EPIC for Gas Sweetening Facilities Project (GSF)
at Mesaieed & Dukhan
Part-1 SRU (Mesaieed)
Doc. No.: 2970-0-22-0001
Rev.: 0
Date: 03/09/2012
Page: 2 of 517
TITLE: OPERATION AND MAINTENANCE MANUAL
REVISION DESCRIPTION SHEET
Rev.
Para.
0
Revision Description
For Review
Hold
No.
Para.
1
2.3.1
Vendor supplied MSDS of MDEA
2
2.3.2
Vendor supplied MSDS of Antifoam
3
2.3.3
Vendor supplied MSDS of Corrosion Inhibitor
4
2.3.4
Vendor supplied MSDS of Caustic
5
2.3.5
Vendor supplied MSDS of Biocide
6
2.3.6
Vendor supplied MSDS of Scale Inhibitor
7
2.3.7
Vendor supplied MSDS of Oxygen Scavenger
8
2.3.8
Vendor supplied MSDS of Complex Product
9
4.5.4
5.4.3
Instrument Air Compressor loading and unloading pressure set
points/lead/lag compressor loading and unloading pressure set
points
10
4.11.3.1
4.11.3.2
4.11.3.3
7.2.6
Demineralized Water Package operating set point/alarm and trip
set points
11
4.13.3.1
4.13.3.2
4.13.3.4
4.13.3.5
4.13.3.6
4.13.3.7
7.2.8
Steam Generation Package: operating set point/alarm and trip
set points
Description of Hold
EPIC for Gas Sweetening Facilities Project (GSF)
at Mesaieed & Dukhan
Part-1 SRU (Mesaieed)
Doc. No.: 2970-0-22-0001
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TITLE: OPERATION AND MAINTENANCE MANUAL
CONTENTS
SECTION I
1.1
1.2
1.3
1.4
OBJECTIVE ............................................................................. 11
ABBREVIATION ......................................................................... 11
UNITS OF MEASUREMENT ............................................................. 12
GENERAL DESCRIPTION ............................................................... 13
SECTION II
2.1
2.2
2.3
2.3.1
2.3.2
2.3.3
2.3.4
2.3.5
2.3.6
2.3.7
2.3.8
2.3.9
OVERVIEW OF SRU UPGRADE FACILITIES ........................ 20
PROCESS ................................................................................ 21
SRU Upgrade Facilities Overview ................................................... 21
Acid Gas Enrichment Unit (AGEU) .................................................. 21
Sulphur Recover Unit Process Description ......................................... 24
Tail Gas Treatment Unit (TGTU) .................................................... 26
Tail Gas Incinerator ................................................................... 29
Amine Drain System .................................................................. 31
NEW UTILITY FACILITIES.............................................................. 33
Instrument and Plant Air ............................................................. 33
Demineralised Water System ........................................................ 35
Sea Cooling Water System ........................................................... 37
Boiler Feed Water System ........................................................... 39
Steam Generation Package 6848-A-02A/B/C...................................... 41
Fuel Gas System ....................................................................... 44
Effluent and Waste Water Treatment Unit ........................................ 46
FIRE WATER & DELUGE SYSTEM ..................................................... 48
Fire Water System .................................................................... 48
Deluge System ......................................................................... 48
SECTION IV
4.1
4.1.1
4.1.2
4.2
4.2.1
HEALTH SAFETY AND ENVIRONMENT ............................ 15
HEALTH, SAFETY AND ENVIRONMENT (HSE) ....................................... 16
LEAKAGE OF ACID GAS ................................................................ 16
HAZARDS IN HANDLING CHEMICALS ................................................. 17
MDEA .................................................................................... 17
Antifoam ............................................................................... 17
Corrosion Inhibitor .................................................................... 17
Caustic .................................................................................. 17
Biocide .................................................................................. 17
Scale inhibitor ......................................................................... 17
Oxygen Scavenger ..................................................................... 17
Complex Product ...................................................................... 17
Hydrogen Sulphide .................................................................... 17
SECTION III
3.1
3.1.1
3.1.2
3.1.3
3.1.4
3.1.5
3.1.6
3.2
3.2.1
3.2.2
3.2.3
3.2.4
3.2.5
3.2.6
3.2.7
3.3
3.3.1
3.3.2
INTRODUCTION ...................................................... 10
PROCESS AND CONTROL DESCRIPTION.......................... 50
ACID GAS ENRICHMENT UNIT (AGEU) ............................................... 51
Equipment Specification ............................................................. 51
AGEU PROCESS DESCRIPTION & CONTROL ......................................... 58
SULPHUR RECOVERY UNIT ........................................................... 75
Equipment Details .................................................................... 75
EPIC for Gas Sweetening Facilities Project (GSF)
at Mesaieed & Dukhan
Part-1 SRU (Mesaieed)
Doc. No.: 2970-0-22-0001
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TITLE: OPERATION AND MAINTENANCE MANUAL
4.2.2
4.2.3
4.2.4
4.3
4.3.1
4.3.2
4.3.3
4.4
4.4.1
4.4.2
4.5
4.5.1
4.5.2
4.5.3
4.5.4
4.6
4.6.1
4.6.2
4.6.3
4.7
4.7.1
4.7.2
4.8
4.8.1
4.8.2
4.8.3
4.9
4.9.1
4.9.2
4.9.3
4.10
4.10.1
4.10.2
4.11
4.11.1
4.11.2
4.11.3
4.12
4.12.1
4.12.2
4.12.3
4.13
4.13.1
4.13.2
4.13.3
Revamped Claus Unit Process Chemistry .......................................... 77
Revamped Claus Unit Process Description ......................................... 78
Sulphur Recovery Unit Process Control ............................................ 79
TAIL GAS TREATMENT UNIT .......................................................... 89
Tail Gas Treatment Unit Equipment Specification ............................... 89
Tail Gas Treatment Unit (TGTU) Process Description............................ 92
Tail Gas Treatment Unit Control Description ..................................... 94
INCINERATOR ......................................................................... 102
Equipment Specification ............................................................ 102
Process Description and Control ................................................... 103
INSTRUMENT AIR PACKAGE.......................................................... 107
Instrument Air Compressor Package ............................................... 107
Instrument Air Dryer Package ...................................................... 108
Instrument Air Package Description ............................................... 109
Instrument Air Package Control Description ..................................... 110
EFFLUENT & WASTE WATER TREATMENT ......................................... 112
Equipment Specification ............................................................ 112
Effluent and Waste Water Treatment Process Description .................... 116
Effluent & Waste Water Treatment Control Description ....................... 118
LP FUEL GAS .......................................................................... 123
Equipment Specification ............................................................ 123
Fuel Gas System Process Description.............................................. 123
SEA COOLING WATER SYSTEM ...................................................... 125
Equipment Specification ............................................................ 125
Sea Cooling Water System Process Description .................................. 126
Sea Cooling Water Control .......................................................... 127
Electrochlorination Package ........................................................ 128
Equipment Specification ............................................................ 128
Electro Chlorination System Description ......................................... 131
Electro chlorination Package Control ............................................. 132
NGL-4 SEA WATER FILTERS.......................................................... 133
Equipment Specification ............................................................ 133
NGL-4 Sea Water Filters S-8840A/B Description ................................. 134
DEMINERALISED WATER SYSTEM ................................................... 134
Equipment specification ............................................................ 134
Demineralised Water System Process Description............................... 138
Demineralised Water System Control description ............................... 141
BOILER FEED WATER DEAERATOR SYSTEM ........................................ 144
Equipment specification ............................................................ 144
Boiler Feed Water De-aerator Description ....................................... 146
Boiler Feed Water Deaerator Control Description ............................... 148
STEAM GENERATION PACKAGE ..................................................... 151
Equipment Specifications ........................................................... 151
Steam Generation Package Process Description ................................. 154
Control Description .................................................................. 165
EPIC for Gas Sweetening Facilities Project (GSF)
at Mesaieed & Dukhan
Part-1 SRU (Mesaieed)
Doc. No.: 2970-0-22-0001
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Date: 03/09/2012
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TITLE: OPERATION AND MAINTENANCE MANUAL
4.14
4.14.1
4.14.2
4.14.3
4.14.4
4.14.5
4.14.6
4.14.7
4.14.8
CHEMICAL INJECTION SYSTEMS ..................................................... 177
Antifoam Injection Package 9103-A-11 ........................................... 177
Caustic Injection Package 9103-A-13.............................................. 179
Corrosion Inhibitor Injection Package 9103-A-12 ................................ 181
Complex Product Injection Package 6834-A-09 .................................. 184
Oxygen Scavenger Injection Package 6834-A-09................................. 187
Biocide Injection Package 6932-A-06.............................................. 189
Scale Inhibitor Injection Package 6932-A-07 ..................................... 192
Catalyst Injection Package 9101-A-01............................................. 195
SECTION V
5.1
5.2
5.3
5.3.1
5.4
5.4.1
5.4.2
5.4.3
5.4.4
5.4.5
5.4.6
5.5
5.5.1
5.6
5.6.1
5.6.2
5.7
5.7.1
5.7.2
5.7.3
5.7.4
5.7.5
5.7.6
5.8
5.8.1
5.8.2
5.9
5.9.1
PRE-REQUISITE FOR START-UP ................................... 198
GENERAL .............................................................................. 199
INTERFACE ACTIVITIES............................................................... 200
START-UP OF UTILITIES.............................................................. 202
Start-up Sequence ................................................................... 202
Instrument Air/Plant Air System ................................................... 202
Pre Start-up Checks.................................................................. 202
Instrument Air compressor Start-up ............................................... 203
Start-up permissive conditions: .................................................... 204
Instrument Air Dryer start-up ...................................................... 208
Instrument Air Dryer Start-up Checks ............................................. 208
Dryer Start ............................................................................ 208
Nitrogen system ...................................................................... 211
Lining up of Nitrogen from existing system to the New Distribution Header 211
Drinking water system ............................................................... 212
Lining up of Drinking Water to existing network ................................ 212
Lining up of Drinking Water to DMW Package .................................... 212
Effluent & Waste Water Treatment system ...................................... 213
Lining up of Waste Water Degasser 6922-V-07 ................................... 213
Lining up of Sour Water Stripper 6922-C-01...................................... 214
Lining up of Stripper Overhead Circulation Pump 6922-P-11A/B ............. 215
Lining up of Sour Water Stripper overhead Sour Gas ........................... 215
Pressurising Waste Water Degasser 6922-V-07 with Nitrogen ................. 215
Lining up of Sour Water Stripper Reboiler ........................................ 216
Flare system .......................................................................... 217
Start-up of LP Flare System ........................................................ 217
LP ACID GAS FLARE SYSTEM......................................................... 218
Fuel Gas System ...................................................................... 219
Line-up Fuel Gas from the Existing 1st Stage Booster Compressor
6701-K-10/20/30 in NGL-3 .......................................................... 219
5.10
Sea cooling water system ........................................................... 220
5.10.1 Pre-start up checks .................................................................. 220
5.10.2 Initial Starting and Lining Up of Sea Cooling Water ............................. 221
5.11
Electro Chlorination Package Start-up ............................................ 221
5.11.1 Normal start-up of Electro Chlorination Plant: .................................. 222
5.12
Chemical Injection System ......................................................... 224
EPIC for Gas Sweetening Facilities Project (GSF)
at Mesaieed & Dukhan
Part-1 SRU (Mesaieed)
Doc. No.: 2970-0-22-0001
Rev.: 0
Date: 03/09/2012
Page: 6 of 517
TITLE: OPERATION AND MAINTENANCE MANUAL
5.12.1
5.12.2
5.12.3
5.12.4
5.12.5
5.12.6
5.12.7
5.12.8
5.13
5.13.1
5.13.2
5.13.3
5.14
5.14.1
5.14.2
5.15
5.15.1
5.15.2
5.15.3
5.15.4
5.15.5
5.15.6
5.15.7
5.15.8
5.15.9
5.16
5.17
Complex Product Injection Package (6834-A-09) ................................ 224
Oxygen Scavenger Injection Package (6834-A-09)............................... 225
Biocide Injection Package (6932-A-06)............................................ 226
Scale Inhibitor Injection Package (6932-A-07) ................................... 227
Catalyst Injection Package (9101-A-01)........................................... 228
Antifoam Injection Package (9103-A-11) ......................................... 229
Corrosion Inhibitor Injection Package (9103-A-12) .............................. 230
Caustic Injection Package (9103-A-13)............................................ 231
Demineralized Water System ....................................................... 231
Demineralized Water Unit Start-up ............................................... 231
Demineralized Water Unit Sequence .............................................. 235
Neutralization Pit .................................................................... 238
Boiler Feed Water Deaerator system .............................................. 241
Lining up of Steam Condensate Flash Drum 6834-V-05 ......................... 241
Lining up of BFW Deaerator Package 6834-A-08 ................................. 242
Steam Generation Package Start-up .............................................. 243
Checks for Start-up .................................................................. 243
Water Filling .......................................................................... 244
Fuel Gas Line-up ..................................................................... 245
FD Fan Start-up....................................................................... 245
Burner Start-up ....................................................................... 246
Boiler Normal Start-up .............................................................. 250
Start-up from Cold Condition (Manual Mode) .................................... 251
Start-up from Hot Condition........................................................ 254
Going On Line......................................................................... 254
LEAK CHECKING OF SYSTEMS ....................................................... 255
PURGING............................................................................... 256
SECTION VI
6.1
6.2
6.3
6.3.1
6.3.2
6.3.3
6.3.3.1
6.3.3.2
6.3.4
6.4
SECTION VII
7.1
