Classification

Long chain fatty amine derivative

Synonyms Corrosion InhibitorTrade Name

Ahuralan ESK 50

Formula R1NHR2NHR3RH4

C.A.S. NO. 5285-60-9 UN NO.

RegulatedIdentification

Shipping Name: Codes/LabelHazardous waste: I.D. No. Hazchem Code

Ahuralan ESK 50

Hazardous ingredients

C.a.s. No. Hazardous ingredients

C.a.s. No.

Ahuralan ESK 50

5285-60-9

2) PHYSICAL AND CHEMICAL DATA

Boiling Point/ Range oCMelting/ Freezing Point oC

150 - 300

<10

Physical State

Vapour pressure@ 35 oC, mm Hg

Liquid

< 1 mmHg @ 68oF

Appearance

Odour

Viscous, Yellowish brown Pungent

Vapour Density(Air = 1)

Solubility in water @ 30 oC

Insoluble Solubility in others

Specific Gravity(Water = 1)

0.83 pH Not applicable

3) FIRE AND EXPLOSION HAZARD DATA

231

Flammability

TDG Flammability

Moderate

3

LEL (%V)

UEL (%V)

0.7

5.0

Flash Point (OC) oC

Flash Point, (CC) oC 37 – 66

Auto ignition Temperature oCExplosion Sensitivity to ImpactExplosion Sensitivity to Static ElectricityHazardous Combustion productsHazardous Polymerization

228

CO, CO2

Combustible Liquid

Yes Explosive Material

No Corrosive Material No

Flammable Material

Yes Oxidiser No Others

Pyrophoric Material

No Organic Peroxide No

4) REACTIVITY DATA

Chemical StabilityIncompatibility with other material

StableNone

ReactivityHazardous Reaction Products

5) HEALTH HAZARD DATA

Routes of Entry Inhalation, ingestion, contact

Effects of Exposure/ InhalationSymptomsIngestion

Contact

Emergency Treatment Obtain immediate medical attention.

232

Inhalation Remove affected person to fresh air. If respiratory problems develop.

Ingestion Do not induce vomiting.Contact Skin Contact : Apply a generous amount of waterless

hand cleaner (such of GOOP, Gojo or similar product) to the affected area. Rub briskly onto the skin, on and around the affected area. Remove the mixture of cleaner-product with paper towels or clean dry rags. Repeat the entire procedure, then was the skin with a mild soap, rinsing with warm water. Eye Contact: Flush with water for at least 15 mins. If irritation occurs.

LD50 (Oral-Rat), mg/kg

LD50 , mg/kg

Permissible mg/kgExposure Limit ppm

Odor Threshold, ppm mg/kg

TLV (ACGIH) ppm mg/kg

STEL, ppm mg/kg

NFPA Hazard Signals Health Flammability Reactivity/Stability

Special

6) PREVENTIVE MEASURES

Personal Protective Equipment

Gloves, footwear, coveralls, and/or apron as necessary to prevent repeated or prolonged skin contact. Any clothing, which becomes wet with product should be removed immediately and laundered before reuse.Chemical goggles or face shield as necessary to prevent eye contact.

Handling and Storage Precautions

Store in tightly closed, properly labeled containers in a cool, well ventilated area away from all ignition sources. Store out of direct sunlight. Wear appropriate personal protective equipment. Avoid inhalation of product vapors or mist. Never use a welding or cutting torch on or near a drum (even empty) because vapours from the material (even residue) can ignite explosively. Follow all MSDS/label precautions even after container is emptied because it may retain product residue.

7) EMERGENCY AND FIRST AID MEASURES

FIRE Fire Extinguishing MediaSpecial

Use water fog, foam, dry chemical powder, CO2

Use water to cool fire exposed components.

233

ProcedureUnusual Hazards

EXPOSURE

First Aid Measures

Antidotes/ Dosage

Obtain immediate medical attention.

Inhalation : Remove affected person to fresh air. If

respiratory problems develop.

Ingestion : Do not induce vomiting. Skin Contact : Apply a generous amount of waterless hand cleaner (such of GOOP, Gojo or similar product) to the affected area. Rub briskly onto the skin, on and around the affected area. Remove the mixture of cleaner-product with paper towels or clean dry rags. Repeat the entire procedure, then was the skin with a mild soap, rinsing with warm water. Eye Contact : Flush with water for at least 15 mins. If irritation occurs.

SPILLS Steps to be taken

Waste Disposal Method

Standard hydrocarbon spill procedures apply to this

product. Remove all sources of ignition. Isolate the

affected area. Confirne entry into the affected area to

those persons properly protected. Stop leak at the source.

Cut off and redirect surface runoff by trenching of diking.

Spills should be contained through the use of commercial

oil adsorbent, but other materials such as earth, sand or

sawdust may be more expedient to limit the extent of the

spill. Prevent the release of this product into the waterway

or sewer. To prevent further losses, reposition, plug or

place the leaking container into an oversized recovery

drum/container.

Wear protective equipment. Absorb spilled product using a

commercial oil absorbent soaking up as much product as

possible.

234

10.5.9.2 AMMONIA

AMMONIA

1) CHEMICAL IDENTITY

Chemical Name: AMMONIA Chemical Classification : Inorganic Compound

Synonyms: Liquid Ammonia, Ammonia Gas, Trade Name: Ammonia Ammonia Anhydrous.

Formula: NH3 C.A.S.NO: 7664-41-7 UN NO. 1005

Regulated Shipping Name : AmmoniaIdentification Codes/Label: Non Flammable Gas, Class 2 Hazardous waste I.D. No: 17 Hazchem Code : 2 PEHAZARDOUS INGREDIENTS C.A.S.NO. HAZARDOUS INGREDIENTS C.A.S.NO.

1. Ammonia 7664-41-7 2.

2.PHYSICAL AND CHEMICAL DATA

Boiling Point/Range -33.4oC Physical State : Liquefied Compr.Gas Appearance : Colourless Vapour pressure @ 35oC 7600 mm Hg at 25.7oC Odour : Strong Pungent Odour Melting / Freezing -77.77oC Point ___________________________________________Vapour Density 0.60 Solubility in water @ 30oC Others (Air = 1) Very soluble Moderately soluble in Alcohol

Specific Gravity 0.771 pH: I N aq. Sol. 11.6(Water = 1) @ 0oC

3.FIRE AND EXPLOSION HAZARD DATA

Flammability No LEL 16.0 % Flash Point oC Not Pertinent (OC)TDG Flammability NA UEL 25.0 % Flash Point oC Not Pertinent (CC)Auto ignition Temperature oC 651.0Explosion Sensitivity to Impact StableExplosion Sensitivity to Static Not availableElectricity

235

Hazardous Combustion products Emits toxic fumes of NH3 & NOx

Hazardous Polymerization Does not occur.Combustible Liquid Yes Explosive Material No Corrosive Material No

Flammable Material No Oxidiser No OthersPyrophoric Material No Organic Peroxide No

4.REACTIVITY DATA

Chemical Stability Stable

Incompatibility with Strong Oxidisers, Calcium hypochlorite, Gold, Mercury, Silver, Halogens,Other material Acetaldehyde, Acrolein.

Reactivity Reacts with Silver chloride, Silver nitrate, Silver azide, chlorine, bromine, iodine, heavy metals and their compounds, Incandescent reaction when heated with Calcium.

Hazardous Reaction Reacts with Silver chloride, Silver nitrate, Silver Azide and Silver OxideProducts form explosive silver nitride.

5.HEALTH HAZARD DATA

Routes of Entry Inhalation, Skin or EyesEffects of Exposure/ Symptoms: - 700 ppm causes eye irritation and permanent injury may result if prompt medical remedial measures are not taken. 5000 ppm may cause death fromspum inflammation, or edema of the larynx. Contact of the liquid with skin freezes the tissues and causes the caustic burns.

Emergency Treatment Inhalation:- Remove the victim to fresh air and provide artificial respiration or oxygen, if needed. Skin and Eyes : Wash the affected area with plenty of water for 15 mins. Seek Medical Aid.Permissible Exposure Limit 25 ppm 18 mg/m3 Odour Threshold 46.8 ppm 32.53 mg3

L.D50 (Oral-Rat) 350 mg/kgTLV (ACGIH) 25 ppm 18 mg/m3 STEL 35 ppm 27 mg/m3

NFPA Hazard Signals Health Flammability Reactivity Special 2 1 0

6.PREVENTIVE MEASURES

Personal Protective Equipment: - Avoid contact with liquid or vapors Provide rubber boots, safety goggles, self-contained breathing apparatus, gas mask and protective clothing in case of liquid ammonia.

Handling and Storage Precautions: -Avoid storing along with oxidizing materials and away

236

from all possible sources of ignition. Store in well ventilated flame resistant locations.

7.EMERGENCY AND FIRST AID MEASURES

FIRE Fire Extinguishing Media Stop flow of gas. Use water spray or fog.

Special Procedure Keep the containers cool by spraying water if exposed to heat or flame.

Unusual Hazards Gas is suffocating.

EXPOSURE First Aid Measures Inhalation : Remove the victim to fresh air area, provide artificial respiration or oxygen, if needed.Skin : Remove the contaminated clothes and wash the affected area with plenty of water and soap.

Eyes : Flush with plenty of water for 15 mins. Seek medical aid. Antidotes/Dosages Not available.SPILLS :- Steps to be taken Contain leaking liquid on sand or earth, allow to evaporate. Dilute the vapors with plenty of water.

Waste Disposal Method :- Put into a large vessel containing water, neutralize with HCl And discharge into sewer with sufficient water.

8.ADDITIONAL INFORMATION/REFERENCES

A human poison by an unspecified route. Difficult to ignite. NH3 and air in a fire, can detonate. Potentially violent or explosive reactions on contact with interhalogens. Forms sensitive explosive mixture with air and hydrocarbons. Those affected with eye and pulmonary diseases should avoid exposure to Ammonia.

237

10.5.9.3 CAUSTIC SODA

CAUSTIC SODA

1.CHEMICAL IDENTITY

Chemical Name: SODIUM HYDROXIDE Chemical Classification : Alkaline Inorganic Compound

Synonyms: Caustic Soda, Soda Lye, Lye, Sodium Hydrate Trade Name : Caustic soda

Formula NaOH C.A.S.NO. 1310-73-2 UN. No. 1823 / 1824

Regulated Shipping Name : Sodium Hydroxide, Solid / SolutionIdentification Codes/Label : Corrosive, Class-8

Hazardous Waste I.D. No: 16

Hazchem Code : 2 R HAZARDOUS INGREDIENTS C.A.S.NO. HAZARDOUS INGREDIENTS C.A.S.NO.

1. Sodium Hydroxide 1310-73-2


Boiling Point/Range oC 1390 - 1557 Physical State : Solid Appearance : White Flakes / Pellets Melting / Freezing oC 318.4 - 322 Vapour pressure Odour: Odourless Point @ 35oC 1 mm Hg at 730 oC

Vapour Density Not Pertinent Solubility in water @ 30 oC Others: Soluble in Alcohol, Methanol (Air = 1) Soluble and Glycerol.

Specific Gravity 2.12 pH 13 - 14 (Water = 1) at 24oC/4 oC

3.FIRE AND EXPLOSION HAZARD DATA

238

S.C GUPTA, 01/03/-1,

Page: 1

Flammability No LEL Not pertinent Flash Point oC (OC) TDG Flammability N.A. UEL Not pertinent Flash Point oC (CC)

Auto ignition Temperature oC Not Pertinent Explosion Sensitivity to Impact Stable Explosion Sensitivity to Static Stable ElectricityHazardous Combustion products Emits toxic fumes of Na2O. Hazardous Polymerization Will not occurCombustible Liquid No Explosive Material No Corrosive Material Yes Flammable Material No Oxidiser No OthersPyrophoric Material No Organic Peroxide No

4.REACTIVITY DATAChemical Stability Stable

Incompatibility with Water, Acids, Flammable Liquids, Organic halides, metals, A1, Sn, Zn, Nitromethane other material. and Nitro Compounds. Reactivity Vigorous reaction with Organic Halides, Metals, Nitro Compounds. Hazardous Reaction Not available. Products


Routes of Entry Inhalation, Skin, Ingestion & Eyes. Effects of Exposure/ Inhalation : Causes small burns to upper respiratory tract & lungs, mild nose Symptoms irritation. Ingestion : Causes severe damage to mucous membrane, Severe scaring or perforation may occur. Eyes: Severe damage. Skin: Causes severe burns.Emergency Treatment Inhalation: Remove the victim from exposure. Support respiration, give oxygen, If necessary.

239

Ingestion: Give water or milk followed by dilute vinegar or fruit juice. Do not Induce vomiting.` Skin: Wash the affected area with plenty of water and soap. Eyes: Wash with plenty of water for 15 mins. Seek medical aid immediately.L.D50 (Oral-Rat) Not listed mg/Kg L.D50

Permissible - ppm 2 (Ceiling) mg/m3 Odour Threshold Odourless ppm Odourless mg/m3

Exposure Limit TLV (ACGIH) - ppm 2 (Ceiling) mg/m3 STEL Not listed ppm Not listed mg/m3

NFPA Hazard Signals Health Flammability Reactivity/Stability Special 3 0


Personal Protective Avoid contact with solid or liquid. Equipment. Provide side covered safety goggles, face shield, filter or dust-, type respirator, rubber shoes and rubber hand gloves.

Handling and Storage Keep in a cool, dry and well ventilated place. Precautions

7. EMERGENCY AND FIRST AID MEASURES

FIRE Fire Extinguishing Media Not FlammableSpecial Procedure Keep the containers cool by spraying water if exposed to heat or flame, Unusual Hazards Toxic gases are produced . . EXPOSURE First Aid Measures If eyes are affected, flush with plenty of water for 15 mins. Skin: Remove contaminated clothes & shoes.Wash the affected area with plenty of water. If inhaled, remove the victim to fresh air area. Support respiration. Seek medical aid immediately for all types of exposures. Antidotes/Dosages Not available. SPILLS: Steps to be taken : Sweep and collect without making dust. Wash the surface with plenty of water and soap. Waste Disposal Method :Put into a large vessel, neutralise with HCl and drain into sewer with abundant water.

8.ADDITIONAL INFORMATION/REFERENCES

240

A strong base. Vigorous reaction with 1, 2, 4, 5-Tetrachlorobenzene has caused many industrial explosions & forms extremely toxic 2, 3, 7, 8 – Tetra-chloro-di-benzodioxin. Under proper conditions of temperature, pressure and state of dilution, it can react or ignite violently with Acetic Acid, Acetaldehyde, Acetic Anhydride, Acrolein, Acrylonitrile, Allyl Alcohol, Allyl Chloride.

241

10.5.9.4 DIETHANOL AMINE

DIETHANOL AMINE

1.CHEMICAL IDENTITY

Chemical Name Di-ethanol amine Chemical Classification

Organic compound, amine

Synonyms DEA, 2,2-Iminodiethanol Trade Name DEA

Formula H(NCH2 CH2 OH)2 C.A.S. NO. 111-42-2 UN NO.


Shipping Name

Codes/Label

Hazardous wasteI.D. No.

Hazchem Code

Di-ethanol amine

17

2T

HAZARDOUS INGREDIENTS

C.A.S. NO. HAZARDOUS INGREDIENTS

C.A.S. NO.

1. Diethanolamine 111-42-2


Boiling Point/ Range oC

Melting/

269.1(decomposes)

28

Physical State


Liquid Appearance

Odour

Fainlty coloured

Ammonia

242

Freezing Point oC


3.65 Solubility in water @ 30 oC

Solubility in others


1.0919 pH

1. FIRE AND EXPLOSION HAZARD DATA

Flammability

TDG Flammability

Slight LEL (%V)

UEL (%V)

Flash Point (OC) oC

Flash Point, (CC) oC

148.89

151.6

Auto ignition Temperature oC

Explosion Sensitivity to Impact

Explosion Sensitivity to Static

Electricity

Hazardous Combustion products

Hazardous Polymerization

662

Does not occur.

Combustible Liquid


No Corrrosive Material

No

Flammable Material


Pyrophoric Material


2. REACTIVITY DATAChemical StabilityIncompatibility with other material

StableOxidising materials

ReactivityHazardous Reaction Products

3.HEALTH HAZARD DATARoutes of EntryEffects of Exposure/ Symptoms

Inhalation/ingestion/contac

Diethanol amine has been characterized as being of low

toxicity. Acute toxicity shows that direct contact may

impair vision and denature skin. DEA is an irritant to the

243

eyes and has caused liver and kidney damages in animals.

Emergency Treatment (IMMEDIATE MEDICAL ATTENTION REQUIRED)CONTACT : Remove victim to fresh air. Remove contaminated clothing Wash affected part with plenty of water for at least 30 mins.INGESTION : Give plenty of water to conscious victim to drink and induce vomiting.


2.83 LD50 , mg/kg


Odor Threshold, ppm mg/kg


3 STEL, ppm mg/kg

NFPA Hazard Signals Health1

Flammability1

Reactivity/Stability0

Special

4.PREVENTIVE MEASURESPersonal Protective Splash proof goggles, rubber gloves and rubber boots.Handling and Storage Precautions

5.EMERGENCY AND FIRST AID MEASURES

FIRE Fire Extinguishing Media

Special Procedure

Unusual Hazards

Foam, CO2, DCP, Water spray

Use water spray, dry chemical, foam or carbon-dioxide. Water or foam may cause frothing. Use water to keep fire exposed containers cool. Water spray may be used to flush spills away from exposure.

EXPOSURE

First Aid Measures

Antidotes/ Dosage

IMMEDIATE MEDICAL ATTENTION REQUIRED.Remove victim to fresh air. Remove contaminated clothing Wash affected part with plenty of water for atleast 30 mins.Give plenty of water to conscious victim to drink and induce vomiting

SPILLS Steps to be taken

Waste Disposal Method

244

10.5.9.5 DEMULSIFIER

DEMULSIFIER

1.CHEMICAL IDENTITY

Chemical Name Demulsifier Chemical Classification

Mixture of organic compounds

Synonyms Blend of Ethoxylated Block Co-Polymer, Resin, Wetting Agent and Surfactant in Aromatic Solvent

Trade Name Demulsifier

Formula C.A.S. NO. UN NO.


Shipping NameCodes/LabelHazardous wasteI.D. No.Hazchem Code

Demulsifier

HAZARDOUS INGREDIENTS

C.A.S. NO. HAZARDOUS INGREDIENTS

C.A.S. NO.