7.1.1
7.1.2
7.1.3
7.1.4
7.1.5
START-UP OF PLANT .............................................. 258
GENERAL .............................................................................. 259
START-UP SEQUENCE ................................................................ 259
START-UP OF PROCESS .............................................................. 260
Start-up of Incinerator 9101-F-14.................................................. 260
Start-Up of Acid Gas Enrichment Unit ............................................ 267
Start-Up of Sulphur Recovery Unit................................................. 283
Start-up of Reaction Furnace (9101-F-01) Burner ............................... 283
Heating Up the System .............................................................. 290
Start-up of Tail Gas Treatment Unit .............................................. 304
RAMP UP OF PLANT LOAD ........................................................... 319
OPERATION & MONITORING ...................................... 320
PROCESS PLANT OPERATION AND MONITORING .................................. 321
Acid Gas Enrichment Unit ........................................................... 321
Sulphur Recovery Unit ............................................................... 326
Tail Gas Treatment Unit ............................................................ 331
Instrumentation ...................................................................... 337
Process On-Stream Analysis and Testing .......................................... 337
EPIC for Gas Sweetening Facilities Project (GSF)
at Mesaieed & Dukhan
Part-1 SRU (Mesaieed)
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TITLE: OPERATION AND MAINTENANCE MANUAL
7.1.6
7.2
7.2.1
7.2.2
7.2.3
7.2.4
7.2.5
7.2.6
7.2.7
7.2.8
Tail Gas Incinerator .................................................................. 339
UTILITIES .............................................................................. 341
Instrument Air & Plant Air .......................................................... 341
Effluent & Waste Water Treatment ............................................... 343
Fuel gas system....................................................................... 345
Sea Cooling Water System .......................................................... 345
Electro Chlorination Package....................................................... 346
DM Water Package ................................................................... 348
Boiler feed water system ........................................................... 351
Steam Generation .................................................................... 353
SECTION VIII START-UP AFTER EMERGENCY SHUTDOWN .................... 357
8.1
8.2
8.3
8.4
8.5
GENERAL .............................................................................. 358
Tail Gas Incinerator Restart ........................................................ 358
Acid Gas Enrichment Unit Restart ................................................. 358
Sulphur Recovery Unit Restart ..................................................... 359
TGTU Restart ......................................................................... 359
SECTION IX
9.1
9.1.1
9.1.2
9.1.3
9.1.4
9.2
9.2.1
9.2.2
9.2.3
9.2.4
9.2.5
9.2.6
9.2.7
PROCESS ............................................................................... 362
Incinerator ............................................................................ 362
Acid Gas Enrichment Unit ........................................................... 362
Sulphur Recovery Unit ............................................................... 364
Tail Gas Treating Unit ............................................................... 365
UTILITIES .............................................................................. 366
Instrument air package.............................................................. 366
Effluent & Waste Water Treatment Unit ......................................... 368
Electro Chlorination Package....................................................... 368
Chemical Injection Packages ....................................................... 369
DM Water Package ................................................................... 376
Boiler Feed Water System .......................................................... 376
Steam Generation Package ......................................................... 377
SECTION X
10.1
10.1.1
10.1.2
10.1.3
10.1.4
10.2
10.2.1
10.2.2
10.2.3
10.2.4
10.2.5
10.2.6
10.2.7
10.2.8
TROUBLE SHOOTING OPERATIONS.............................. 361
PLANNED SHUTDOWN ............................................. 380
Planned Shutdown - Process ........................................................ 381
TGTU Shutdown ...................................................................... 381
SRU Shutdown ........................................................................ 384
Acid Gas Enrichment Unit Shutdown .............................................. 386
Incinerator Shutdown................................................................ 387
UTILITIES .............................................................................. 389
Steam Generation Package Shutdown ............................................ 389
Boiler Feed Water System Shutdown .............................................. 390
DM water package Shutdown ....................................................... 391
Chemical Injection System Shutdown ............................................. 392
Electro Chlorination Package Shutdown .......................................... 395
Sea cooling water Shutdown ....................................................... 396
Fuel Gas system Shutdown.......................................................... 396
Effluent & Waste Water Unit Shutdown .......................................... 397
EPIC for Gas Sweetening Facilities Project (GSF)
at Mesaieed & Dukhan
Part-1 SRU (Mesaieed)
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TITLE: OPERATION AND MAINTENANCE MANUAL
10.2.9 Instrument air Shutdown ............................................................ 398
SECTION XI
11.1
11.2
11.2.1
11.2.2
11.2.3
11.2.4
11.3
11.3.1
11.3.2
11.3.3
11.3.4
11.3.5
11.3.6
11.3.7
11.3.8
11.3.9
11.4
11.4.1
11.4.2
11.4.3
11.4.4
11.4.5
11.4.6
SECTION XII
12.1
12.2
12.2.1
12.2.2
12.3
12.4
12.4.1
12.4.2
12.4.3
12.4.4
12.4.5
12.4.6
12.4.7
12.4.8
12.5
EMERGENCY SHUTDOWN ......................................... 400
GENERAL .............................................................................. 401
PROCESS ............................................................................... 403
Acid Gas Enrichment Unit ........................................................... 403
Sulphur Recovery Unit ............................................................... 411
Tail Gas Treatment Unit ............................................................ 423
Incinerator ............................................................................ 430
UTILITIES .............................................................................. 432
Steam Generation System .......................................................... 432
Boiler Feed Water System .......................................................... 434
DM water system ..................................................................... 437
Chemical Injection System ......................................................... 439
Electro Chlorination System ........................................................ 444
Sea Cooling Water System .......................................................... 444
Fuel Gas System ...................................................................... 445
Effluent Waste Water System ...................................................... 446
Instrument Air Compressors ........................................................ 450
Utility Failure ......................................................................... 450
LP Steam Failure ..................................................................... 451
Sea Cooling Water Failure .......................................................... 451
Instrument Air Failure ............................................................... 452
Power Failure ......................................................................... 452
Boiler Feed Water Failure .......................................................... 452
Fuel Gas Failure ...................................................................... 452
MAINTENANCE ...................................................... 454
General ................................................................................ 455
PREVENTIVE MAINTENANCE ......................................................... 455
Process ................................................................................ 455
UTILITIES .............................................................................. 470
SHUTDOWN MAINTENANCE .......................................................... 485
Catalyst Loading & special procedures ........................................... 485
SRU 1st Stage & 2nd Stage Converters/Hydrogenation Reactor................. 486
Catalyst Activity & Life Expectancy ............................................... 497
Catalyst Preparation ................................................................. 499
Catalyst Management................................................................ 501
SRU Converter Catalyst Rejuvenation: ............................................ 502
SRU Converter Catalyst Stripping .................................................. 503
TGTU Hydrogenation Reactor Catalyst Oxidation: .............................. 505
Hydrogenation Reactor Sulphiding in Series with the SRU ..................... 510
Combustion Air Blower 9102-K-11A lube oil replacement...................... 512
SECTION XIII ANNEXURE ........................................................... 513
13.1
13.2
13.3
PFD/P&ID .............................................................................. 514
HEAT AND MATERIAL BALANCE ..................................................... 514
CAUSE AND EFFECT DIAGRAM....................................................... 514
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TITLE: OPERATION AND MAINTENANCE MANUAL
13.4
13.5
DESIGN BASIS ......................................................................... 514
MSDS ................................................................................... 514
SECTION XIV REFERENCE DOCUMENTS .......................................... 515
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TITLE: OPERATION AND MAINTENANCE MANUAL
SECTION I
INTRODUCTION
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TITLE: OPERATION AND MAINTENANCE MANUAL
1.1
OBJECTIVE
The purpose of this Operating & Maintenance Manual (O&M) is to provide guidance to
the operators for safe and efficient operation of the Utilities and Processing Facilities
at the SRU Upgrade Facilities at Mesaieed. This O&M Manual provides detailed
guidance on the start-up, shut-down and safe operation of the Utilities and Processing
Facilities at SRU Upgrade Facilities.
1.2
ABBREVIATION
AG
Acid Gas
AGEU
Acid Gas Enrichment Unit
AGRU
Acid gas removal unit
ATM
Atmospheric
BCS
Boiler control system
BFW
Boiler Feed Water
BMS
Burner Management System
BSR
Beavon Sulphur Recovery
BTEX
Benzene, Toluene, Ethyl Benzene, Xylene
CCR
Central Control Room
DCC
Desuperheater/Contact Condenser
DCS
Distributed Control System
DMW
Demineralised Water
ECP
Electro Chlorination Package
ESD
Emergency Shutdown
FD
Forced Draft
FV
Flow Control Valve
F&G
Fire and Gas
HAZOP
Hazard & Operability Study
HCV
Hand Control Valve
HMI
Human Machine Interface
HP
High Pressure
HSE
Health, Safety and Environment
ICSS
Integrated Control and Safety System
ITR
Inspection and Test Report
KOD
Knock Out Drum
LCP
Local Control Panel
LCS
Local Control Station
LEL
Lower Explosive Limit
LER
Local Equipment Room
LOR
Local Off Remote
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TITLE: OPERATION AND MAINTENANCE MANUAL
1.3
LP
Low Pressure
LPM
litres per minute
LV
Level Control Valve
MCC
Motor Control Centres
MDEA
Methyl Di Ethanol Amine
MMS
Machine Monitoring System
MP
Medium Pressure
MSDS
Material Safety Data Sheet
NGL
Natural Gas Liquids
O&M
Operation & Maintenance
PFD
Process Flow Diagram
P&ID
Piping and Instrument Diagram
PIL
Petrofac International Limited
PPE
Personal Protective Equipment
PSV
Pressure Safety Valve
PV
Pressure Control Valve
QP
Qatar Petroleum
RGG
Reducing Gas Generator
SRU
Sulphur Recovery Unit
TGTU
Tail Gas Treatment Unit
TLV
Threshold Limit Value
TV
Temperature Control Valve
TSV
Temperature Safety Valve
UCP
Unit Control Panel
UEL
Upper Explosive Limit
UPS
Uninterrupted Power Supply
VFD
Variable Frequency Drive
UNITS OF MEASUREMENT
Sm3/hr
3
Standard cubic meter per hour
Nm /hr
Normal cubic meter per hour
m³/hr
Cubic meter per hour
l/hr
Litres per hour
T/hr
Tonnes per hour
mg/l
Milligram per Litre
Kg/hr
Kilograms per hour
Bar (a)
Bar absolute
Bar (g)
Bar gauge
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TITLE: OPERATION AND MAINTENANCE MANUAL
mbar
Milli bar
Ppb
Parts Per Billion
ppmv
Parts Per Million by Volume
ppmw
Parts Per Million by Weight
M
Meters
Mm
2
1.4
Milli meters
m
Square meters
Kcal/hr
Kilo calories per hour
kW
Kilo Watt
GENERAL DESCRIPTION
The primary objective of the Sulphur Recovery Upgrade project is to comply with State
Environmental Regulations. The objective is met by upgrading the existing Sulphur
Recovery Facilities at NGL-3, in Mesaieed, to achieve a minimum sulphur recovery of
99.5% during normal operation.
The upgrade of the SRU includes routing additional sour gas streams from other NGL
plants (NGL-1, 2 and 4) to SRU unit along with NGL-3 AGRU 1 & 2 acid gases.
New Process systems that are included in this upgrade project are:
•
Acid Gas Enrichment Unit (AGEU)
•
Tail Gas Treating unit (TGTU)
•
Tail Gas Incinerator
•
Existing SRU is upgraded.
New utility systems that are included in this upgrade project are:
•
Instrument Air and Plant Air System
•
Nitrogen System
•
Drinking Water System
•
Oily Water Drain System
•
Effluent & Waste Water Treatment System
•
Flare System
•
LP Fuel Gas System
•
Sea Cooling Water System
•
Demineralised Water System
•
Boiler Feed Water Deaerator System
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•
Steam Generation System
•
Electrical Power System
•
Control and Safety System
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SECTION II HEALTH SAFETY AND ENVIRONMENT
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2.1
HEALTH, SAFETY AND ENVIRONMENT (HSE)
This safety section briefs about the safety features of the Sulphur Recovery Upgrade
facilities at Mesaieed which provide safety systems to protect personnel, environment
and assets from the threats of production hazards. The safety of the plant facilities is
maintained at a minimum risk level by adopting the following safety design aspects:
1. Avoiding Exposure to Potential Hazards
2. Minimising the Potential (frequency) for Hazardous occurrences (release of
Hydrocarbons, Hydrocarbon Flammable Gases and any other abnormal hazardous
event)
3. Containing and Minimising the Consequence (Fire, Explosion and Toxic Gas
releases) of the Hazards
4. Providing the Means of Escape and Evacuation from such Hazards
5. Proving a Safe Working Environment for the Plant Personnel.
2.2
LEAKAGE OF ACID GAS
While starting up of Acid Gas System that contains H2S & CO2, it is necessary to take
special precautions as follows:
1.
Area around the specific area is barricaded to prevent personnel approaching the
worksite.
2.
Personnel carrying out this operation have to take Work Permit and be aware of
the hazards associated with Nitrogen (N2), Carbon Di-oxide (CO2) and Hydrogen
Sulphide (H2S).
3.
Wear appropriate Personal Protective Equipment (PPE).
4.
As far as possible, the system to be entered is purged using N2/water prior to
opening. This also negates the threat of elemental sulphur and associated
corrosion and cracking.
5.
Pyrophoric fire prevention measures are put in place (including availability of
relevant portable fire extinguishers).
6.
Personnel involved in the operation should wear Breathing Apparatus (BA) sets.
7.
Check H2S concentration frequently after wedge open the flange.
8.
Purging using N2 is continued as necessary.
9.
When H2S concentration is NIL, the ‘All Clear’ is given and normal work activities
can recommence.
10. Ensure O2 supply by circulating fresh air through the equipment prior to making
vessel entry.