1. Petroleum solvent

2. Aromatics


Boiling Point/ Range oC

Melting/ Freezing

Physical State


Liquid Appearance

Odour

Dark Brown

245

Point oC


Solubility in water @ 30 oC

Dispersible Solubility in others

Aromatic solvent, kerosene


0.92 0.02 at 25oC pH 6.0 to 7.0

3. FIRE AND EXPLOSION HAZARD DATA

Flammability

TDG Flammability

Yes

3

LEL (%V)

UEL (%V)

Flash Point (OC) oC

Flash Point, (CC) oC >93

Auto ignition Temperature oC

Explosion Sensitivity to Impact

Explosion Sensitivity to Static Electricity

Hazardous Combustion products

Hazardous Polymerization

CO, CO2

Does not occur.Combustible Liquid


No Corrosive Material

No

Flammable Material


Pyrophoric Material


4.REACTIVITY DATAChemical Stability

Incompatibility with other material

Stable

Reactivity

Hazardous Reaction Products

246


Routes of Entry Inhalation, contact

Effects of Exposure/ InhalationSymptoms

May cause headache and nausea.

Ingestion

Contact

Nausea, vomiting. If retained leads to symptoms of

central nervous system depression.

Skin : Dermatitis,

Eyes : Irritation

Emergency Treatment Medical attention is required.

Inhalation Move to fresh air. If breathing is difficult give oxygen and call for physician.

IngestionContact Skin : Flush with large amount of water for 15 minutes.

Eyes : Immediately flush eyes with large quantities of water for at least 15 minutes.


LD50 , mg/kg


50 mg/m3

10Odor Threshold, ppm mg/kg


STEL, ppm mg/kg

1575 mg/m3

NFPA Hazard Signals Health Flammability Reactivity/Stability

Special


Personal Protective Equipment Rubber or plastic gloves, solvent resistant, chemical safety goggles.

247

Handling and Storage Precautions Store between 5 oC and 49oC. May be stored in unlined Mild Steel Tanks

7.EMERGENCY AND FIRST AID MEASURESFIRE Fire Extinguishing

Media

Special Procedure

Unusual Hazards

DCP, CO2

Fire fighters must use SCBA.

EXPOSURE

First Aid Measures

Antidotes/ Dosage

Medical attention is required.Move to fresh air. If breathing is difficult give oxygen and call for physician.Skin : Flush with large amount of water for 15 minutes.Eyes : Immediately flush eyes with large quantities of water for at least 15 minutes.

SPILLS Steps to be takenWaste Disposal Method

Absorb with an inert material such as sand, soil or

vermiculite.

8. DISCLAIMER

Information contained in this material safety data sheet is believed to be reliable but no representation, guarantee or warranties of any kind are made as to its accuracy, suitability for a particular application or results to be obtained from them.

248

10.5.10 CONTROL VALVE FAIL SAFE CONDITION

S.No. TAG NO. SERVICE ACTION/ FAIL SAFE CONDITION1 BOILER FEED WTR A/C (FO)2 5LV2602 RICH AMINE TO ARU A/O (FC)3 5LV3104 STM CONDEN. TO FLASH DRM A/O (FC)4 5LV3106 LP STM COND. FRM VV-035 A/O (FC)5 5FV1807 HY. NAPHTHA FOR GAS OIL A/O (FC)6 5FV2502 LPG BOOSTER PMP FLW A/C (FO)7 5LV3202 LPG TO LPG DRM VV-029 A/O (FC)8 5PV1701 VENT FRM VV-003 A/O (FC)9 5FV2501 LPG SURGE DRM A/C (FO)10 5PV3111 FO TO VV-026(BPC) A/C (FO)11 5FV1508 STRIPPING STM TO CC-001 BTM. A/O (FC)12 5FV2011 HY. NAPHTHA TO KERO R/D A/O (FC)13 5FV2503 LPG FRM PA-014A/B A/O (FC)14 5PV1415 FO TO HTR A/O (FC)15 5PV1504A FG TO FLARE FRM CC-001 A/O (FC)16 5PV1504B FG TO VV-002 A/O (FC)17 5PV1912 LPG PRODUCT R/D A/O (FC)18 5PV2011 HY. NAPHTHA TO STORAGE A/O (FC)19 5PV3203 LPG TO FG KOD VV-028 A/O (FC)20 5PV4406 HP STM TO DESUPER HTR A/O (FC)21 5SDV1406 FG SUPPLY(PILOT) A/O (FC)22 5SDV1701 DRAIN FRM VV-003 A/O (FC)23 5SDV1901 CAUSTIC SOL. EX VV-006 A/O (FC)24 5SDV1902 WASH WTR EX VV-007 A/O (FC)25 5SDV1903 WTR EX VV-008 A/O (FC)26 5SDV1904 CAUST. WASH WTR EX VV-016 A/O (FC)27 5SDV2001 CASTIC EX VV-009 A/O (FC)28 5SDV2002 WASH WTR EX VV-010 A/O (FC)29 5SDV2003 WTR FRM VV-025 A/O (FC)30 5SDV2201 CAUSTIC EX VV-013 A/O (FC)

249

31 5SDV2202 WASH WTR EX-VV-014 A/O (FC)32 5SDV2203 WASH WTR EX VV-015 A/O (FC)33 5SDV2601 AMINE SETTLER BTM A/O (FC)34 5SDV2602 LPG AMINE ABSORBER BTM A/O (FC)35 5LV1201 BR IN FRM DSTLR TO DGASR A/O (FC)36 5LV3103 FO TO VV-026 A/O (FC)37 5FV1201 2nd STAGE DESAL. WTR I/L A/O (FC)38 5FV1409 PLANT AIR FOR DECOCKING A/C (FO)39 5FV2501 LPG TO AMINE ABSORBER A/O (FC)40 5LV1602 SOUR WTR TO VV-005 A/O (FC)

S.No. TAG NO. SERVICE ACTION/ FAIL SAFE CONDITION

41 5PV3202 LP STM TO LPG VAPORISER A/O (FC)42 5SDV1401 FO RETURN A/O (FC)43 5LV1202 1st STAGE DIST. WTR I/L A/O (FC)44 5TV1702 NAPH. STAB. BTM. SAT. EE-018A/B LOCK (FC)45 5FV1401 CRUDE TO HTR PASS-1 A/C (FO)46 5FV1402 CRUDE I/L PASS-2 A/C (FO)47 5FV1403 CRUDE I/L PASS-3 A/C (FO)48 5FV1404 CRUDE I/L PASS-4 A/C (FO)49 5FV1804 HSD R/D A/O (FC)50 5FV2206 KERO/ATF COALASCER O/L A/O (FC)51 5FV3102 HP STM TO EE-028A/B/C/D A/O (FC)52 5HV1701 STABISER O/H VAPOUR A/O (FC)53 5PDV1420 ATM STM TO HTR A/C (FO)54 5SDV1402 FO SUPPLY A/O (FC)55 5SDV1601 SOUR WTR TO SRU A/O (FC)56 5SDV2501 LPG TO LPG SURGE DRM A/O (FC)57 5PV1423 FG TO HTR A/O (FC)58 5FV1410 DECOCKING STM TO HTR PASS-1 A/C (FO)59 5FV1412 DECOCKING STM TO HTR PASS-3 A/C (FO)60 5FV1413 DECOCKING STM TO HTR PASS-4 A/C (FO)61 5FV1414 DECOCKING STM TO HTR PASS-2 A/C (FO)62 5FV1505 TOP RFLX TO CC-001 A/C (FO)63 5FV1805 LR TO BL(FPU) A/O (FC)64 5FV1806 LR TO BL STORAGE A/O (FC)65 5HV2001 LN+CAUSTIC TO VV-009 A/C (FO)66 5HV2002 LN WTR TO VV-010 A/C (FO)67 5HV2201 KERO+ATF+CAUST. TO VV-013 A/C (FO)68 5HV2202 KERO+ATF+WASH WTR TO VV-014 A/C (FO)69 5SDV1801 LN TO CAUSTIC WASH A/O (FC)70 5FV1501 TOP CIR. RETURN TO CC-001 A/C (FO)71 5LV1508 KERO STRIPPER FEED A/O (FC)72 5LV1510 GAS OIL STRIPPER FEED A/O (FC)73 5SDV1403 FG SUPPLY A/O (FC)

250

74 5LV1206 CRUDE BOOSTER PMP D/S A/C (FO)75 5FV1502 ATF/KERO CR RETURNED TO CC-001 A/C (FO)76 5TV1116 EXCH-05-EE-006 A/B BYPASS A/C (FO)

Note: a) A/O stands for AIR TO CLOSE

b) A/C stands for AIR TO OPEN

c) FC stands for FAIL TO CLOSE

d) FO stands for FAIL TO OPEN

10.5.11 CORRECTIVE ACTION TO BE TAKEN TO PREVENT HAZADOUS

SITUATION FROM ESCALATING

HAZARDOUS SITUATION ACTIONSevere hydrocarbon leakage Cut off all furnace

Take unit on circulation. If required shutdown totally.

Block adjacent roads Inform F&S Isolate leaky section using PPEs &

depressurize to flare. Inform RSM/CPNM

Furnace Coil Rupture Open STD Cut off fuel to furnace Cut off feed Put coil purging steam. Take emergency S/D of entire

plant Inform RSM / CPNM

Severe Exchanger Leakage Bypass exchanger-using PPE & isolate it.