11. Follow PTW of QP.
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2.3
HAZARDS IN HANDLING CHEMICALS
2.3.1
MDEA
Refer the Vendor supplied MSDS in Section XIII (Annexure)
2.3.2
Antifoam
Refer the Vendor supplied MSDS in Section XIII (Annexure)
2.3.3
Corrosion Inhibitor
Refer the Vendor supplied MSDS in Section XIII (Annexure)
2.3.4
Caustic
Refer the Vendor supplied MSDS in Section XIII (Annexure)
2.3.5
Biocide
Refer the Vendor supplied MSDS in Section XIII (Annexure)
2.3.6
Scale inhibitor
Refer the Vendor supplied MSDS in Section XIII (Annexure)
2.3.7
Oxygen Scavenger
Refer the Vendor supplied MSDS in Section XIII (Annexure)
2.3.8
Complex Product
Refer the Vendor supplied MSDS in Section XIII (Annexure)
2.3.9
Hydrogen Sulphide
Accidental Release Measures
1.
Personal Precautions: Keep unnecessary personnel away. Ensure adequate
ventilation. Do not touch or walk through spilled material.
2.
Methods of containment: Stop the flow of material, if this is without risk.
Eliminate all ignition sources (no smoking, flares, sparks or flames in immediate
area). Prevent entry into waterways, sewers, basements or confined areas.
3.
Methods for cleaning up: Avoid dust formation. Vacuum or sweep up material and
place in a disposal container.
4.
It is likely that the liquid in the system may contain pyrophoric iron sulphide. Even
after steam-out/water washing, this may ignite when drying out in the presence
of air. Therefore, water connections for flushing should be readily available
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Hazards Identification
1. Health Hazards:
•
Hydrogen Sulphide is a highly toxic gas, rapidly causing death when inhaled in high
concentrations. Even at low concentrations irritation of the eyes, nose and throat
are possible. The following table illustrates the hazard of varying concentrations:
•
TLV for prolonged exposure: 10 ppm
•
Slight symptoms after several hours exposure: 70-150 ppm
•
Maximum Concentrations that can be inhaled for one hour without serious
effects: 170-300 ppm
•
Dangerous after exposure of 30 minutes to one hour: 400-700 ppm
•
Fatal in 30 minutes: 700 ppm and above
•
Skin absorption has been reported but is not considered significant
•
Hydrogen Sulphide can be recognized by its “rotten egg” odour. However its odour
should never be used as a means of detection because exposure even to low
concentrations may dull the sense of smell
•
Acute toxicity: The greatest danger from the inhalation of hydrogen sulphide is
from its acute effects; it is not cumulative in action
•
Exposure to moderate concentrations causes headache, dizziness, nausea and
vomiting in that order. Continued exposure may cause loss of consciousness,
respiratory failure and death if the gas concentration is high enough. In exposures
to high concentrations, loss of consciousness may occur rapidly and respiratory
failure may follow a few minutes later. After severe exposures to hydrogen
sulphide the individual may regain consciousness after several hours of treatment
but he may show evidence of permanent severe brain damage. Persons having a
significant exposure to hydrogen sulphide may develop a complete and permanent
loss of the sense of smell thus destroying any ability to detect the presence of
hydrogen sulphide
2. Chronic Exposure
Prolonged exposure to low concentrations of Hydrogen Sulphide has an irritant
effect on the mucous membranes, eyes and the respiratory tract. Eye effects have
been reported at concentrations of 20 ppm or below.
First-Aid Measures
1. General Principles: in case of exposure to hydrogen sulphide the patient should be
removed to fresh air as quickly as possible. The rescuer must be certain that he is
adequately protected against breathing the gas.
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2. Contact with skin and mucous membranes: Skin absorption is very low. Skin
discoloration is possible after contact with liquid hydrogen sulphide. If such skin
contact is suspected, the area should be thoroughly washed.
3. Contact with eyes: Eye contact with liquid and gas will cause painful irritation. In
case of eye contact keep patient in darkened room; apply ice compresses; put ice
on forehead. Send for physician. Eye irritation caused by exposure to hydrogen
sulphide requires treatment by a physician, preferably an eye specialist.
4. Inhalation: A worker who has been overcome by hydrogen sulphide must be carried
at once into uncontaminated atmosphere. If breathing has stopped, mouth to
mouth resuscitation should be started immediately. If Oxygen inhalation apparatus
is available, Oxygen should be administered by a competent person. Keep the
patient quiet and warm. Call a physician immediately. Do not give anything by
mouth to an unconscious patient.
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SECTION III OVERVIEW OF SRU UPGRADE FACILITIES
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3.1
PROCESS
3.1.1
SRU Upgrade Facilities Overview
The following facilities are part of the Sulphur Recovery Upgrade Project:
•
New Acid Gas Enrichment Unit (AGEU)
•
New Tail Gas Treating Unit (TGTU)
•
New Tail Gas Incinerator
•
Existing SRU upgrade/modification
•
Existing SRU upgrade - The SRU plant is upgraded to process the acid gas flow from
the two AGRU trains, along with the acid gas streams from NGL 1/2/4 units.
•
Utilities System Upgrade: Sea Water Cooling System, Boiler Feed Water System,
Steam Generation System, Instrument/Plant Air System, Fuel Gas System, Waste
Water System, Electrical Power System, Control & Safety System.
AGEU & TGTU are provided with common Amine System. Proprietary Amine solvent
(Dow Ucarsol HS-103) has been selected for this purpose.
3.1.2
Acid Gas Enrichment Unit (AGEU)
Lean acid gas enters the unit at a temperature of 53°C and a pressure of 0.55 barg.
This stream is cooled in an Acid Gas Coolers (9103-E-101A/B), before passing to the
Lean Acid Gas KO Drum (9103-V-14). The Lean Acid Gas KO Drum allows bulk removal
of any condensed/entrained liquid from upstream. The liquid level in the Lean Acid
Gas KO Drum is controlled by pumping the liquid via the Acid Gas KO Drum Return
Pumps (9103-P-14A/B) to the existing MDEA storage tank. Alternatively, the sour water
can be routed to the sour water stripper, via a normally closed isolation valve.
Vapour leaves the Lean Acid Gas KO Drum and fed to the Acid Gas Amine Absorber
(9103-C-11), at the bottom. The vapour passes upwards through a trayed bed in
contact with a lean amine solution. The counter current contact with the amine
solution essentially removes all the H2S and some of the mercaptans and part of the
CO2 from the vapour stream. If any BTEX exists in the lean acid gas, it is expected that
80-90% will slip directly to the Incinerator.
Treated gas leaving the top of the absorber (9103-C-11) goes to the Incinerator (9101F-14). The rich amine solution, containing absorbed acid gas, is combined with solvent
from the Tail Gas Amine Absorber (9102-C-12). It is removed from the column by the
Acid Gas Rich Amine Pump (9103-P-12A/B). This stream is then heated in the
Lean/Rich Exchanger, before it is fed to the Amine Regenerator (9103-C-12). The rich
amine flow rate is controlled to maintain the level in the Acid Gas Amine Absorber.
The amine regeneration facilities required for the Acid Gas Enrichment and Tail Gas
Treatment Units are shared with the use of a common solvent.
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In the Amine Regenerator, the rich solution is stripped counter currently with vapours
generated by the Amine Regenerator Reboiler. The bottom of the column is
maintained at a temperature by regulating the LP steam flow rate into the
Regenerator Reboiler (9103-E-13). The stripping action in the lower section removes
and releases the contaminants from the solution, such as the acid gases, mercaptans
and residual dissolved hydrocarbons.
The stripped vapours are cooled in the Regenerator Condenser (9103-E-12), and the
Regenerator Condenser Trim Cooler (9103-E-16), by regulating air flow by fans in
Regenerator Condenser and adjusting the flow rate of Sea water to the Regenerator
Condenser Trim Cooler. Any water and amine in the overhead stream is condensed and
collects in the Regenerator Reflux Drum (9103-V-12). The reflux flow rate is controlled
by maintaining the liquid level in the Regenerator Reflux Drum. Acid gas from the
Regenerator Reflux Drum passes overhead to the Sulphur Recovery Unit.
Hot lean amine solution from the Regenerator is pumped to the Amine Surge Tank
(9103-T-11) by the Hot Lean Amine Pump (9103-P-17 A/B). The Lean/Rich Exchanger
(9103-E-11), Lean Amine Cooler (9103-E-14) and Lean Amine Trim Cooler (9103-E-15)
cool the solution prior to the Amine Surge Tank. The lean solution from the Amine
Surge Tank is pumped to the Acid Gas Amine Absorber and the Tail Gas Amine
Absorber via the Lean Amine Pump (9103-P-13A/B). A slipstream is taken off after the
pump and returns to the surge tank through the Lean Amine Filter (9103-S-11), Carbon
Filter (9103-S-12) and the Fines Filter (9103-S-13). The filters remove particulate
matter from the stream as well as hydrocarbons that accumulate in the Amine
solution.
The Amine Surge Tank (9103-T-11) receives the recycle flow from the filter circuit and
the regenerator. It has the capacity to hold the whole system inventory at shut down.
The Amine Surge Tank is maintained at a slightly positive pressure, however not high
enough to be able to float on the flare header to maintain pressure and stop ingress of
Oxygen. Therefore it is provided with Nitrogen blanketing to prevent air ingress and to
minimise the risk of solution degradation.
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Fig. 1 – Acid Gas Enrichment Unit
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3.1.3
Sulphur Recover Unit Process Description
The acid gas stream from the gas treating plant enters the Acid Gas KO Drum (9101-V04) where acid water is knocked out and pumped to Amine Sump (9103-V-14). The gas
stream flows to exchanger (9101-E-06) for preheating before entering the Reaction
Furnace (9101-F-01), where the acid gas is burnt by the high intensity burner with a
controlled amount of air. Air is supplied by an electrically driven blower (9101-K01A/B) & preheated by exchanger (9101-E-05). The products of the combustion are
cooled in passing through the tube section of the Waste Heat Boiler (9101-E-07) where
a 24 barg steam is generated in the shell side. Gases and any condensed liquid sulphur
from the Waste Heat Boiler flow to the Sulphur Condenser (9101-E-01) where the gases
are cooled and the additional sulphur is condensed. The gases then passes through the
Auxiliary Burner (9101-F-02) where they are reheated by burning a split stream of acid
gas (or fuel gas) with air, before entering the first Claus Converter (9101-V-01). In this
converter the gases flow downwards through a bed of CR 4/8 mm activated alumina,
top loaded with a layer of AM 4/8 catalyst. In the converter, additional elemental
sulphur is produced and carried over in vapour phase by the hot gases. The exothermic
Claus reaction results in a temperature increase through the adiabatic converter. The
hot gases leaving the first converter are cooled in the Sulphur Condenser (9101-E-02)
by generating 5 barg steam, the condensed sulphur flows to the Sulphur Degassing Pit
(9101-T-01/01Z) through Sultraps. The gases from the Sulphur Condenser (9101-E-02)
flow through a coalescer equipped with SS wire mesh pads for the removal of any
entrained sulphur. The gases then passes through the second stage auxiliary burner
(9101-F-03) where they are reheated by burning a split stream of acid gas (or fuel gas)
with air, before entering the second Claus Converter (9101-V-02), loaded with a more
active catalyst CRS 31 and a layer of AM 4/8 mm catalyst on the top of the bed. The
Final Condenser (9101-E-04) ensures cooling of the process gases by preheating the
boiler feed water which is used in the Waste Heat Boiler (91 01-E-07) and the two LP
steam producing 1st stage & 2nd stage condenser (9101-E-01 & 9101-E-02). The process
gases from Final Condenser passes through a Final Separator (9101-V-05) to achieve
complete removal of liquid sulphur drops from the process gases. A coalescer is
provided in Final Separator (9101-V-05). From final separator, the process gas is
routed to Incinerator (9101-F-14), where all remaining sulphur compounds are burnt to
sulphur dioxide. Incineration is achieved by burning fuel gas with a slight excess of air
at a temperature of 800°C. The incinerated gas is disposed of to the atmosphere via
stack (9101-X-11). The sulphur produced in the process is extracted from all sulphur
condensers through sultraps and is routed to the Sulphur Degassing Pit (9101-T-01).
The sulphur is degassed through AQUISULF sulphur degassing process. The degassed
sulphur is then transferred to the Storage Tank 9101-T-02 by Sulphur Transfer Pumps
(9101-P-04A/B).
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Fig. 2 - Sulphur Recovery Unit
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3.1.4
Tail Gas Treatment Unit (TGTU)
The purpose of the Tail Gas Treating Unit is to reduce the hydrogen sulphide
concentration in the tail gas to a level corresponding to >99.5% total sulphur recovery.
All residual hydrogen sulphide is oxidised to sulphur dioxide before it is released to the
atmosphere.
The BSR/Amine process consists of a Beavon Sulphur Recovery (BSR) reducing or
hydrogenation section and a selective amine section. The process uses the BSR
technology to reduce all sulphur compounds in the SRU tail gas to hydrogen sulphide.
This section includes water condensation and separation upstream of the amine
section with a caustic circulation system to protect against SO2 breakthrough, which
degrades the amine and causes severe corrosion.
The amine section uses an amine solution to remove most of the hydrogen sulphide
from the treated sulphur plant tail gas while minimising the co-absorption of carbon
dioxide.
The Claus tail gas from the Final Sulphur Condenser 9101-E-04 is fed to the Reducing
Gas Generator (RGG). The purpose of the Reducing Gas Generator is to generate
reducing gases (H2 and CO). This is achieved by the combustion of fuel gas with a substoichiometric quantity of air. The production of reducing gases is regulated by
controlling the flow of the fuel gas and air. Air flow is set by the outlet temperature of
the Reducing Gas Generator 9102-F-01 whilst the fuel gas flow rate is set to be a fixed
proportion of the air flow. LP steam is fed to the Reducing Gas Generator to suppress
the formation of carbon. The flow rate of the steam is ratio-controlled according to
the fuel gas flow rate. The tail gas from the Final Sulphur Condenser is mixed with the
hot combustion products in the Reducing Gas Generator to ensure a temperature that
will favour the desired reactions in the Hydrogenation Reactor (9102-V-01).