Depressurize Keep steam Lancer Inform RSM / CPNM Cut off furnace if H/C vapor travels

towards furnacePump Seal Leakage Start stand by pump

Isolate the leaky pump Depressurize Keep fire Engine standby. Inform RSM / CPNM

251

10.5.12 SAFETY SYSTEM AND THEIR FUNCTIONS

Following safety systems are available in our unit

1. PSVs

2. Interlocks

3. Hydro-carbon leak detectors

4. Fire water sprinkler system

5. PPEs

1. PSVs

Purpose: PSVs are provided to protect the equipments like columns, vessels, pipe line

etc by relieving excess pressure to flare / atmosphere when there is abnormal

pressurization due to CW failure or fire etc.

Where Situated: Normally it is situated at column top vessel top, compressor discharge

and positive displacement pump discharge.

Relieve Where: Normally to flare system.

Flare Knock Out Drum: All PSV discharge is routed to flare connected to a header

which is routed to flare KOD located at AU5 battery limit. Liquid which is carried along

with gas is settled in this vessel are drained out to CBD. Only gas from it’s top is send to

flare. It is provided with a level indication (with alarm). Level indication is transmitted to

DCS CR. In normal condition once in a shift draining is done.

2. Interlocks

252

Purpose: Meant for protecting of equipment in case of extreme deviation in parameter

from operating limit, before it reaches the equipment design limit.

Location: Furnaces

What all interlocks: (Furnace fuel will cut off if there is)

Low Combined pass flow

Low FG pressure

Low Fuel Oil pressure.

FD fan failure

ID fan failure (STD does not open with in 30 sec)

3. Hydrocarbon Leak detectors:

Facility: The unit is provided with 05 numbers of hydrocarbon detectors located at

vulnerable points where chances for leak is more. It senses the leak & if concentration is

more than the specified limit, will give signal to DCS control room through alarm. After

getting the alarm, Panel operator instructs the field operator to check physically the area,

for any leakage.

4. Fire water Sprinkler:

Firewater Sprinkler is provided on all black hot hydrocarbon pump for cooling purpose.

During pump seal leak & subsequent fire, sprinkler system is activated to cool the pump

to avoid damage to piping & structure. This system will be provided to all hot pump in

near future.

5. PPEs:

Safety helmet, safety shoe, rubber / canvas hand gloves, apron, Breathing apparatus, gas

mask/ canister for use in different gas atmosphere etc are provided for safe operation and

emergency handling in case of abnormal condition. BA set is kept in DCS control room.

Safety helmet & safety shoes have been provided to all operating personnel. Other PPEs

are available in Check & Change room of operators.

6. HVLR.

High Velocity Long Range monitor has been provided for spraying water jet at top of

high column during fire fighting

253

10.5.13 SAFETY PRECAUTIONS IN EQUIPMENTS HANDLING DURING

OPERATION

10.5.13.1 FURNACE BURNER LIGHT UP:(DURING START UP)

SR.NO

DESCRIPTION

1. Inform Panel operator

2. Fully open STD

3. Purge the box with steam and allow steam come out from stack. Confirm negative draft inside furnace.

4. Deblind the fuel gas main header and pilot gas lines.5. Light up the pilot burners6. Deblind IFO in and out lines.7. Slowly establish IFO circulation in IFO ring. Flush all FO burners with steam.8. Light up the IFO burner one after another. As per requirement.9. Light up main gas burners one by one as per requirement. 10. Observe the furnace arch pressure, temperature & flame pattern

10.5.13.2. WARMING UP OF PUMPS:

SR.NO

DESCRIPTION

1. Inform PNE / Panel operator2. Check up the pump assembles whether these are properly fixed or not.3. Check up the coupling, Coupling guard. Ensure pump is energized. Check lube Oil

level, Cooling water system/ flow. Ensure that shaft is free.4. Check up the casing & In let line drain bleeders and ensure these are closed and capped

/ end blinded.

254

5. Open suction valve 2-3 thread and slowly remove air through vent line by filling the line with liquid. Ensure that liquid comes from the vent are cooled in cooler before draining

6. Check for leakage. If OK fully open suction valve.7. Slowly open warm up valve and gradually warn up pump.

10.5.13.3. PUMP CHANGE OVER/START UP:

SR.NO

DESCRIPTION

1. Inform PNE / Panel operator

2. Check for electrical supply if it is back from maintenance.3. Check up the pump coupling guard, drain point, and lube oil in the bearing, C/W

to bearing and casing, freeness of the shaft.4. Check & Open suction valve.5. Warm up the pump slowly and let it hot at pumping material temperature.(If hot

pump)6. Inform panel operator before change over.7. Close the warm up valve (If hot pump)8. Start the pump. Gradually open the discharge valve.9. Check up the Amp (Load). If the AMP is increased, gradually close the

discharge valve of former (running) pump.10. Check pump load, if required open more discharge.11. Whenever discharge valve of previous running pump is fully closed, stop the

pump and open the warm up valves (If hot pump).12. Check for any abnormality, vibration, abnormal sound etc.13. Inform panel operator that C/O is completed. Confirm discharge flow

requirement is fulfilled.

10.5.13.4 HEAT EXCHANGER COMMISSIONING:

SR.NO

DESCRIPTION

1. Inform shift in charge and panel operator for commissioning of exchanger.2. Check all blinds are removed at inlet and outlet lines. Ensure Bull plug fixing.

Check CBD & OWS line valves are closed

255

3. Check all the disturbed flanges are boxed up with new gasket and there is no short bolt.4. Do steaming of exchanger of both sides (tube / shell) by keeping

drain and vent open through hose connections.5. Check leaks if any by pressurizing with steam. Before this, close partially the vents /

drain bleeders. Be sure that pressure does not cross the design test pressure.6. Stop steaming, if no leak is there. Provide hose connection in both shell side & tube side

vents.7. Take FLO in shell and tube sides & displace air through the vent. Make sure that oil

has comes out from vents. Close & cap all vents.8. After settling for half an hour, drain water (if any) from shell & tube side.

Simultaneously makeup with fresh FLO.9. Slowly open both side inlet & outlet valves. Slowly close the bypass valves. Take

sufficient time to close bypass valves.10. Blind CBD, OWS & FLO.

5. MAN ENTRY IN CLOSED VESSEL/ EQUIPMENT:

VESSEL IS CONSIDERED.

SR.NO

DESCRIPTION

01. Isolate the equipment and depressurize first to flare & then CBD. Slowly open the vent after isolating flare valve.

02 Provide steam hose connection or Deblind steam out point . Start steaming & drain condensate through drain line.

03 After thorough steaming is over, depressurize the vessel & give clearance for positive blind as per master blind list.

-4 Open manhole, through which provide firewater hose connection & do thorough water washing.

05. Drain water when water washing is over.

06 Check for O2 content inside vessel & other gases by respective instrument.07 If OK & O2 is more than 19%, Provide light & air hose connection inside vessel & give

clearance for man-entry.

6. FURNACE BURNER LIGHT UP: (DURING NORMAL OPERATION)

SR.NO

DESCRIPTION

Inform Panel operator01. Ensure that Burner is properly boxed up & gasket is provided.02. Check the burner valve and ensure that it is in closed position.

256

03. Check steam to Burner.04. Flush the oil burner with the flushing steam during that time ensures that Burner Oil B/V is

in closed position. Check any leakage during steam flushing. 05. Slowly Light up oil burner adjusting oil and steam flow. Ensure that other burner does not

disturb.06. Observe the flame pattern and if required adjust steam/oil flow or air.07. Observe the Furnace condition and ensure that there is no flame impingement. If required

burner oil and steam flow can be adjusted.

CHAPTER-11

PROCESS UPSET & CORRECTIVE ACTIONS

257

PROCESS UPSET & CORRECTIVE ACTIONS

Sl.No Equpt No Measured parameter Deviation Action to be taken1 Column Top Pressure High Check top pressure C/V

Reduce bottom firing /COT

if required

Reflux drum level High Check the reflux pump

Check R/D flow for any

blockage

Maintain required top

temperature

258

Differential pressure High Check withdrawal temp. of

side stream

Draw more product

Check over flash & pull

more HSD

2 Vessel Level High Increase R/D flow

Optimize inflow-keeping

specification on grade.

Check for any R/D

blockage

Pressure High Check PCV opening

Check for any blockage

Maintain vessel level as

required

Maintain vessel

temperature as required

Temperature High Increase CW flow in

Cooler / Condenser

Reduce CW supply

temperature

Maintain product draw

temperature as required.

3 Furnace COT of any pass High Increase pass flow

Reduce furnace firing

Skin temperature High Increase pass flow to that

pass

Adjust furnace firing to

check any impingement on that

pass

259

Arch temperature High Adjust furnace firing

Adjust excess air

Open STD a little

Stack temperature High Adjust furnace firing

Adjust excess air

Do shoot blowing.

If above does not solve,

decommission APH & do water

wash.