The Hydrogenation Reactor contains a fixed bed Cobalt/Molybdenum (CoMo) catalyst.
The reactions are exothermic resulting in a temperature rise across the reactor. The
gas is cooled by the generation of LP steam in the Reactor Effluent Cooler.
The tail gas is then desuperheated and the excess water removed in the
Desuperheater/Contact Condenser (9102-C-01). This tower contains an upper packed
section, a chimney tray and a lower section containing packing and bubble cap trays.
In the lower packed section of the tower (Desuperheater section), tail gas is contacted
with a circulating stream of a mildly caustic water solution. This removes sulphur
dioxide and cools the tail gas down. The Desuperheater Circulation Pump (9102-P11A/B) pumps the caustic water solution from the bottom of the tower to the top of
the packing. Water make up is provided to the lower (Desuperheater) section, under
level control, from the top (Contact Condenser) section circulation.
The solution is maintained at an alkaline pH of around 9.0 to protect against SO2
breakthrough from the reactor. SO2 causes corrosive conditions in the Desuperheater
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Contact Condenser and the Amine Absorber, and degrades the amine. The pH of the
circulating liquid is monitored by a continuous analyser and controlled by periodic,
manual addition of fresh caustic solution. An intermittent bleed from this section
removes accumulated contaminants from the circuit.
The desuperheated gas and water vapour then passes through the (wash) bubble cap
trays and the chimney tray into the upper (Contact Condenser) packed section. Here
the gas is cooled by direct contact with a circulating water stream. The water is
pumped by the Cooling Water Circulation Pump from the chimney tray, through the
Contact Condenser Cooler where it is cooled, and back to the top of the tower. The
water that is condensed in this section is slightly sour. Some is used as make up on
demand to the lower Desuperheater section and the remainder is taken off under level
control and sent to effluent treatment. The condensed water loop is kept separate
from the water in the desuperheater circulation loop to avoid contamination with salt
products that may be formed in the Desuperheater section.
The tail gas leaves the Desuperheater Contact Condenser (9102-C-11) at a temperature
of approximately 40°C and is sent to the Tail Gas Amine Absorber (9102-C-12) which
uses a lean amine solution to remove the hydrogen sulphide from the tail gas, whilst
minimising the co-absorption of carbon dioxide.
The gas enters at the bottom of the absorber and passes through a packed bed counter
current to the lean amine solution that preferentially absorbs H2S. The lean amine
solution is supplied from the Amine Regenerator.
The Tail Gas Rich Amine Pump (9102-P-16 A/B) pumps the rich solvent solution from
the bottom of the Tail Gas Amine Absorber (9102-C-12) to the Acid Gas Amine
Absorber (9103-C-11) before it is regenerated in the Amine regenerator (9103-C-12).
The amine regeneration facilities required for the Acid Gas Enrichment and Tail Gas
Treatment Units are shared with the use of a common solvent. The H2S that is stripped
from the rich amine solution in the Amine Regenerator is fed to the Sulphur Recovery
section, thus closing the recycle loop around the SRU and TGTU sections.
Treated gas from the Tail Gas Amine Absorber passes to the Incinerator along with
that from the Acid Gas Amine Absorber and from the Sulphur Pit. The incinerator is
designed to incinerate all sulphur compounds in the streams under normal operation.
It is also used to incinerate additional streams while the TGTU is bypassed or during
start-up or abnormal operating conditions. The flue gas is released to the atmosphere
through the Stack (9101-X-11).
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Fig. 3 - Tail Gas Treatment Unit
FV-1314
XV-1331
LV-1305
FV-1304
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3.1.5
Tail Gas Incinerator
An Incinerator is provided to thermally oxidise all possible sulphur compounds to SO2 in
off gas effluents from the Acid Gas Amine Absorber, Tail Gas Amine Absorber, SRU tail
gases and vent gases from the sulphur Degassing Package. Moreover all BTEX content
of off gas effluent is also destructed.
To ensure complete combustion of these sulphur compounds the Incinerator's
combustion chamber temperature is maintained at a temperature of about 817°C by
burning fuel gas supplied with combustion air in the unit's burner. Combustion air is
supplied from 2 x 100% Incinerator Air Blowers (9101-K-12 A/B). The flows of fuel gas
and combustion air are each measured by flow and then ratio controlled to ensure the
correct amount of excess air is always maintained in the Incinerators combustion
chamber to allow the oxidation of the sulphur compounds in the tail and vent gases to
take place. An Oxygen analyser located in the Incinerator outlet combustion gases
ducting monitors the excess O2 in the Incinerators combustion gases. Adjustments may
be made to the fuel gas to air ratio controller to ensure the correct excess of O2 (3% by
Mol) is seen in the stack gases. A SOX/NOX analysers, located part way up the
Incinerator Stack (9101-X-11), monitors the Incinerator stack gases for SOX/NOX
content.
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Fig. 4 - Tail Gas Incinerator
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3.1.6
Amine Drain System
Amine drained from pumps and other equipment during times of maintenance and
plant overhaul, is collected in the Amine Sump. The Amine Sump Pump must be
started manual by operations in order to transfer the amine to the Amine System via
the Amine Sump Filter. A differential pressure indicator across the filter monitors the
filter pressure drop. In the event that the amine sump pump is not manually stopped
when the low level alarm is activated then a low low level switch will stop the pump
to prevent loss of suction damage to the pump.
To prevent air ingress into the amine sump a small flow of Nitrogen is introduced into
the amine sump and allowed to pass out of the sump to the atmosphere through
carbon canister.
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Fig. 5 - Amine Sump and Pump
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TITLE: OPERATION AND MAINTENANCE MANUAL
3.2
NEW UTILITY FACILITIES
3.2.1 Instrument and Plant Air
The new air compressor package consists of the following:
1.
Two Air Compressors (6837-K-02A/B) having a capacity of 900 Nm3/hr (dry basis)
2.
One air compressor discharge drum, (6837-V-10) is provided
•
Two Instrument Air Dryer packages, (6837-A-03/04) running at 2 X 50%, each
dryer capacity is 300 Nm3/hr (dry basis)
•
One Instrument Air Receiver (6837-V-11) with storage capacity to provide
instrument air for a period of 20 minutes following a compressor trip
The new Air System will supply instrument and plant air with the following supply
battery limit conditions for both instrument and plant air:
Design
Operating
Pressure bar (g)
9.7
7.0
Temperature (°C)
85
55/60
The new instrument and plant air headers are connected to the existing NGL-3
instrument and plant air headers respectively through cross over connection lines with
(manual isolation valves) for operation flexibility.
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Fig. 6 – Plant/Instrument Air System
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TITLE: OPERATION AND MAINTENANCE MANUAL
3.2.2
Demineralised Water System
The supply of fresh water to the new DMW Package is taken from existing Drinking
Water Storage Tanks (6834-T-01 A/B) by means of new Drinking Water Feed Pumps
(6834-P-23 A/B, one operating, one standby). Each pump is designed for a flow of
10 m3/h and supplies fresh water to the following users:
•
Demineralised Water Package
•
Cross connection to the existing fresh water network
•
Utility water to utility stations, safety showers and eye wash stations.
The Demineralised Package is based on ion exchange technology (similar to the
existing DMW Package) and consists of two identical trains. The following equipment
items are envisaged to form part of the package:
•
Two Cation Exchangers
•
Two Anion Exchangers
•
Two Demineralised-Water Regeneration Pumps
•
two Demineralised-Water Recirculation Pumps
•
One Hydrochloric Acid (HCL) Storage Tank
•
There HCL Injection Pumps
•
One Caustic (NaOH) Storage Tank
•
Three NaOH Injection Pumps
•
One Neutralisation Pit
•
One Neutralisation Pump
The DMW Package operates continuously and automatically and thus requires minimum
operator intervention. The package includes the necessary control and safety devices.
The Demineralised Water from the DMW Package is routed to Demineralised Water
Storage Tank (6834-T-08). Capacity of Demineralised Water Storage Tank is 83 m3.
Centrifugal type, DMW Feed Pumps (6834-P-24A/B one running, one standby) are used
to supply demineralised water at 3.7 barg pressure and ambient temperature, from
DMW Storage Tank to the:
•
Steam Condensate Flash Drum (6834-V-05)
•
Amine Surge Tank (9103-T-11)
•
Make-up water to Cooling Water Circulation Pump (9102-P-12 A/B)
•
Start-up water to Stripper Overhead Circulation Pump (6922-P-11 A/B)
•
Make-up water to Amine Regenerator Reflux Drum (9103-V-12)
•
Existing DMW Network System (for operational flexibility, normally no flow).
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Fig. 7 – Demineralized Water System
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TITLE: OPERATION AND MAINTENANCE MANUAL
3.2.3
Sea Cooling Water System
Two Seawater Cooling Pumps 6932-P-04A/B are installed on a new jetty and take
suction from the sea. The pumps are vertical-shaft, constant speed centrifugal pumps
and are electric motor driven. The seawater cooling pumps have a design capacity of
1600 m3/h (each) at a discharge pressure of 5.0 barg.
One pump is normally running, while the other is on standby. Each pump is capable of
supplying a normal flow of 1200 m3/h to users for SRU upgrade.
The water enters the pump through a suction pipe (stilling tube) to reduce turbulence.
A coarse mesh bar suction screen is installed at each pump to prevent seaweed and
other debris from entering the seawater supply system.
From the common discharge of seawater cooling pumps, seawater stream flows via a
new dedicated 24” main supply header to the new Filtration Package Unit (6932-S02A/B). The self cleaning rotary type Seawater Filters (one in operation and one on
standby) are capable of removing particle sizes greater than 1000 microns from
seawater and each unit is designed for a flow of 1600 m3/h. The filtered water from
filters is routed to the heat exchangers located in AGEU/TGTU and other users.
The filter skid comprises:
•
Two Rotary Filters (6932-S-02A/B) and motors
•
The 2 x 100% filters are equipped with an automatic back-flushing mechanism
which operates on intermittent basis
A small portion of the main seawater (cooling water) flow is diverted downstream of
the filters to provide seawater supply for the Electro Chlorination Unit (6932-A-05).
The Electro Chlorination Unit generates sodium hypochlorite solution. The sodium
hypochlorite solution is injected into Sea Cooling Water Pumps suction lines to control
growth of marine organisms in the Sea Cooling Water System. There is one dedicated
new Electro Chlorination Unit.
In addition, a dedicated Biocide Injection Unit (6932-A-06) for effective control of
growth of marine organisms and a dedicated Scale Inhibitor Injection Unit (6932-A-07)
to prevent formation of mineral scales in the Sea Cooling Water system are also
provided for existing as well new Sea Cooling Water Systems.
The new Cooling Water System is a once through system and the seawater returned
from the SRU upgrade facilities is discharged into existing Seawater Observation Sump
(6932-X-01) which has a retention capacity of 60 m3.
From the sump the seawater overflows to the sea. To prevent fouling the temperature
of cooling water from each exchanger outlet should not exceed the maximum
allowable temperature limit of 45°C. A tie in to the existing NGL-3/4 seawater supply
system is also provided to supply seawater from the new Sea Water Pumps.
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Fig. 8 – Sea Cooling Water System
To Existing Sea Cooling Water System
6932-S-02A/B
Cooling
Water
Filters
9103-E-101
Acid Gas
Cooler
9103-E-15
Lean Amine
Trim Cooler
9103-E-16
Regenerator
Condenser
Trim Cooler
9102-E-13A/B
Contact
Condenser
Trim Cooler
6848-T-02
Boiler Blow
Down Pit
Steam Generation
Package
Acid Gas Enrichment Unit
6932-A-05
M
M
Electro Chlorination
Package
Sea Cooling
Water Pumps
6932-P-04A
6932-A-06
Biocide Injection Package
6932-T-01
Local Chemical Drain Pit
6932-P-04B
6932-A-07
Scale Inhibitor
Injection Package
Tail Gas Tr. Unit
To Observation Sump
6932-X-01
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TITLE: OPERATION AND MAINTENANCE MANUAL
3.2.4
Boiler Feed Water System
Boiler Feed Water (BFW) is required for the generation of MP and LP steam in the gas
fired water Steam Generators (6848-A-02 A/B/C). The Boiler Feed Water, consists of a
mixture of LP steam condensate and Demineralised Water make-up.
The Boiler Feed Water system includes the following equipment:
Description
Steam condensate Flash Drum
Deaerator Feed Pumps
Equipment Tag No.
6834-V-05
6834-P-20A/B
Steam Condensate Cooler
6834-E-02
Boiler Feed Water Deaerator Package
6834-A-08
Boiler Feed Water Pumps
BFW Chemical Injection Package
• O2 Scavenger Injection Pumps
• Complex Product Injection Pumps
6834-P-22 A/B/C
6834-A-09
The Boiler Feed Water passes through a Steam Condensate Flash Drum 6834-V-05
where the flash steam cools down the inventory to 102°C to prevent cavitations in
Deaerator Feed Pumps.
The DMW Condensate is pumped by the Deaerator Feed Pumps to the heating section
of a Thermal Deaerator where all the free carbon dioxide and the oxygen up to 5 ppb
are removed by heating and scrubbing the water with the LP saturated steam at
0.2 barg pressure.
The extracted dissolved gases such as O2, CO2 and water vapour are discharged
through restriction orifice (68-RO-1305) to atmosphere.
A dose of Oxygen Scavenger is injected into the hold up section of the Deaerator to
completely eliminate the residual oxygen from the water. The capacity of the holding
section in the Deaerator is equivalent to 20 minutes.