4 VV-02 Boot water PH High Increase ammonia / caustic

injection

VV-02

Low Reduce ammonia / caustic

injection

5 VV-02 CL content

Fe content

High

High

Increase caustic injection

Check caustic solution

strength

Reduce ammonia as per

PH requirement

Check operation of Corrosion inhibitor pump & increase dozing

6 LPG & Naphtha caustic / water wash

H2S slippage by Pb-acetate test

+ve Replenish spent caustic

with 10% strength fresh

caustic

Replace water of water

wash vessel

260

CHAPTER-12

HANDING & TAKING OVER OF INFORMATION DURING SHIFT CHANGE

HANDING & TAKING OVER OF INFORMATION DURING SHIFT CHANGE

1.Shift PNE:Out going PNE Should inform Incoming PNE

262

About any equipment problem existing

Any quality deviation & corrective action taken

Any hazardous condition existing in plant

Any instruction yet to be implemented

About any follow-up action to be taken for equipment under maintenance.

About any additional manpower requirement if any

About any Interlocks bypassed & reason.

2. Panel Operator:

Out going Panel Operator Should inform Incoming Panel Operator

About any prevailing instrument problem

About Any instruction yet to be followed

About Deviations from normal operating parameter

Corrective actions taken for deviation of quality.

About Inter lock remaining bypassed if any.

About Critical alarm if any.

About Follow-up actions for quality deviation to be taken

About Any instrument under maintenance.

3. Field Operator

Out going Field Operator Should inform incoming Field Operator

About any equipment under maintenance.

About any unsafe condition

About any instruction yet to be implemented.

About any equipment problem, yet to be given to maintenance.

About follow up action for maintenance, H/O or T/O.

About change of product routing

About health of burners.

4. Pump Operator:

Out going Pump Operator Should inform Incoming Pump Operator

263

About any pump running in unsafe condition

About any problem which needs immediate attention.

About equipment under maintenance

About equipment run in the shift & observation

About any equipment ready for trial run.

About follow up action with maintenance.

About instruction yet to be implemented.

264

CHAPTER-13

CONTROL OF HAZARDOUS CHEMICAL INVENTORY LEVEL

265

CONTROL OF HAZARDOUS CHEMICAL INVENTORY LEVEL

In atmospheric distillation unit main hazardous chemical, are ammonia & NaOH. Caustic

solution is dozed at pre-desalter inlet to neutralize Naphthenic acid & at post desalter

exchanger train to neutralize HCL generated by hydrolysis of salts of MgCl2. NH3 is

injected in the over head of column to neutralize any HCL vapour which has remained

un-neutralized by caustic. NH3 is injected in some units as ammonia solution of 2-3%

strength diluted with DM water & in some units as ammonical caustic solution where

NH3 remains in solution with dilute caustic for neutralization purpose.

NH3 is procured in cylinders of 40 Kg weight. Caustic is received from OMS & diluted

to required strength with DM water.

Caustic is also used for removing H2S from naphtha & LPG streams in naphtha & LPG

Caustic & water wash system, where caustic of 10% strength is used. Inventory of this

chemical is maintained for about 15 days of average daily consumption.

Chemical Unit Average daily

consumption

Requirement

for 15 days

Inventory level

(requirement+

10%)

NaOH AU1 715 Kg 10 Mt 12 Mt

AU2 189 Kg 2.5 Mt 2.75 MT

AU5 280 Kg 4 Mt 4.4 Mt

Ammonia AU1 5 Kg 75 Kg / 2

cylinder

3 cylinders

AU2 8 kg 120 / 2 cylinder 4 Cylinders

AU5 10 150 / 4

Cylinder

5 cylinders

266

CHAPTER-14

PLANT EQUIPMENT IDLING METHOD

267

PLANT EQUIPMENT IDLING METHOD

14.1 FOR SHORT SHUTDOWN:

EQUIPMENT ACTIONAtmospheric column / stabilizer column

Float with Fuel gas

Stop all chemical injection

Maintain positive pressure

Atmospheric column reflux drum (VV-02)Stabilizer column reflux drum (VV-03)

Float with FG

Float with FG

Float with FG

Float with Flare

Desalter Switch off transformer

Stop water & demulsifier injection

Drain brine to low level & block the valve.

Water wash vessel Drain water to lowest level & block the valveCaustic wash vessel Drain caustic to sour water system to lowest

level & block the valvePumps Isolate discharge valve

Close warm-up valve

Close quenching steam

Heat Exchanger Line up TSVs

268

Pinch CW out let valve to cooler / condenser

Battery Limit valves on product lines

Isolate

Tracing steam / Electric tracers for RCO line

To be kept on

Steam Keep it charged within UnitIFO Maintain circulation through ring

14.2 FOR LONG IDLING:

Make unit hydrocarbon free and follow Preservation procedure as per OISD-STD-171.

CHAPTER-15

DCS INFORMATION

269

DCS INFORMATION

1.Refinery name and location Gujarat Refinery

2. Plant data AU- 5 Ver.10.20

3. DCS

3.1 MAKE YOKOGAWA BLUE STAR3.2 MODEL CENTUM-CS

4. DCS OPERATING SYSTEM

4.1 SOFTWARE TYPE/ VERSION FCS: CENTUM CS HP UNIX Ver.10.20

ICS: AT&T UNIXHICS: HP UNIX

4.2HARDWARE PLATFORM HICS:HP 9000WORKSTATION

270

FCS & ICS: YBL PROPRIETARY STATIONS

5.PLC (FOR SHUTDOWN SYSTEM)

5.1 MAKE ABB-AUGUST SYSTEMS5.2 MODEL CS – 300E5.3 ARCHITECTURE TMR

6.CONTROLLER SUB SYSTEM

6.1MULTI LOOP6.1.1 MODEL NO CP 334D6.1.2 SCAN TIME 1 ms to 500 ms (configurable)6.2 SINGLE LOOP6.2.1 MODEL NO N/A6.2.2 SCAN TIME

7.HIGHWAY DATA COMMUNICATION SYSTEM

7.1 BUS/ HIGHWAY TYPE MULTIDROP/TOKEN PASSING7.2 SPEED OF COMMUNICATION 10 MBPS (V- NET)

8. DATABASE ARCHITECTURE (viz. CENTRAL/DISTRIBUTED ETC)

DISTRIBUTED DATABASE

9.APPROX. NO OF LOOPS9.1 CLOSED 919.1.2 OPEN 4219.1.3 DIGITAL 239

10.INTERFACE WITH ADVANCE CONTROL NOT IMPLIMENTED10.1 DMC10.2 SET POINT10.3 OTHERS (PLEASE SPECIFY)

11. CONNECTIVITY/ NETWORK TO OTHER EQUIPMENT/ SYSTEM11.1 FIELD BUS11.1.2 LAN11.1.3 IEE802.3 ETHERNET (IEEE802.3)11.1.4 OTHERS (PLEASE SPECIFY)

271

12.DCS ARCHITECTURE (DRG. TO BE ENCLOSED)

272

LABORATORY TEST SCHEDULE

S.N0. STREAM TEST FREQUENCY TEST PERFORMED

1. LPG COPPER CORROSION H2S &CAUSTIC WASH

1/D1/D

SHIFT

2. LIGHTNAPHTHA

DENSITY DISTILATION

2/D1/D

SHIFT

CHAPTER-16

LABORATORY TEST SCHEDULE

273

RVPCOPPER CORROSION

2/DOnce in an

alternate day

SHIFT

3. HEAVY NAPHTHA

DENSITYDISTILATION

2/D1/D

SHIFT

4. SKO DENSITYFLASH DISTILATION

2/D2/D2/D

SHIFT

5. GASOIL DENSITY,FLASH POURPOINT, DISTILATION

2/D2/D2/D

SHIFT

6. SOUR WATER EX.V2

PHCHLORIDE FE

1/D1/D1/D

SHIFT

7. V-6/9/13 CAUSTIC

STRENGTH 1/D SHIFT

8. DESALTER CRUDE I/L,O/L

DENSITYSALT BS&W

1/W1/W1/W

SHIFT- SUN

9. DESALTER BRINE WATER

PH OIL CONTENT

1/W1/W

SHIFT- SUN

10. V-7/10/14 WATER

% OF CAUSTIC 1/W G/S -WED

11. FLUE GAS ORSAT ON REQ SHIFT12. CAUSTIC/

AMMONIASTRENGTH ON REQ SHIFT

13. RCO RECOVERY AT 360°C 1/W G/S14. TK-2A/B &

TK-6A/BCAUSTIC SOLUTIONSTRENGTH

ON REQ SHIFT

274

BLIND LIST

BLIND LIST

S. No DESCRIPTION SIZE RUNNING

S/D TYPE

1. CW inlet 24” Out In Tail2. Rich Amine To SRU 2” Out In Spect3. Lean Amine from SRU 2” Out In Spect4. LPG fron AU5 2” out In Spect

CHAPTER-17

MASTER BLIND LIST

275

5. Crude to Unit 14” Out In Tail6. LR to Storage 10” Out In Tail7. HSD to FCC 6” Out In Spect8. LP steam to unit 14” Out In Tail9. MP steam to Unit 12” Out In Spect10. HP steam to Unit 6” Out In Spect11. Amine Ex Sump to CRU 2” Out In Tail12. HSD to DHDS 6” Out In Spect13. HSD to OMS 6” Out In Spect14. SOUR water to SRU 4” Out In Spect15. Stripped ex SRU 4” Out In Spect16. Spent caustic to ETP 2” Out In Spect17. BFW to Unit 3” Out In Spect18. FLO 4” Out In Spect19. Instrument Air 4” Out In Tail20. Plant Air 4” Out In Spect21. Service Water 4” Out In Spect22. DM water 4” Out In Spect23. LPG Rundown 4” Out In Spect24. Light Naphtha to OMS 4” Out In Spect25. Caustic Ex OMS to Unit 3” Out In Spect26. LPG ex AU3 4” out In Spect27. ATF R/D 6” Out In Spect28. SKO R/D 6” Out In Spect29. FG to DHDS 8” In In Spect30. Slop to GRE/OMS 10” Out In Tail31. FG ex GHC 12” Out In Tail32. Hot RCO to GHC 10” Out In Tail33. IFO ex GHC 8” Out In Spect34. Wild Naphtha ex OMS/UNIT 2” Out In Spect35. Light Naphtha from Unit 3” Out In Tail36. Light Naphtha new line 6” In In Tail37. CW return 24” Out In Tail38. Flare KOD to Flare line 24” Out In Tail

CC01- COLUMN

SrNo DESCRIPTION SIZE RUNNING

S/D TYPE

1. Feed Entry 30” Out In Tail2. Desalter PSV-1 10” Out In Tail3. Desalter PSV-1 10” Out In Tail4. Bottom O/L 14” Out In Tail

276

5. Top O/L 30” Out In Tail6. Gas Oil CR Return 14” Out In Tail7. Kero CR Return 14’ Out In Tail8. Top CR return 12” Out In Tail9. Top Reflux 8’ Out In Tail10. Top CR Draw Off 16” Out In Tail11. Side Draw Off 8” Out In Tail12. Kero (to Stripper) Draw Off 16” Out In Tail13. Kero CR Draw Off 16” Out In Tail14. Gas Oil draw Off 16” Out In Tail15. Gas Oil CR Draw Off 16” Out In Tail16. Vapour Return from HN Stripper 10” Out In Tail17. Vapour Return from Kero Stripper 12” Out In Tail18. Vapour Return from Gas OIL Stripper 14” Out In Tail19. Stripping Steam to Column 10” Out In Tail20. Column Top Vent 3” In Out Tail21. 2 Nos of Over Flash Draw Off 8” Out In Tail22. Over Flash Return 8” Out In Tail23. Steam Out (Utility) to Column In In Tail24. Ahuralan Injection 1” Out In Tail25. Ammonia Injection 1” Out In Tail

C2-Collumn26. Vapour Outlet 10” Out In Tail27. Top Vent 2” In Out Tail28. Pump Minimum circulation Return 2” Out In Tail29. Reboiler Feed 6” Out In Tail30. Reboiler Return 10” Out In Tail31. Bottom Outlet 6” Out In Tail32. Steam Out point 2” In Out Tail

CC03- COLLUMN

SrNo DESCRIPTION SIZE RUNNING

S/D TYPE

1 Vapour Outlet 12” Out In Tail2 Top Vent 2” In Out Tail

277

3 Stripping Steam I/L 8” Out In Tail4 Reboiler Feed Out In Tail5 Reboiler Return 12” Out In Tail6 Bottom Outlet 12” Out In Tail7 Steam Out point 2” In Out Tail

CC04-COLUMN1 Vapour Outlet 12” Out In Tail2 Top Vent 3” In Out Tail3 Stripping Steam I/L 10” Out In Tail4 Reboiler Feed Out In Tail5 Reboiler Return 14” Out In Tail6 Bottom Outlet 12” Out In Tail7 Steam Out point 3” In out Tail

CC05- COLUMN1 Vapour Outlet 14” Out In Tail2 Top Vent 2” In Out Tail3 Reflux Nozzle 4” Out In Tail4 Reboiler Feed 14” Out In Tail5 Reboiler Return 18” Out In Tail6 Bottom Outlet 10” Out In Tail7 Steam Out Point 2” In Out Tail8 2 Nos Feed Inlet 8” Out In Tail9 PSVs 6” Out In Tail

CC06- COLUMN1 Vapour Outlet 4” Out In Tail2 Top Vent 2” In Out Tail3 Sour LPG Feed Inlet 4” Out In Tail4 Lean Amine Feed Inlet 2” Out In Tail5 Rich Amine outlet 2” Out In Tail6 Utility Connection 2” In Out Tail7 PSVs 4” Out In Tail

278

CONTROL VALVES DATA

S.No. TAG NO. SERVICE SIZE(in.) RATING CV MAKE1 5F BOILER FEED WTR 1 300 3.8 MIL2 5LV2602 RICH AMINE TO ARU 1 300 7.5 PIGNONE3 5LV3104 STM CONDEN. TO FLASH DRM 1 600 6 PIGNONE

CHAPTER-18

CONTROL VALVES DATA

279

4 5LV3106 LP STM COND. FRM VV-035 1 150 7.5 PIGNONE5 5FV1807 HY. NAPHTHA FOR GAS OIL 1.5 300 22 PIGNONE6 5FV2502 LPG BOOSTER PMP FLW 1.5 300 7.5 PIGNONE7 5LV3202 LPG TO LPG DRM VV-029 1.5 300 22 PIGNONE8 5PV1701 VENT FRM VV-003 1.5 300 12 PIGNONE9 5FV2501 LPG SURGE DRM 2 300 45.63 ARCA10 5PV3111 FO TO VV-026(BPC) 2 300 60 MOTOYAMA11 5FV1508 STRIPPING STM TO CC-001 BTM. 2 300 27 PIGNONE12 5FV2011 HY. NAPHTHA TO KERO R/D 2 300 22 PIGNONE13 5FV2503 LPG FRM PA-014A/B 2 300 22 PIGNONE14 5PV1415 FO TO HTR 2 300 12 PIGNONE15 5PV1504A FG TO FLARE FRM CC-001 2 150 49 PIGNONE16 5PV1504B FG TO VV-002 2 150 49 PIGNONE17 5PV1912 LPG PRODUCT R/D 2 300 49 PIGNONE18 5PV2011 HY. NAPHTHA TO STORAGE 2 300 22 PIGNONE19 5PV3203 LPG TO FG KOD VV-028 2 300 43 PIGNONE20 5PV4406 HP STM TO DESUPER HTR 2 600 43 PIGNONE21 5SDV1406 FG SUPPLY(PILOT) 2 150 49 PIGNONE22 5SDV1701 DRAIN FRM VV-003 2 300 49 PIGNONE23 5SDV1901 CAUSTIC SOL. EX VV-006 2 300 49 PIGNONE24 5SDV1902 WASH WTR EX VV-007 2 300 49 PIGNONE25 5SDV1903 WTR EX VV-008 2 300 49 PIGNONE26 5SDV1904 CAUST. WASH WTR EX VV-016 2 150 49 PIGNONE27 5SDV2001 CASTIC EX VV-009 2 150 49 PIGNONE28 5SDV2002 WASH WTR EX VV-010 2 150 49 PIGNONE29 5SDV2003 WTR FRM VV-025 2 150 49 PIGNONE30 5SDV2201 CAUSTIC EX VV-013 2 300 49 PIGNONE31 5SDV2202 WASH WTR EX-VV-014 2 300 49 PIGNONE32 5SDV2203 WASH WTR EX VV-015 2 300 49 PIGNONE33 5SDV2601 AMINE SETTLER BTM 2 300 49 PIGNONE34 5SDV2602 LPG AMINE ABSORBER BTM 2 300 49 PIGNONE35 5LV1201 BR IN FRM DSTLR TO DGASR 2 300 43 UCH PIG.36 5LV3103 FO TO VV-026 3 300 150 MOTOYAMA37 5FV1201 2nd STAGE DESAL. WTR I/L 3 300 88 PIGNONE38 5FV1409 PLANT AIR FOR DECOCKING 3 150 49 PIGNONE39 5FV2501 LPG TO AMINE ABSORBER 3 300 49 PIGNONE40 5LV1602 SOUR WTR TO VV-005 3 150 49 PIGNONE41 5PV3202 LP STM TO LPG VAPORISER 3 150 88 PIGNONE42 5SDV1401 FO RETURN 3 300 108 PIGNONE

S.No. TAG NO. SERVICE SIZE(in.) RATING CV MAKE43 5LV1202 1st STAGE DIST. WTR I/L 3 300 88 UCH PIG.44 5TV1702 NAPH. STAB. BTM. SAT. EE-018A/B 4 300 117 ARCA45 5FV1401 CRUDE TO HTR PASS-1 4 600 140 MIL46 5FV1402 CRUDE I/L PASS-2 4 600 140 MIL47 5FV1403 CRUDE I/L PASS-3 4 600 140 MIL