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Fig. 9 – Boiler Feed Water System
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3.2.5
Steam Generation Package 6848-A-02A/B/C
The MP steam boiler package 6834-A-02A/B/C includes three boilers, two operating
and one stand-by. Each boiler has a nominal steam generating capacity of 45 T/h.
The Boiler Feed Water enters the external Economizer 6848-E-01A, which is a finned
tubes heat exchanger (water/flue gas). The feed water is heated by the flue gas
thermal heat in the flue gas path. In case sour fuel gas is used, the boiler feed water is
sent to a preheating water circuit installed inside the water drum, before going to the
Economiser 6848-E-01A. This is to avoid acid condensation inside the flue gas duct.
From the Economizer outlet, the feed water enters into the boiler upper drum called
“Steam Drum” 6848-V-02A. Boiler functioning relies on “steam/water natural
circulation”, with evaporating rising circuits formed by the hottest tubes of boiler
evaporating bank. Remaining tubes acts as downcomers, which feed the rising circuits.
In the boiler evaporating tubes, the mixture of saturated water & steam is produced.
Then through the steam drum internal separators, the saturated steam is separated
from the saturated water droplets. The steam then passes through the steam header
and reaches the temperature and pressure controlling stations. The pressure is
controlled by a pressure control valve 68-PV-1524 and the temperature is controlled by
water injection type Desuperheater 6848-X-03A.
The combustion air for the boiler is supplied by a Forced Draft Fan 6848-K-02A, driven
by an electric motor. At the inlet of the FD Fan 6848-K-02A, a Grid Filter 6848—03A, a
Sand Filter 6848-S-02A and a silencer 6848-X-06A are provided. Downstream of this,
the modulating inlet control damper is provided. At the outlet the air passes through a
duct that delivers air to wind box. The combustion air measuring device 68-FE-1526 is
provided in this duct. Air is supplied to the burners through the wind box.
When the combustion takes place, the high temperature flue gas pass through the
boiler furnace, enclosed by water cooled tubes.
The flue gases at the end of the combustion chamber, turn to 180° and pass through
the evaporative convective section. The convective section is located on the right side
of the furnace.
The flue gases then pass through the Economizer and reach the stack.
A Flue Gas Recirculation Fan 6848-K-03A, which takes suction from the flue gas
Economizer downstream duct and discharges to the combustion air measuring device
68-FE-1526 provided in combustion air duct, is provided. In order to meet the
specified low emissions target, at high boiler load, the burners can be operated in flue
gas recirculation mode, the combustion air is mixed with a proper flue gas flow rate
(about 15% of nominal flow rate).
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The steam generator is provided with one burner, designed to burn both sour and
sweet fuel gas. The burner is designed to have a turndown of 10:1. Burner is provided
with a pilot which is of high energy type.
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TITLE: OPERATION AND MAINTENANCE MANUAL
XV-1527
TV-1522
PV-1523
Fig. 10 – Steam Generation System
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3.2.6
Fuel Gas System
LP fuel gas is required for
• New Steam Generation Boilers 6848-A-02A/B/C
The main normal LP fuel gas supply for the new MP Steam Boiler Package (6848-A-02A/B/C) and Waste Water Degasser (6922-V-07) blanketing is supplied from the first
stage suction of the existing Booster Compressors (6701-K-10120/30) in NGL-3. In
addition, two back up sources are provided; the first is the fuel gas from (6103-K-01
A/B) with a second backup from existing 30” line to Point B. The new fuel gas supply
system will consist of a letdown station, Fuel Gas KO Drum (6236-V-05), and a supply
header to the Steam Boilers and Waste Water Degasser. The source pressure from the
take-off point is let down to 7 barg through the pressure control valve 62-PV-1301A
before entering the LP Fuel Gas KO Drum. The source pressure of the fuel gas from
6103-K-01 A/B is 20 barg whilst that of feed gas from the 30” line is 45 barg. The
former is let down to 7 barg through the pressure control valve 62-PV-1301 B and the
latter via 62-PV-1302.
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Fig. 11 – Fuel Gas System
PV-1303
Hydro Carbon Gas
Flare Header
To LP Flare
To Steam Boiler Package
6848-A-02A/B/C
XV-1301
PV-1301A
From 1st Stage
Booster Compressor
(6701-K-10/20/30)
Suction Header
To LP Hydrocarbon Flare
Header
E-19
LP Fuel Gas
KO Drum
6236-V-05
XV-1302
PV-1301B
Backup Supply Fuel
Gas from 6103-K-01A/B
XV-1303
PV-1302
To Flare Header
Backup Supply Fuel Gas
from 30" Existing Line
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3.2.7
Effluent and Waste Water Treatment Unit
The sour water resulting from the new facilities added as part of the SRU Upgrade
Project contains high levels of dissolved sulphides which need to be removed before
the waste water can be discharged to the marine environment. The acceptable levels
of sulphides is 0.1 mg/l (0.1 ppmw) and to achieve this the sour water is treated in the
sour water treatment system.
Sour water from various sources is collected in the Degassing Drum, which provides
over 20 minutes of hold-up for the waste water. The flow of waste water from
Desuperheater/Contact Condenser (9102-C-11) is continuous at a rate of 8.7 m3/h
whilst all other sources are intermittent. The sour water from the degasser is
continuously pumped under flow control by Waste Water Degasser Pumps (6922-P08A/B) to the Sour Water Stripper Unit for treatment.
In the event the Sour Water Treatment System is unavailable due to a process upset,
provision exists for manually routing the degasser liquids directly to the Observation
Sump (6922-X-04).
A balance line between Degassing Drum and Sour Water Stripper 6922-C-01 means that
the pressure in the Degassing Drum floats on the stripper operating pressure (i.e.
1.0 barg). A nitrogen supply line is provided to maintain pressure in the drum if it falls
below a certain minimum as liquids are pumped out.
The sour water from degasser drum is filtered in 6922-S-06 and then preheated in Sour
Stripped Water Exchanger 6922-E-01 before feeding to Sour Water Stripper 6922-C-01.
The Sour Water Stripper operates at 1.0 barg and has an upper section and a lower
tray section.
The sour water is stripped by the vapours generated from the Sour Water Stripper
Reboiler 6922-E-04. The Reboiler utilises LP steam to heat the sour water that comes
from the bottom of the Sour Water Stripper to 126⁰C. The condensed steam from the
Reboiler is sent to the LP Condensate system through level control.
Reflux for the column is provided by a pump-around system. Water is taken from below
tray 33 pumped by Stripper Overheads Circulation Pumps 6922-P-11A/B under flow
control, cooled in Stripper Overheads Cooler 6922-E-03 and then returned to the top tray.
The stripper overhead acid gases are routed to the AGEU (upstream of 9103-V-14). In
the event of high column pressure, excess gases are diverted to LP Acid Gas flare.
The stripped water from the stripper is pumped under level control cascaded to a flow
controller via Stripped Water Pump 6922-P-10A/B to the Sour/Stripped Water
Exchanger 6922-E-01 to preheat the feed to the stripper. The water is then routed to
the Stripper Water Cooler 6922-E-02 where it is cooled to 55°C before discharge to the
Observation Sump.
An analyser is provided in the line to the Observation Sump to monitor the sulphide
content of the stripped water stream.
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Fig. 12 – Waste Water Treatment Unit
Balance Line
LP Fuel Gas from
6236-V-05
PV 1315A
PV-1307
Waste Water from Cooling
Water Circulation pumps
9102-P-12A/B
PV 1315B
Sour Gas to TGTU
To LP Acid Gas Flare
XV 1312
PV 1307
Pressurised drain from
9102-P-12A/B
Stripper Overheads Cooler
6922-E-03
XV 1313
M
LV-1325
Water for Startup
Sour Water from Regenerator
Reflux Drum 9103-P-11A/B
Corrosion Inhibitor
NC
Waste Water Degasser
6922-V-07
FV 1316
FV 1314
Waste
Water
Stripper
6922-C-01
Stripper Overheads
Circulation Pumps
6922-P-11 A/B
TV 1327
Sour Water
Stripper
Reboiler
6922-E-04
Waste Water
Degasser Pumps
6922-P-08A/B
Sour Water Filter
6922-S-06
Sour Stripped
Water Exchanger
6922-E-01
Desuperheater FV 1315
6922-X-01
From LP Steam
Reboiler
Condensate
Drum
6922-V-09
LV 1327
LP
Condensate
Stripped Water Pumps
6922-P-10A/B
Stripped Water Cooler
6922-E-02
M
FV 1317
Stripped Water to
Observation Sump
6922-X-04
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TITLE: OPERATION AND MAINTENANCE MANUAL
3.3
FIRE WATER & DELUGE SYSTEM
3.3.1
Fire Water System
The fire water ring main for the new Process facilities is connected to the existing 12”
ring main and tie-in provided at two existing fire water ring mains 12”-6533-FW-001C12T & 12”-6533-FW-002-C12T.
The fire water ring main for the new Utilities is connected to the existing 12” ring
main and tie-in provided at two existing fire water ring mains 12”-6533-FW-006-C121
& 12”-6533-FW-107-C120.
Fire water ring main is buried with minimum 1 meter cover. Ring main block valves are
post indicator type and accessible from surface.
Fire hydrants and monitors are located at 1.5 m from road. If the distance is shorter, a
crash barrier is provided. The fire hydrants and monitors are located at 15 m from
plant/equipment/buildings they intended to protect. All fire hydrants face the plant
equipment.
Fire hydrants are 4-way outlet hydrant valves with (1000 LPM) inbuilt pressure
regulating device. Each hydrant is provided with 6” riser pipe bib nosed 3” branch
inlet and 2.5” instantaneous hose connection.
Monitors are suitable for manual operation with locking facilities in both horizontal
and vertical planes. It is capable of 360° horizontal movement and elevation 75°
above and 30° below the horizontal.
3.3.2
Deluge System
Deluge Skid is used in the new facilities as per details below.
Deluge Skid No.
91-DV-1711
Deluge Valve Size
4”
Equipment protected
Hydrogenation Reactor (9101-V-11)
Acid Gas Cooler (9103-E-101)
91-DV-1712
8”
Lean Acid Gas KO Drum (9103-V-14)
Acid Gas Amine Absorber (9103-C-11)
Deluge valves are activated by:
•
Automatically activated upon fire detection via F&G System/fusible plug loop
•
Manually locally activated by hand lever through HCV/Push button at safe distance
•
Manually/remotely activated from F&G console.
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LC
NC
Air Vessel
6 Lit. Capacity
LO
Fig. 13 – Deluge Valve Typical Installation
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TITLE: OPERATION AND MAINTENANCE MANUAL
SECTION IV
PROCESS AND CONTROL DESCRIPTION
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4.1
4.1.1
ACID GAS ENRICHMENT UNIT (AGEU)
Equipment Specification
Acid Gas Coolers
Equipment Tag No.
Process Medium (Shell/Tube)
9103-E-101A/B
Acid Gas/Sea Water
Design Pressure Shell Side, barg
6.2
Design Pressure Tube Side, barg
8.0
Design Temperature Shell Side, (Max./Min.), °C
175/0
Design Temperature Tube Side, (Max./Min.),°C
85/0
Operating Pressure Shell/Tube Side, barg
0.51/1.7
Operating Temperature, Shell Side (In/Out) °C
63/53
Operating Temperature, Tube Side (In/Out) °C
35/41.76
Design Duty, kW
Material of Construction, Shell/Tube
164
SS316L/Titanium Grade 2
Lean Acid Gas KO Drum
Equipment Tag No.
9103-V-14
Tower Diameter/Height, mm
3000/7000
Process Medium
Acid Gas
Design Pressure, barg
3.5/FV
Design Temperature, °C (Max./Min.)
175/0
Operating Pressure, barg
Operating Temperature, °C
Material of Construction, Shell/Internals
0.38
53
CS/SS316L
Acid Gas KO Drum Return Pump
Equipment Tag No.
Process Medium
3
9103-P-14A/B
Sour Water
Capacity, m /hr (Normal/Rated)
5/6.7
Driver Type
Motor
Rated Power, kW
Suction Pressure, bar(a) (Rated/Max.)
7.5
1.66/5.23
Discharge Pressure, bar(a)
5.0
Operating Temperature, °C
49
Design Temperature, °C (Max./Min.)
Material of Construction - Casing/Impeller
85/0
A351-CF8M/SS316L
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TITLE: OPERATION AND MAINTENANCE MANUAL
Acid Gas Amine Absorber
Equipment Tag No.
9103-C-11
Tower Diameter, mm
4100
Tower Height, mm
20040
Tray Nos.
10
Process Medium
Acid Gas/MDEA
Design Pressure, barg (Max./Min.)
3.5/FV
Design Temperature, °C (Max./Min.)
175/0
Operating Pressure, Top/Bottom, barg
Operating Temperature, Top/Bottom, °C
Material of Construction, Top section
Material of Construction, Bottom section
Material of Construction, Internals
0.19/0.38
46/58.1
CS+SS316L CLAD
CS
SS316L
Acid Gas Rich Amine Pumps
Equipment Tag No.
Process Medium
3
Capacity, m /hr (Normal/Rated)
Driver Type
Rated Power, kW
Suction Pressure, bar(a) (Rated/Max.)
9103-P-12A/B
Rich Amine
682/750.2
Motor
195
1.99/6.1
Discharge Pressure, bar(a)
8.5
Operating Temperature, °C
56
Design Temperature, °C (Max./Min.)
Material of Construction Casing/Impeller
85/0
A351-CF8M/SS316L
Lean/Rich Amine Exchanger
Equipment Tag No.
Process Medium
9103-E-11A/B
Rich Amine/Lean Amine
Design Pressure Lean Amine Side, barg
14.3
Design Pressure Rich Amine Side, barg
13.6
Design Temperature (Max./Min.)°C
Operating Pressure Lean/Rich Amine Side bar(g)
150/0
5.8/5.32
Operating Temperature, Lean Amine Side
(In/Out) °C
129/85
Operating Temperature, Rich Amine Side
(In/Out) °C
55/101
Design Duty, kW
34669
Material of Construction, Plates
SS 316L
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Amine Regenerator
Equipment Tag No.
9103-C-12
Tower Diameter, mm
5650
Tower Height, mm
24450
Tray Nos.
24
Design Pressure, barg (Max./Min.)
7.0/FV
Design Temperature, °C (Max./Min.)
175/0
Operating Pressure, Top/Bottom, bar(a)
2.21/2.44
Operating Temperature, Top/Bottom, °C
118/131
Material of Construction, Top section
Material of Construction, Bottom section
Material of Construction, Internals
CS+SS316L CLAD
CS
SS316L
Hot Lean Amine Pumps
Equipment Tag No.
Process Medium
3
Capacity, m /hr (Normal/Rated)
Driver Type
Rated Power, kW
Suction Pressure, bar(a) (Rated/Max.)
9103-P-17A/B
Lean Amine
717/789
Motor
195
2.84/8.9
Discharge Pressure, bar(a)
7.8
Operating Temperature, °C
131
Design Temperature, °C (Max./Min.)
Material of Construction Casing/Impeller
150/0
A351-CF18M/SS316L
Regenerator Condenser Cooler
Equipment Tag No.
Type
Process Medium
9103-E-12
Forced Draft Air Cooler
Acid Gas
No. of Fans
12
Fan Power, kW/Fan
22
Design Pressure, barg
7.0/FV
Design Temperature (Max./Min.)°C
175/0
Operating Pressure bar(a)
2.18
Operating Temperature, (In/Out) °C
118/54
Design Duty, kW
18574
Material of Construction, Header & Tubes
Alloy 825
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Regenerator Condenser Trim Cooler
Equipment Tag No.
Process Medium (Shell/Tube)
9103-E-16
Acid Gas/Sea Water
Design Pressure Shell Side barg (Max./Min.)
8.0/FV
Design Pressure Tube Side barg (Max./Min.)
8.0/FV
Design Temperature Shell Side(Min./Max.) °C
150/0
Design Temperature Tube Side (Min./Max.) °C
85/0
Operating Pressure Shell/Tube Side, barg
1.07/5.0
Operating Temperature, Shell Side (In/Out) °C
54/49
Operating Temperature, Tube Side (In/Out) °C
35/42
Design Duty, kW
Material of Construction Shell/Tube
271
SS316L/Titanium Grade-2
Regenerator Reflux Drum
Equipment Tag No.
Process Medium
9103-V-12
Acid Gas
Drum Diameter, mm
1500
Drum Height, mm
4520
Design Pressure, barg (Max./Min.)
7.0/FV
Design Temperature, °C (Max./Min.)
175/0
Operating Pressure, barg
Operating Temperature, °C
Material of Construction
1.02
49
SS316
Regenerator Reflux Drum Pumps
Equipment Tag No.
Process Medium
Capacity, m3/hr (Normal/Rated)
Driver Type
Rated Power, kW
Suction Pressure, bar(a) (Rated/Max.)
Discharge Pressure, bar(a)
Operating Temperature, °C
Design Temperature, °C (Max./Min.)
Material of Construction, Casing/Impeller
9103-P-11A/B
Regenerator Reflux Liquid
26.15/31.4
Motor
22
2.27/8.6
8.41
49
85/0
A351-CF8M/SS316L
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Regenerator Reboiler Condensate Pot
Equipment Tag No.
Process Medium
Drum Diameter, mm
Drum Height, mm
Operating Pressure, barg
Operating Temperature, °C
Design Pressure, barg (Max./Min.)
Design Temperature, °C (Max./Min.)
Material of Construction
9103-V-13
Condensate
2100
4100
4.5
155
7.0/FV
185/0
CS
Regenerator Reboiler
Equipment Tag No.
Process Medium
Design Pressure, Shell Side, barg
Design Pressure, Tube Side barg
Design Temperature, Shell side °C
Design Temperature, Tube side °C
Operating Pressure, Shell, Side barg
Operating Pressure, Tube Side barg
Operating Temperature, Shell side °C
Operating Temperature, Tube side °C
Design Duty, kW
Material of Construction, Shell side
Material of Construction, Tube side
9103-E-13
Amine
7.0/FV
7.0/FV
150/0
185/0
1.356
4.5
130
159
48413
CS
SS316L
Lean Amine Cooler
Equipment Tag No.
9103-E-14
Process Medium
Lean Amine
Design Pressure, barg, (Max./Min.)
14.3/FV
Design Temperature °C
175/0
Operating Pressure barg
4.3
Operating Temperature °C
85
Design Duty, kW
Material of Construction
30318
Header/Tubes
Alloy 825
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Lean Amine Trim Cooler
Equipment Tag No.
Process Medium
9103-E-15
Lean Amine
Design Pressure, Lean Amine Side, barg
14.3
Design Pressure, Sea Water Side, barg
8.0
Design Temperature Lean Amine Side °C
90/0
Design Temperature Sea Water Side °C
85/0
Operating Pressure Lean Amine Side barg
5.30
Operating Pressure Sea Water (In/Out) Side
barg
2.6
Operating Temperature, Lean Amine Side
(In/Out) °C
54/45
Operating Temperature, Sea Water Side
(In/Out) °C
35/45
Design Duty, kW
6821
Material of Construction, Plates
Titanium SB265
Amine Surge Tank
Equipment Tag No.
Process Medium
Size (ID/Height), mm
Design Pressure, barg (Max./Min.)
9103-T-11
MDEA
1100/5500
0.075/-0.005
Design Temperature, °C (Max./Min.)
85/0
Operating Pressure, barg
0.02
Operating Temperature, °C
45
Material of Construction
CS
Lean Amine Pumps
Equipment Tag No.
Process Medium
3
Capacity, m /hr, Normal/Rated
Driver Type
Rated Power, kW
Suction Pressure, bar(a) (Rated/Max.)
9103-P-13A/B
Lean Amine
835/919
Motor
240
1/1.59
Discharge Pressure, bar(a)
7.50
Operating Temperature, °C
45
Design Temperature, °C
85
Material of Construction, Casing/Impeller
A351-CF8M/SS316L
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Lean Amine Filter
Equipment Tag No.
Process Medium
9103-S-11
Lean Amine
Operating Pressure, barg
2.8
Clean Pressure drop, bar
0.1
Max. Allowed Pressure drop, bar, dirty
0.7
Operating Temperature, °C
45
Design Temperature, °C
Design Pressure, barg
3
85/0
9.4
Flow rate, m /hr
184
Material of Construction
CS
Activated Carbon Filter
Equipment Tag No.
Process Medium
9103-S-12
Lean Amine
Operating Pressure, barg
2.1
Clean Pressure drop, bar
0.3
Max. Allowed Pressure drop, bar
0.7
Operating Temperature, °C
45
Design Temperature, °C
85/0
Design Pressure, barg
9.4
Flow rate, m3/hr
184
Material of Construction
CS
Fines Filter
Equipment Tag No.
Process Medium
9103-S-13
Lean Amine
Operating Pressure, barg
1.4
Clean Pressure drop, bar
0.1
Max. Allowable Pressure drop, bar
0.7
Operating Temperature, °C
45
Design Temperature, °C
Design Pressure, barg
3
85/0
9.4
Flow rate, m /hr
184
Material of Construction
CS
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Amine Sump
Equipment Tag No.
Process Medium
Vessel size (ID/T/T) mm
9103-V-10
MDEA
4200/8500
Design Temperature, °C (Max./Min.)
175/0
Design Pressure, barg (Max./Min.)
7.0/FV
Operating Temperature, °C
Ambient
Operating Pressure, barg
0.05
Material of Construction
CS
Amine Sump Pump
Equipment Tag No.
Process Medium
3
Capacity, m /hr (Normal/Rated)
Driver Type
9103-P-15
Amine
11.8
Motor
Rated Power, kW
Suction Pressure, bara, Max./Rated
Operating Temperature, °C
Design Temperature, °C (Max./Min.)
Material of Construction, Casing/Impeller
15
8.4/1.03
20
175/0
A351-CF8M/SS316L
Amine Sump Filter
Equipment Tag No.
Process Medium
Size (ID/T/T), mm
Design Temperature, °C
Design Pressure, barg
3
9103-S-14
Amine
308/920
175/0
17.7
Flow rate, m /hr
10
Material of Construction
CS
4.1.2
AGEU PROCESS DESCRIPTION & CONTROL
4.1.2.1
Acid Gas Enrichment Unit Process Chemistry
The function of the amine solvent is:
To enrich the week acid gas stream from the upstream gas sweetening units in an Acid
Gas Amine Absorber so that the H2S content of the acid gas is increased to a point that
will make the gas easier to process in the downstream SRU.
The H2S in the acid gases from the upstream gas sweetening unit are absorbed by
amine solvent in the Acid Gas Amine Absorber. Similarly the H2S gases produced in the
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TGTU are absorbed by amine in the Tail Gas Amine Absorber. The combined rich
amines from both the absorber are routed to the Amine Regenerator where the H2S is
stripped from the amine by heating. The stripped gases from the regenerator system
are routed to SRU.
Hydrogen Sulphide, H2S or HSH is a weak acid and ionizes in water to form hydrogen
ions and sulphide ions.
H+ + SH-
HSH
Since it is a weak acid, only a small fraction of the HSH will ionize.
Ethanolamines are weak bases and ionize in water to form amine ions and hydroxyl
ions:
(CH3)z
(CH3)z
(CH2OHCH2)x NHy + H2O
Where for MDEA x = 2, y = 0, z = 1
(CH2OHCH2)x NHy+1 + OH-
When H2S dissolves into the solution containing the amine ions, it will react to form a
weakly bonded salt of the acid and the base.
(CH3)z
(CH3)z
(CH2OHCH2)x NHy+1 + SH(CH2OHCH2)x NHyS
The sulphide ion is thus absorbed by the amine solution.
This salt formation reaction does not go to completion. As the arrow indicates, and
equilibrium level of sulphide ion, SH- remains in the sour gas stream. The overall
reaction can be summarized by the following equation:
(CH3)z
(CH3)z
(CH2OHCH2)x NHy + H2S
(CH2OHCH2)x N HyS
Operating variables are adjusted to favour the forward reaction (absorption process)
and conversely, adjusted to favour the reverse reaction (regeneration process).
4.1.2.2
Acid Gas Enrichment Unit Process Description
Lean acid gas enters the unit at a temperature of 53°C and a pressure of 0.55 barg.
This stream is cooled in Acid Gas Coolers (9103-E-101A/B), before passing to the Lean
Acid Gas KO Drum (9103-V-14). The Acid Gas Coolers (9103-E-101A/B) are cooled by
sea cooling water. The outlet temperature of the Acid Gas Coolers (9103-E-101A/B) is
maintained at 49°C.
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The Lean Acid Gas KO Drum allows bulk removal of any condensed/entrained liquid
from upstream. The liquid level in the Lean Acid Gas KO Drum is controlled by
pumping the liquid through the Acid Gas KO Drum Return Pumps (9103-P-14A/B) to the
existing MDEA storage tank. Alternatively, the sour water can be routed to the sour
water stripper, through a normally closed isolation valve.
Vapour leaves the Lean Acid Gas KO Drum and fed to the Acid Gas Amine Absorber
(9103-C-11), at the bottom. The vapour passes upwards through a trayed section in
contact with a lean amine solution. The counter current contact with the amine
solution essentially removes all the H2S and some of the mercaptans and part of the
CO2 from the vapour stream. If any BTEX exists in the lean acid gas, it is expected that
80-90% will slip directly to the Incinerator.
The Acid Gas Amine Absorber (9103-C-11) consists of 10 numbers of valved trays. The
feed gas enters below the bottom of the bottom tray. The lean amine enters over the
top of the top tray.
Lean amine flow to the Acid Gas Amine Absorber is controlled by the flow controller
91-FIC-1501; set point for the controller 91-FIC-1501 is calculated in the block 91-FFY1502 by multiplying the acid gas/lean amine ratio set point (0.02) provided through
91-HIC-1502, with the pressure and temperature compensated acid gas flow (91-FY1502). 91-FIC-1501 regulates the lean amine flow to the acid gas amine absorber via
the control valve 91-FV-1501.
Acid gas amine absorber (9103-C-11) top pressure is controlled at 0.2 barg by the
pressure controller 91-PIC-1502. The pressure is maintained through the pressure
control valve 91-PV-1502 located in the treated gas line to the Incinerator.
Rich amine from the Tail Gas Amine Absorber enters at the bottom of the column.
Treated gas leaving the top of the absorber (9103-C-11) goes to the Incinerator
(9101-F-14). The rich amine solution, containing absorbed acid gas, is combined with
solvent from the Tail Gas Amine Absorber (9102-C-12). It is removed from the column
by the Acid Gas Rich Amine Pump (9103-P-12A/B). This stream is then heated in the
Lean/Rich Exchanger, before it is fed to the Amine Regenerator (9103-C-12). The rich
amine flow rate is controlled to maintain the level in the Acid Gas Amine Absorber.
The amine regeneration facilities required for the Acid Gas Enrichment and Tail Gas
Treatment Units are shared with the use of a common solvent.
The Amine Regenerator 9103-C-12 consists of 24 numbers of valved trays and one
chimney tray. The rich amine enters over the top of the 3rd tray from the top. The rich
amine flow is controlled by the flow controller 91-FIC-1520B. The pressure of the
Regenerator is controlled by supplying nitrogen through a pressure controller 91-PIC1539. The Regenerator Reboiler vapours enter the bottom of the vessel.