280

48 5FV1404 CRUDE I/L PASS-4 4 600 140 MIL49 5FV1804 HSD R/D 4 300 195 PIGNONE50 5FV2206 KERO/ATF COALASCER O/L 4 300 95 PIGNONE51 5FV3102 HP STM TO EE-028A/B/C/D 4 600 115 PIGNONE52 5HV1701 STABISER O/H VAPOUR 4 300 195 PIGNONE53 5PDV1420 ATM STM TO HTR 4 300 195 PIGNONE54 5SDV1402 FO SUPPLY 4 300 195 PIGNONE55 5SDV1601 SOUR WTR TO SRU 4 150 195 PIGNONE56 5SDV2501 LPG TO LPG SURGE DRM 4 300 195 PIGNONE57 5PV1423 FG TO HTR 6 150 444.6 ARCA58 5FV1410 DECOCKING STM TO HTR PASS-1 6 300 359 PIGNONE59 5FV1412 DECOCKING STM TO HTR PASS-3 6 300 359 PIGNONE60 5FV1413 DECOCKING STM TO HTR PASS-4 6 300 359 PIGNONE61 5FV1414 DECOCKING STM TO HTR PASS-2 6 300 359 PIGNONE62 5FV1505 TOP RFLX TO CC-001 6 150 250 PIGNONE63 5FV1805 LR TO BL(FPU) 6 300 440 PIGNONE64 5FV1806 LR TO BL STORAGE 6 300 440 PIGNONE65 5HV2001 LN+CAUSTIC TO VV-009 6 300 250 PIGNONE66 5HV2002 LN WTR TO VV-010 6 300 250 PIGNONE67 5HV2201 KERO+ATF+CAUST. TO VV-013 6 300 359 PIGNONE68 5HV2202 KERO+ATF+WASH WTR TO VV-014 6 300 359 PIGNONE69 5SDV1801 LN TO CAUSTIC WASH 6 300 341 PIGNONE70 5FV1501 TOP CIR. RETURN TO CC-001 8 150 475 PIGNONE71 5LV1508 KERO STRIPPER FEED 8 150 475 PIGNONE72 5LV1510 GAS OIL STRIPPER FEED 8 150 475 PIGNONE73 5SDV1403 FG SUPPLY 8 150 680 PIGNONE74 5LV1206 CRUDE BOOSTER PMP D/S 8 300 475 UCH PIG.75 5FV1502 ATF/KERO CR RETURNED TO CC-001 10 300 900 ARCA76 5TV1116 EXCH-05-EE-006 A/B BYPASS 12 300 1521 ARCA

281

LIST OF ALARMS & INTER LOCKS

CHAPTER-19

LIST OF INTERLOCKS

282

In AU-V two types of alarms are in service. In first category, alarms are associated with

independent switches mounted on various circuits. Second category of alarms consists of

those, which are associated with various controllers/indicators.

Alarms emanating from independent switches can be brought either to DCS panel (CR to

or on panel of control room. Alarm setting can be provided to all DCS open loop or

closed loop measurements and can be taken to DCS panel, or control panel through a

converter. The alarms appearing on DCS are called software alarms while alarms on

panel of control room (console panel) are called Hard Wired alarms. The alarms

emanating from switches, but appearing on DCS only are also called software alarms.

Settings of software alarms can be wired to any value if the output from field is coming

through a transmitter, while hardwired alarms originating from switches have more or

less prefixed settings and are normally not varied

AU-5 TRIP SETTINGS

TAG NO DESCRIPTION TRIP VALUE RANGE

05PSHH1130 P01A/B/Cv. High Dis. Pressure 35 Kg/cm2

05PSHH2607 CC-06 Top Pressure V. High 18.9 Kg/cm2

05PSL3102 P45A/B low Discharge

pressure

7.8 Kg/cm2

05PSH1810 LR to SLOP 20 Kg/cm2

05FSL1401B Low Flow in pass 1 53.75 m3/hr 0-215M3/hr




05PSLL1427 Very low pressure in fuel oil 3 Kg/cm2

05PSLL1424 Very low pressure in fuel gas 0.5 Kg/cm2

05PSL1435 Fuel gas to FF-01 0.8 Kg/cm2

TAG NO DESCRIPTION TRIP VALUE RANGE

05FSLL1453 Very low flow in combustion 30000NM3/hr 0-164KNM3/hr

283

Air

05PSHH1452A High pressure in Furnace Arch 10 mm WC -20,+20mm WC

05PSHH1452B V. High pressure in Furnace

Arch

10 mm WC -20,+20mm WC

05PSHH1452C V. High pressure in Furnace

Arch

10 mm WC -20,+20mm WC

05SSLL1483 Very low speed of FD fan A 200 rpm 1000 rpm

05SSLL1484 Very low speed of FD fan B 200 rpm 1000 rpm

05FSL1455 Low flow in FD Fan A suction 15000 NM3/hr 82000 NM3/hr

05FSL1454 Low flow in FD Fan B suction 15000 NM3/hr 82000 NM3/hr

05SSLL1485 Very low speed of ID 200 rpm 1000rpm

05TSHH1497 Very high temp in CAPH 245° C

05FSLL1460 V. low flow cir. Oil in FD fan

A

60 lts/min

05FSLL1463 V. low flow cir. Oil in FD fan

B

60 lts/min

05FSLL1457 V. low flow cir. Oil in ID fan

A

60 lts/min

PROCESS INTERLOCK LOGIC:

284

A 05-FC-1401-PASS FLOW LOW-

FAL 1401

BPS 1405

F-01 cut off IFO SDV 1402

close

05-FC-1402-PASS FLOW LOW

---FAL1402

IFO Return SDV 1401 close


---FAL1403

FG supply SDV 1403 close


---FAL1404

B FUEL OIL PRESS LOW PSLL-1427- BPS

1407

FUEL OIL SDV CLOSE

C FUEL GAS PRESS LOW PSLL-1424 -- BPS

1407

FUEL GAS SDV CLOSE

D ARCH PRESS. HIGH PAHH-1452--- BPS

1410

STACK DAMPER OPEN

NOTE: - If stack Damper does not open within 30 sec, Furnace will CUT-OFF.

E VERY LOW COMBUSTION AIR

FLOW

FALL-1453 -- BPS

1409

FUEL OIL SDV CLOSE

FUEL GAS SDV CLOSE

STD OPEN.

F 05-KA-01B CIRCUL OF OIL

FLOW LOW

FSLL-1463 ---BPS-

1417

- FD – 1B TRIP

G 05-KA-01A CIRCUL. OF OIL

FLOW LOW

FSLL-1460 -- BPS-

1416

-- FD – 1A TRIP

H LOW SPEED ID FAN BPS 1415 ID TRIP STACK DAMPER

OPEN

I CAST APH O/L TEMP. HIGH TSHH-1497 STACK DAMPER OPEN

NOTE: In case stack damper will not open automatically, ID fan will trip and furnace

will cut off

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J I.D.FAN CIRCULATING OIL

FLOW LOW

FSLL-1457 --- BPS

1418

I.D. WILL TRIP

K FD FAN 1A SPEED LOW BPS 1412 FD FAN 1A TRIP

L FD FAN 1B SPEED LOW BPS 1413 FD FAN 1B TRIP

M 05-PM-01A/B/C DISCH. PRESS

HIGH

05 PM-01A/B/C TRIP

N 05-VV-20 LEVEL HIGH LAHH-2501 SDV-2501 CLOSE (LPG

INLET TO VV-20)

O 05-VV-20 LEVEL LOW LALL-2502 TRIP 05-PM-50A/B (LPG

BOSTER PUMPS)

P 05-CC-06 HIGH PRESSURES PAHH-2607 CLOSE FC-2601 (AMINE

TO C-06)

NOTE: - In case of high pressure in C- 06, FC-2601 will shut off. After attaining normal

condition FC-2601 will work as normal flow controller.

Q 05-CC-06 BOTTOM LEVEL

LOW

LALL-2605 CLOSE SDV 2602

R CLOSE SDV 2602 05-PM-45A 05-PM-45B

If pump (B) is running then selection switch [SS 3110] should be on (A), so that in case

at pressure low [PAL 3102B] pump (A) will start.

NOTE: - “OFF” push button of stand by pump must not be in lock condition.

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CHAPTER-20

SKO/ATF SALT DRYER

287

SKO/ATF SALT DRYER

A Salt dryer is additionally provided in the SKO/ATF run down after coalescer to reduce

haziness in SKO/ATF due to fine mist of moisture, which slips through coalescer. The

salt dryer is loaded with 50MT of rock salt. It is provided with inlet at the bottom and

outlet at the top. Wet ATF/SKO enters the vessel through a Johnson Screen. A bypass

valve is also provided between inlet & outlet lines to bypass the dryer. A drain line is

provided at the bottom, which is connected with OWS & CBD. Two numbers of PSV are

installed at the top of the vessel, which is release to CBD & OWS. PG’s provided at the

inlet and outlet to enable monitoring the pressure drop across the salt bed. As feed enters

at the bottom, the salt absorbs water droplets and its density increases. The dense brine

droplets settle at the bottom, which are drain out easily. Field operator drain out water

twice in a shift.

Design data: Salt to load: 61 Mt.

Inlet moisture: 1300-1500 ppm.

Outlet moisture: <200 ppm

Start up:

Ensure PSV are lined up

Line up outlet valve

Line up inlet valve slowly

Check that vessel top pressure is healthy.

Check that delta P across drier bed is healthy.

Shut down:

Bypass drier

Close inlet valve

Close outlet valve

Check that top pressure is below PSV set value

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Drain out residual water at the bottom

Trouble shooting:

High-pressure drop. Johnson screen is chocked

Above calls for unloading of salts and inspection of Johnson screen

Moisture Slippage

Bed channeling due to high flow/partial chockage of Johnson screen.

High moisture in the bed due to unsatisfactory coalescer performance

Insufficient salt in the drier

High pressure in the vessel

Outlet valve partially closed

Rundown line restriction

Correct the problem by opening the valve

289

CHAPTER-21

HSD COALESCER

290

HSD COALESCER

OPERATION AND MANTENANCE M ANNUAL:

CLIENT : M/S INDIAN OIL CORPORATION LIMITED

PROJECT : IOCL GUJARAT REFINERY (UNIT-AU3)

INSPECTION : M/S LRIS

ITEM : DIESEL COALESCER

TAG NO : 05-VV-301 / ONE

DESCRIPTION:

MULTITEX DIESEL COALESCER is a compactly made mechanical device

manufactured to a high degree of accuracy. If complete instructions regarding

installation, operation and maintenance of these units are observed carefully, the

coalescer should give trouble free service for a very long period.