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The Reboiler is heated by LP Steam which is drawn from the steam distribution
header. Steam flow to the Regenerator Reboiler is controlled by 91-FIC-1503 which
regulates the control valve 91-FV-1503. Set point-1 (SP1) for the steam flow control is
received from the calculation block 91-FFY-1503A which multiplies the rich amine flow
controller 91-FIC-1520A output and manually provided set ratio (118.5) between steam
and rich amine through 91-HIC-1503. Set point-2 (SP2) is received from the output of
the Regenerator overhead temperature controller 91-TIC-1510. During normal
operation SP1 take precedence and when the temperature of the Regenerator over
head reaches more than 118°C SP2 will take precedence.
In the Amine Regenerator, the rich solution is stripped counter currently with vapours
generated by the Amine Regenerator Reboiler. The bottom of the column is
maintained at a temperature by regulating the LP steam flow rate into the
Regenerator Reboiler (9103-E-13). The stripping action in the lower section removes
and releases the contaminants from the solution, such as the acid gases, mercaptans
and residual dissolved hydrocarbons.
The stripped vapours are cooled in the Regenerator Condenser Cooler (9103-E-12), and
the Regenerator Condenser Trim Cooler (9103-E-16), by regulating air flow by fans in
Regenerator Condenser Cooler and adjusting the flow rate of Sea water to the
Regenerator Condenser Trim Cooler. Any water and amine in the overhead stream is
condensed and collects in the Regenerator Reflux Drum (9103-V-12). The liquid
collected from the Regenerator Reflux Drum is pumped by the Regnerator Reflux Drum
Pumps 9103-P-11 A/B back to the Regenerator. There is a provision to send the liquid
to the Waste Water Degasser 6922-V-07. The reflux flow rate is controlled by
maintaining the liquid level in the Regenerator Reflux Drum. Acid gas from the
Regenerator Reflux Drum passes overhead to the Sulphur Recovery Unit.
Hot lean amine solution from the Regenerator is pumped to the Amine Surge Tank
(9103-T-11) by the Hot Lean Amine Pump (9103-P-17 A/B). The Lean/Rich Exchanger
(9103-E-11), Lean Amine Cooler (9103-E-14) and Lean Amine Trim Cooler (9103-E-15)
cool the solution prior to the Amine Surge Tank. The lean solution from the Amine
Surge Tank is pumped to the Acid Gas Amine Absorber and the Tail Gas Amine
Absorber via the Lean Amine Pump (9103-P-13A/B). A slipstream is taken off after the
pump and returns to the surge tank through the Lean Amine Filter (9103-S-11),
Activated Carbon Filter (9103-S-12) and the Fines Filter (9103-S-13). The filters remove
particulate matter from the stream as well as hydrocarbons that accumulate in the
Amine solution.
The Amine Surge Tank (9103-T-11) receives the recycle flow from the filter circuit and
the Regenerator. It has the capacity to hold the whole system inventory at shut down.
The Amine Surge Tank is maintained at a slightly positive pressure, however not high
enough to be able to float on the flare header to maintain pressure and stop ingress of
Oxygen. Therefore it is provided with Nitrogen blanketing to prevent air ingress and to
minimise the risk of solution degradation.
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All the amine drains from the unit is collected in the Amine Sump 9103-V-10. The
collected amine is pumped to the Amine Surge Tank through the amine filters. The
amine sump is blanketed with nitrogen at a slightly positive pressure.
4.1.2.3
Acid Gas Enrichment Unit Process Control
4.1.2.3.1
Lean Acid Gas Knock Out Drum Level Control
Lean acid gas knock out drum (9103-V-14) level is maintained by ON/OFF gap
controller 91-LIC-1501 which controls the acid gas KO drum return pumps (9103-P-14
A/B) & the discharge line control valve 91-LV-1501.
91-LIC-1501 controls the ON/OFF of Acid Gas Knock Out Drum Return Pumps and
discharge line valve by sending the signal 0% or 100%.
High level of the level controller 91-LIC-1501 starts the duty Acid Gas Knock Out Drum
Return Pump & opens the level control valve 91-LV-1501. Low level of the controller
closes the level control valve 91-LV-1501 and stops the duty Acid Gas Knock Out Drum
Return Pump.
Acid Gas Knock Out Drum Return pumps ON or OFF can be done by the controller only
when the pumps are in auto mode which is selected through the switch (91-HS-1562 &
91-HS-1563).
Controller
Tag
91-LIC-1501
Control Description
Unit
Lean Acid Gas KO Drum level control
%
Alarm
Low
High
12
37
•
High high level alarm (91-LAHH-1502) in Lean acid gas KO drum closes the acid gas
block valve 91-XV-1501
•
Low low level alarm (91-LALL-1503) in Lean acid gas KO drum trips the acid gas return
pumps (9103-P-14A/B) and closes the on/off valve 91-XV-1503 located at the liquid
outlet line from acid gas KO drum (downstream of the control valve 91-LV-1501)
•
Acid Gas KO Drum Return Pumps discharge control valve 91-LV-1501 closes on
instrument air failure
4.1.2.3.2
Acid Gas Absorber Top Pressure Control
Acid gas amine absorber (9103-C-11) top pressure is controlled by the pressure
controller 91-PIC-1502. The pressure is maintained through the pressure control valve
91-PV-1502 located in the treated gas line to the Incinerator.
Alarm
Controller
Tag
Control Description
Unit
Operating
Set Point
Low
High
91-PIC-1502
Amine absorber top pressure
control
bar(g)
0.2
NA
NA
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Acid gas amine absorber top pressure control valve 91-PV-1502 opens on instrument air
failure.
4.1.2.3.3
Acid Gas/Lean Amine Flow Ratio Control
Acid gas flow to the acid gas amine absorber (9103-C-11) is measured by 91-FT-1502.
Lean amine flow to the Acid Gas Amine Absorber is controlled by the flow controller
91-FIC-1501; set point for the controller 91-FIC-1501 is calculated in the block
91-FFY-1502 by multiplying the acid gas/lean amine ratio set point (0.02) provided
through 91-HIC-1502, with the pressure and temperature compensated acid gas flow
(91-FY-1502).
91-FIC-1501 regulates the lean amine flow to the acid gas amine absorber via the
control valve 91-FV-1501.
Control Loop
Controller
Tag
91-FIC-1501
Control Description
Lean amine flow to absorber
Unit
3
m /hr
Alarm
Operating
Set Point
Low
High
487
390
536
•
High high level alarm (91-LAHH-1504) in Acid Gas Amine Absorber bottom closes the
lean amine ON/OFF valve 91-XV-1504 located at the downstream of 91-FV-1501.
•
Lean amine flow control valve 91-FV-1501 to acid gas amine absorber closes on
instrument air failure.
4.1.2.3.4
Acid Gas Amine Absorber Level Control
Rich amine solution from the TGTU Tail Gas Amine Absorber combines with the rich
amine at the bottom section of the Acid Gas Amine Absorber.
The master level controller 91-LIC-1505 controls the rich amine level at the bottom of
the Acid Gas Amine Absorber by controlling the cascaded slave rich amine flow
controller 91-FIC-1520B, which regulates the Acid Gas Rich Amine Pumps (9103-P12A/B) discharge flow to Amine Regenerator 9103-C-12 via Lean/Rich Amine Exchanger
9103-E-11A/B through the control valve 91-FV-1520 located at the inlet of the Amine
Regenerator 9103-C-12.
Controller
Tag
•
Control Description
91-LIC-1505
Absorber level control
91-FIC-1520B
Rich amine flow to Amine
Regenerator
Alarm
Unit
Operating
Set Point
Low
High
%
50
12
86
m3/hr
635
500
NA
High high level alarm (91-LAHH-1504) in Acid Gas Amine Absorber bottom activates
the ESD Level-2 shutdown
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•
Low low level alarm (91-LALL-1516) in Acid Gas Amine Absorber bottom trips the
Acid Gas Rich Amine Pumps (9103-P-12A/B)
•
Rich amine flow control valve 91-FV-1520 to Amine Regenerator closes on
instrument air failure.
4.1.2.3.5
Acid Gas Rich Amine Pumps Minimum Flow Control
Acid Gas Rich Amine Pumps (9103-P-12A/B) discharge flow is measured by 91-FT-1508
and minimum flow to Acid Gas Amine Absorber bottom is controlled by 91-FIC-1508.
The controller 91-FIC-1508 controls the pump minimum flow control valve 91-FV-1508
to Acid Gas Amine Absorber bottom.
Controller
Tag
91-FIC-1508
Control Description
Acid Gas Rich Amine Pump
minimum flow
Alarm
Unit
Operating
Set Point
Low
High
m3/hr
375
330
NA
•
Low low flow alarm (91-FALL-1510) set at 300 m3/hr in 9103-P-12A/B discharge,
trips the Acid Gas Rich Amine Pumps 9103-P-12A/B
•
Pump minimum flow control valve 91-FV-1508 opens on instrument air failure.
4.1.2.3.6
Rich Amine to Regenerator Temperature Control
Rich amine solution leaving the Lean/Rich Amine Exchanger (9103-E-11-A/B)
temperature is maintained by the temperature controller 91-TIC-1513.
Temperature controller 91-TIC-1513 is located at hot rich amine outlet leaving the
exchanger. The output from this controller resets the control valve 91-TV-1513 on the
hot lean amine solution bypass line around the Lean/Rich Amine Exchanger.
Controller
Tag
91-TIC-1513
Control Description
Rich Amine to Amine
Regenerator temperature
Control
Alarm
Unit
Operating
Set Point
Low
High
°C
104
99
109
Hot lean amine bypass control valve 91-TV-1513 locks on instrument air failure.
4.1.2.3.7
Amine Regenerator Overhead Pressure Control
Amine regenerator overhead pressure is controlled by the pressure controller 91-PIC1539. The pressure is maintained through the pressure control valve 91-PV-1539 by
controlling the nitrogen supply to the Regenerator.
91-PIC-1539 opens the Nitrogen control valve 91-PV-1539 on falling pressure in the
Regenerator over head to Regenerator Condenser Cooler.
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Controller
Tag
91-PIC-1539
Control Description
Amine Regenerator top
pressure control
Unit
Bar g
Operating
Set Point
1.2
Alarm
Low
0.95
High
1.4
Amine Regenerator 9103-C-12 top pressure nitrogen control valve 91-PV-1539 opens on
instrument air failure.
4.1.2.3.8
Amine Regenerator Level Control
The master level controller 91-LIC-1510 maintains the bottom level of Amine
Regenerator by controlling the cascaded slave lean amine flow controller 91-FIC-1530,
which regulates the Hot Lean Amine Pumps (9103-P-17A/B) discharge flow to Lean Rich
Amine Exchanger through the control valve 91-FV-1530 located at the outlet of Lean
Amine Trim Cooler 9103-E-15.
Controller
Tag
Control Description
91-LIC-1510
Amine Regenerator bottom
level control
91-FIC-1530
Lean amine flow to
9103-T-11
Alarm
Unit
Operating
Set Point
Low
High
%
50
17
82
m3/hr
669
NA
NA
•
Low low level alarm (91-LALL-1517) in Amine Regenerator bottom trips the Hot
Lean Amine Pumps (9103-P-17A/B) and closes the Hot Lean Amine ON/OFF valve
91-XV-1507 to Lean Rich Exchanger
•
High high level alarm (91-LAHH-1509) in Amine Regenerator bottom activates the
ESD level-2 shutdown
•
Lean amine outlet flow control valve 91-FV-1530 to Amine Surge Tank closes on
instrument air failure
4.1.2.3.9
Hot Lean Amine Pumps Minimum Flow Control
Hot lean amine pumps (9103-P-17A/B) discharge flow is measured by 91-FT-1512 and
pumps minimum flow to Amine Regenerator bottom is controlled by 91-FIC-1512.
Output of the controller 91-FIC-1512 controls the pump minimum flow control valve
91-FV-1512.
Controller
Tag
91-FIC-1512
Control Description
Hot Lean Amine Pump min
flow
Alarm
Unit
Operating
Set Point
Low
High
m3/hr
250
220
NA
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•
Hot Lean Amine Pumps 9103-P-17A/B discharge flow low low alarm (91-FALL-1509)
set at 200 m3/hr will activate the tripping of 9103-P-17A/B.
•
Pump minimum flow control valve 91-FV-1512 opens on instrument air failure.
4.1.2.3.10 Regenerator Condenser Cooler Control
Temperature of the acid gas flow from the Amine Regenerator overhead is controlled
by cooling the fluid to Tmax=54°C in summer and not less than Tmin=49°C in winter using
one fixed speed fan (on/off) control, and another two VSD controlled fans working
simultaneously.
The Regenerator Condenser Cooler outlet temperature is measured by 91-TT-1516 and
received by the temperature controller 91-TIC-1516. The output of this controller
sends the control signal to control the three fans.
In auto mode, the temperature controller maintains the cooler outlet temperature at
Tset= (54°C + 49°C)/2=52°C by changing the VSD rates of the following cooler fans:
•
9103-EM-12AB
•
9103-EM-12AC
•
9103-EM-12BB
•
9103-EM-12BC
•
9103-EM-12CB
•
9103-EM-12CC
•
9103-EM-12DB
•
9103-EM-12DC
The fixed speed fan (9103-EM-12AA/BA/CA/DA) operates on gap control set point
between the values Tmax=54°C & Tmin=49°C.
This scheme will be applicable for all the 4 bays simultaneously.
Details of control tags are tabulated below:
Sl. #
Motor No.