THE DIESEL COALESCER in its simplest form, designed and manufactured as per

ASME Section VIII Div. I. It consists of a horizontal shell having dished end at its both

ends and one manhole connection at the middle to facilitate the easy removal of coalescer

and separator elements for cleaning and replacement.

INSTALLATION:

The Coalescer is a precision product and requires extremely careful handling during

transportation, fitting and installation. The coalescer is thus normally despatched in well-

packed installation. It should be unpacked just before installation only and the whole

coalescer may be checked for any damage.

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The coalescer should be fitted in position taking care of the orientation of nozzles etc. the

coalescer should be rigidly hooked upto various piping connection and base to avoid any

vibration due to flow. Ensure sufficient empty space on the front of the Manhole opening

to facilitate the element removal without tilting.

IMPORTANT: To avoid damage to the element by any leftover material in the piping

system, up-stream of the element should be flushed thoroughly before the fitment of

coalescer/separator element in the housing.

METHOD OF WORKING

The Diesel Coalescer housing is provided with the inlet and outlet nozzles of suitable

sizes at the front end on dish and at far end on dish of housing respectively. Connection

for safety relief valve has been provided. The water droplets coalesced through the

element gets collected in the horizontal sump provided below main vessel and thereafter

drained through the drain nozzle provided at its bottom.

Horizontal sump with dished end on its both end has been provided. Connections for

Level Transmitter and Level Gauge have also been provided to mount instruments on the

horizontal sump.

The Diesel coalescer consists: -

1st stage: Coalescer element to coalesce fine mist of water and to retain dust particle

2nd Stage: Separator element to separate out water droplets (At outlet < 20 ppm)

All the solid particles 10 microns (98%) are trapped in the element. In addition liquid

droplets do not wet the fibers but remain attached to them as beads of liquid. As more

liquid droplets are separated, more they agglomerated and coalesced into large drops due

to their surface attraction to each other. When the coalesced liquid drops attains a

sufficient size from 100 to 200 times their initial size, the force of gravity and frictional

drag of the fluid causes them to drain out the element and they are carried into sump of

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the vessel. Due to their size, they are readily stripped out in the horizontal sump through

downcomers.

OPERATION

The coalescer has been thoroughly subjected to inspection and testing at their works

before dispatch, but to check the leak proofness of matching flanged connections, the

coalescer along with the up-stream and downstream piping should be subjected to

hydrostatic testing. After satisfying that there is no leaking joint causing spillage and

wastage of service fluid, the coalescer should be put to the operation as follows :

Supply of stream (at required temperature) should be started before putting the coalescer

into operating

Provide all instrument / isolation valves at per drawing P&ID

Close all valves including inlet, outlet and drain plug. Open air vent.

Open inlet valves slowly so that coalescer is in operation.

Open drain plug and flush out any debris.

Close drain plug.

Allow coalescer to fill in with liquid and when the liquid starts coming out of the

air vent, close the air vent again.

Open coalescer outlet valve.

If there is a by-pass valve, close it slowly.

The fluid enters through the inlet to the coalescer. In the process of passing through the

elements, the entrained particles (Liquid+Dust) are caught through the depth of the

element and clean fluid passes out through the outlet.

MAINTENANCE AND CLEANING / REPLACEMENT

The element of the coalescer supplied has been designed for the following pressure drop:

Pressure Drop (clean): - 0.75 kg/cm2

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MULTITEX coalescer will give satisfactory service if it is ensured that the element is

replaced on attaining the maximum permissible pressure drop as indicated above.

The following procedure should be adopted for replacement of the element:

Whenever the pressure drop reaches the maximum permissible pressure drop the

element should be replaced by new element.

Close inlet and outlet valves and open the drain plug and flush out the fluid in the

housing. Take out the dirty element from the shell and replace it. The element can

be taken out by opening Manhole cover. Enter into the housing, unscrew the tie

rod nuts, remove the spider plate and then pull the element on the tie road.

Revolve the element and take out from housing through manhole.

After replacement of element, the system can be now put into operation.

294

CHAPTER-22

PROCESS DIAGRAMS (FROM P&ID)

295

PROCESS DIAGRAMS

NOTE: DRAWINGS ARE AVAILABLE IN HARD COPY FORM.

296

CHAPTER-23

EQUIPMENT HANDLING PROCEDURE

297

EQUIPMENT HANDLING PROCEDURE :

1.PUMPS

Pump is used to transfer liquids from one place to other. Pumps are of three types:

(A) Centrifugal pump

(B) Reciprocating pump

(C) Rotary/Gear pump.

1.A CENTRIFUGAL PUMP

These are most widely used. A centrifugal pump consists of following parts:

Motor, bearing housing, coupling, pump casing, impeller and shaft, mechanical

seal/gland packing, cooling, flushing and quenching systems.

(A) Start-Up Procedure

1. COLD PUMP

Check the mechanical/electrical completion.

Check the quality and level of lube oil. Change/top up lube oil, if required.

Rotate the shaft by hand to ensure that it is free.

Energize the motor.

Commission cooling water if provided.

Commission quenching/flushing medium to seal /gland packing. Adjust pressure.

Open suction valve and fill the casing with liquid. Bleed/Vent if necessary.

Press/start button and check direction of rotation.

Check the discharge pressure and wait till amperage comes down

Open discharge valve gradually.

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Check the amperage of the motor. Adjust the load, if required in consultation with

Panel Operator.

Check for any abnormal conditions like vibrations, abnormal sound, leakage, bearing

temperature etc.

2. HOT PUMP

The procedure is same as that for cold pump except for the following additional

points.

Ensure that pump is in warm-up condition

Close the warm-up valve (across NRV of discharge line).

(B) Shut down procedure

Close the discharge block valve fully.

Stop the motor.

Open warm up b/v for hot pump to keep it hot. Ensure that the pump is not rotating.

(C) Change over of the pumps

Start the stand-by pump as per standard procedure.

Open the discharge valve gradually. Simultaneously close the discharge valve of

running pump and keep a watch on the discharge pressure gauge/flow-meter.

Switch off the originally running pump.

Consult the Panel Operator for any variation in flow

Open warm up b/v of hot pump to keep it warm up.

1.B RECIPROCATING PUMP

This is positive displacement pump; hence an outlet must be available for the liquid displaced

otherwise the system will get over-pressurized and leads to equipment damage.

In reciprocating pump liquid is displaced from suction to discharge by the reciprocating

movement of the piston or plunger in a cylinder. The pump consists of following parts:

Motor, gear-box coupling, pump cylinder, piston/plunger, stroke adjuster, safety valves,

suction/discharge valves.

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(A) Start Up Procedure

Check mechanical/electrical completion.

Check the quality and level of lube oil.

Rotate the shaft by hand to ensure that it is free.

Check the minimum flow circuit and discharge relief valve in line.

Adjust the stroke length in case of dosing pumps.

Start the motor by push-button.

Watch the discharge pressure. If pressure continues to increase beyond normal

pressure, stop pump immediately and check the line-up.

Check for unusual noise, vibrations, and rise in bearing temperatures of

motors and pumps.

Note: Discharge valve of reciprocating pump should never be closed/throttled while the

motor is running.

(B) Shut-Down Procedure

Stop the motor.

Do not close suction/discharge valve unless it is to be handed over to maintenance.

(C) Change-Over Of The Pumps

Start the stand-by pump as per standard procedure.

Immediately switch off originally running pump as soon as the pressure starts

increasing.

1.C ROTARY/GEAR PUMP

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In this pump rotary vanes/gears/lobes displace liquid from suction to discharge. This is

also a positive displacement pump. It consists of following parts:

Motor, coupling, pump casing, vanes/gears/lobes, safety valve, bearing housing.

The start-up, shut-down and change-over procedures are identical to those of

reciprocating pump.

Routine Checks

Following checks should be carried out regularly.

Quality and level of lube oil.

Pump and motor bearing temperatures.

Abnormal sound and vibrations

Leakage

Pressure gauges

2. ID/FD FANS

FD fan supplies combustion air to the furnace and ID fan maintains the furnace pressure.

Main parts of ID/FD fans are:

Motor, bearing housing, coupling, rotor, impeller, suction vanes, discharge dampers

etc.

Pre-Start-Up Checks

Check mechanical completion.

Ensure free rotation of shaft.

Energize the motor.

Check the quality and level of lube oil in the bearing housing.

Ensure free movement of suction vanes.

Start-Up Procedure

Close the discharge damper.

Close suction vanes.

Line up air duct/flue gas duct.

Bypass FD/ID fan interlocks for furnaces.

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Start fan motor.

Check the direction of rotation and any abnormality.

Open discharge damper.

Slowly open suction vanes of FD and ID fans and adjust air flow/furnace pressure

respectively, as per requirement.

Shut Down Procedure

Switch off motor.

Close suction vanes and discharge dampers.

Routine Checks

Record pressure, flow, current and bearing temperature.

Check lube oil quality and level.

Check for abnormal sound, vibrations or any other abnormal condition.

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Au5 Online Operating Manual

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