Control Tag
Remarks
1
9103-EM-12AA
91-HS-1512
Fixed speed fan
2
9103-EM-12AA
91-SY-1513
VSD
3
9103-EM-12AA
91-SY-1552
VSD
4
9103-EM-12BA
91-HS-1553
Fixed speed fan
5
9103-EM-12BB
91-HS-1554
VSD
6
9103-EM-12BC
91-HS-1555
VSD
7
9103-EM-12CA
91-HS-1556
Fixed speed fan
8
9103-EM-12CB
91-HS-1557
VSD
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Sl. #
Motor No.
Control Tag
Remarks
9
9103-EM-12CC
91-HS-1558
VSD
10
9103-EM-12DA
91-HS-1559
Fixed speed fan
11
9103-EM-12DB
91-HS-1560
VSD
12
9103-EM-12DC
91-HS-1561
VSD
High high vibration alarm of each fan trips the respective fan motors.
4.1.2.3.11 Regenerator Condenser Trim Cooler Outlet Temperature Control
91-TIC-1502 located at the outlet of the Regenerator Condenser Trim Cooler,
maintains the outlet temperature of the acid gas condensate to Regenerator Reflux
Drum.
The temperature controller adjusts the bypass control valve 91-TV-1502 and maintains
the Regenerator Condenser Trim Cooler outlet temperature 91-TT-1502.
Controller
Tag
91-TIC-1502
Alarm
Control Description
Unit
Operating
Set Point
Low
High
Regenerator Condenser Trim
Cooler Outlet Temperature
°C
49
44
54
Regenerator Condenser Cooler 9103-E-12 outlet temperature control valve 91-TV-1502
to reflux drum opens on instrument air failure.
4.1.2.3.12 Regenerator Reflux Drums Level Control
Bottom level in the Regenerator Reflux Drum level is maintained by controlling the
reflux return to the Amine Regenerator via Reflux Drum Pumps 9103-P-11A/B.
Regenerator reflux drum bottom level is controlled by the master controller 91-LIC1506 cascaded with the reflux pumps discharge flow slave controller 91-FIC-1531,
which regulates the control valve 91-FV-1531 located in the reflux inlet to Amine
Regenerator.
Controller
Tag
Control Description
91-LIC-1506
Regenerator reflux drum
level control
91-FIC-1531
Reflux to amine regenerator
Alarm
Unit
Operating
Set Point
Low
High
%
50
16
80
m3/hr
26
NA
NA
•
Low low level alarm (91-LALL-1518) in Regenerator Reflux Drum trips the Reflux
Drum Pumps (9103-P-11A/B)
•
High high level alarm (91-LAHH-1507) in Regenerator Reflux Drum closes the DM
water ON/OFF valve 91-XV-1517 to Regenerator Reflux Drum
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Reflux flow control valve 91-FV-1531 to Amine Regenerator opens on instrument
air failure.
•
4.1.2.3.13 Regenerator Reflux Drums Condensate Control
Condensate flow to the Regenerator Reflux Drum bottom is measured by 91-FT-1521
and controlled by 91-FIC-1521.
Condensate flow is controlled through the control valve 91-FV-1521.
Controller
Tag
Control Description
91-FIC-1521
Regenerator reflux drum
condensate flow control
Alarm
Unit
Operating
Set Point
Low
High
m3/hr
0.6
0.4
0.8
•
ESD valve 91-XV-1517 located at the upstream of the control valve 91-FV-1521
closes on high high level alarm 91-LAHH-1507 of Regenerator Reflux Drum
•
Condensate flow control valve 91-FV-1521 closes on instrument air failure.
4.1.2.3.13 Regenerator Reflux Drums Pressure Control
A split range pressure controller 91-PIC-1503 is provided to maintain the pressure of
Regenerator Reflux Drum (9103-V-12) by controlling the following valves:
•
Acid gas control valve 91-PV-1503B (0-50%) to acid gas KO drum 9101-V-04
•
Acid gas control valve 91-PV-1503A (50-100%) to LP Acid Gas Flare
On rising pressure 91-PIC-1503 first opens the acid gas to Acid Gas KO Drum control
valve 91-PV-1503B; further increase in pressure causes the pressure controller to open
the vent valve 91-PV-1503A to release gases to the LP Acid Gas Flare.
Fig. 14 – 91-PIC-1503 Controller Output
The above drawing shows the split range operation of 91-PV-1503A & 91-PV-1503B.
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Alarm
Controller
Tag
Control Description
Unit
Operating
Set Point
Low
High
91-PIC-1503
Regenerator Reflux Drum
pressure
bar(g
)
1
0.787
1.2
•
ESD valve 91-XV-1516 located at the acid gas to Acid Gas KO Drum control valve
downstream
•
Control valve 91-PV-1503B closes on ESD-Level-0, Level-1 & Level-2 shutdown
•
Regenerator Reflux Drum 9103-V-12 pressure control valve 91-PV-1503A to LP flare
opens on instrument air failure
•
Regenerator Reflux Drum 9103-V-12 pressure control valve 91-PV-1503B to Acid
Gas KO Drum closes on instrument air failure.
4.1.2.3.14 Regenerator Reflux Pumps Minimum Flow Control
Regenerator Reflux Pumps (9103-P-11A/B) discharge flow is measured by 91-FT-1505
and minimum flow to Amine Regenerator is controlled by 91-FIC-1505.
Output of the controller 91-FIC-1505 controls the pump minimum flow control valve
91-FV-1505.
Controller
Tag
Control Description
91-FIC-1505
Regenerator Reflux Drum
pumps to Regenerator
Alarm
Unit
Operating
Set Point
Low
High
m3/hr
20
17.6
NA
•
Low low flow alarm (91-FALL-1506) set at 16 m3/hr trips the Regenerator Reflux
Pumps 9103-P-11A/B
•
Pump minimum flow control valve 91-FV-1505 opens on instrument air failure.
4.1.2.3.15 Sour Water Flow Control to Waste Water Degasser
Sour water flow from the discharge of Regenerator Reflux Drum Pumps (9103-P-11A/B)
to the Waste Water Degasser (6922-V-07) is measured by 91-FT-1532 and sends the
signal to the flow controller 91-FIC-1532.
91-FIC-1532 regulates the flow to Waste Water Degasser via the control valve 91-FV1532.
Control Loop:
Controller
Tag
91-FIC-1532
Control Description
Sour water flow to Waste
Water Degasser
Alarm
Unit
Operating
Set Point
Low
High
m3/hr
0.17
NA
NA
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•
ESD valve 91-XV-1575 located at the downstream of the sour water flow control
valve 91-FV-1532 closes on activation of waste water degasser level (69-LI-1311)
high high alarm
•
Sour water flow control valve 91-FV-1532 closes on instrument air failure.
4.1.2.3.16 Amine Regenerator Reboiler Temperature Control
Temperature in the amine regenerator is to be maintained to allow for optimum H2S
stripping from the rich amine. Temperature control is achieved by controlling the
steam flow to the Regenerator Reboiler.
Steam flow to the Regenerator Reboiler is controlled by 91-FIC-1503 which regulates
the control valve 91-FV-1503.
Set point-1 (SP1) for the steam flow control is received from the calculation block
91-FFY-1503A which multiplies the rich amine flow controller 91-FIC-1520A output and
manually provided set ratio (118.5) between steam and rich amine through 91-HIC-1503.
Set point-2 (SP2) is received from the output of the Regenerator overhead
temperature controller 91-TIC-1510. During normal operation SP1 take precedence and
when the temperature of the Regenerator over head reaches more than 118°C SP2 will
take precedence.
Controller
Tag
Control Description
91-FIC-1503
Steam to Regenerator
Re-boiler
91-TIC-1510
Amine Regenerator (9103-C12) overhead
91-FIC-1520A
Rich amine flow control
Alarm
Unit
Operating
Set Point
Low
High
Kg/hr
72410
65816
80442
°C
118
113
123
m3/hr
635
500
NA
•
ESD valve 91-XV-1505 located on the upstream of 91-FV-1503 closes on activation
of amine regenerator bottom level 91-LI-1509 high high alarm set at 50%
•
Steam control valve 91-FV-1503 to reboiler closes on instrument air failure.
4.1.2.3.17 Regenerator Re-Boiler Condensate Pot Level Control
Regenerator Reboiler condensate is collected in the Condensate Pot (9103-V-13). Level
of the Condensate Pot is measured by 91-LT-1508 and controlled by throttling the
control valve 91-LV-1508 to LC distribution header via 91-LIC-1508.
Controller
Tag
91-LIC-1508
Control Description
Regenerator Re-boiler
Condensate Pot level
Alarm
Unit
Operating
Set Point
Low
High
%
50
12
86
Reboiler condensate control valve 91-LV-1508 will close on instrument air failure.
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4.1.2.3.18 Lean Amine Cooler Temperature Control
Temperature of the lean amine from the Lean/Rich Exchanger (9103-E-11) is
controlled by cooling the fluid to Tmax=54°C in summer and not less than Tmin=45°C in
winter using three fans: one fixed speed fan (on/off) control, and another two VSD
controlled fans working simultaneously.
The Lean Amine Cooler 9103-E-14 outlet temperature is measured by 91-TT-1518 and
controlled by the temperature controller 91-TIC-1518. The output of this controller
sends the control signal to control the three fans.
In auto mode, the temperature controller maintains the cooler outlet temperature
T set= (54°C + 45°C)/2=50°C by changing the following VSD rates:
(9103-EM-14AB/AC/BB/BC/CB/CC/DB/DC/EB/EC/FB/FC/GB/GC/HB/HC/IB/IC/JB/JC)
The fixed speed fan (9103-EM-14AA/BA/CA/DA/EA/FA/GA/HA/IA/JA) operates on gap
control set point between the values Tmax=54°C & Tmin=45°C.
This scheme will be applicable for all the 10 bays simultaneously.
Details of control tags are tabulated below:
Sl. #
Motor No.
Control Tag
Remarks
1.
9103-EM-14AA
91-HS-1514
Fixed speed fan
2.
9103-EM-14AB
91-SY-1515
VSD
3.
9103-EM-14AC
91-SY-1558
VSD
4.
9103-EM-14BA
91-HS-1519
Fixed speed fan
5.
9103-EM-14BB
91-SY-1520
VSD
6.
9103-EM-14BC
91-SY-1521
VSD
7.
9103-EM-14CA
91-HS-1522
Fixed speed fan
8.
9103-EM-14CB
91-SY-1523
VSD
9.
9103-EM-14CC
91-SY-1524
VSD
10.
9103-EM-14DA
91-HS-1525
Fixed speed fan
11.
9103-EM-14DB
91-SY-1526
VSD
12.
9103-EM-14DC
91-SY-1527
VSD
13.
9103-EM-14EA
91-HS-1528
Fixed speed fan
14.
9103-EM-14EB
91-SY-1529
VSD
15.
9103-EM-14EC
91-SY-1530
VSD
16.
9103-EM-14FA
91-HS-1531
Fixed speed fan
17.
9103-EM-14FB
91-SY-1532
VSD
18.
9103-EM-14FC
91-SY-1533
VSD
19.
9103-EM-14GA
91-HS-1534
Fixed speed fan
20.
9103-EM-14GB
91-SY-1535
VSD
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Sl. #
Motor No.
Control Tag
Remarks
21.
9103-EM-14GC
91-SY-1536
VSD
22.
9103-EM-14HA
91-HS-1537
Fixed speed fan
23.
9103-EM-14HB
91-SY-1538
VSD
24.
9103-EM-14HC
91-SY-1539
VSD
25.
9103-EM-14IA
91-HS-1540
Fixed speed fan
26.
9103-EM-14IB
91-SY-1541
VSD
27.
9103-EM-14IC
91-SY-1542
VSD
28.
9103-EM-14JA
91-HS-1543
Fixed speed fan
29.
9103-EM-14JB
91-SY-1544
VSD
30.
9103-EM-14JC
91-SY-1545
VSD
High high vibration alarm of each fan trips the respective fan motors.
4.1.2.3.19 Lean Amine Trim Cooler Outlet Temperature Control
91-TIC-1509 located at the outlet of the Lean Amine Trim Cooler (9103-E-15) maintains
the outlet temperature of the lean amine to Amine Surge Tank (9103-T-11).
The temperature controller 91-TIC-1509 adjusts the control valve 91-TV-1509 located
in the bypass line of Lean Amine Trim Cooler maintains the lean amine outlet
temperature.
Controller
Tag
91-TIC-1509
Alarm
Control Description
Unit
Operating
Set Point
Low
High
Lean amine Cooler to amine
surge tank
°C
45
40
50
Lean amine cooler bypass control valve 91-TV-1509 closes on instrument air failure.
4.1.2.3.20 Lean Amine Surge Tank Pressure Control
A split range pressure controller 91-PIC-1526 is provided to maintain the vapour space
of the tank under a slightly positive pressure. On rising pressure in the tank, 91-PIC1526 closes (0-50%) the nitrogen flow to tank via the control valve 91-PV-1526A, on
further increase in pressure the pressure controller 91-PIC-1526 opens (50-100%) the
vent valve 91-PV-1526B to release gases to the atmosphere.
Controller
Tag
91-PIC-1526
Control Description
Lean amine surge tank
(9103-T-11) pressure
Alarm
Unit
Operating
Set Point
Low
High
bar(g)
0.02
0.01
0.03
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Fig. 15 – 91-PIC-1526 Controller Output
The above drawing shows the split range operation of 91-PV-1526A & 91-PV-1526B.
•
Amine Surge Tank 9103-T-11 nitrogen line control valve 91-PV-1526A closes on
instrument air failure.
•
Amine Surge Tank 9103-T-11 control valve control valve 91-PV-1526B opens on
instrument air failure.
4.1.2.3.21 Lean Amine Pumps Minimum Flow Control
Lean amine pumps (9103-P-13A/B) discharge flow is measured by 91-FT-1511 and
minimum flow to Amine Surge Tank is controlled by 91-FIC-1511.
Output of the controller 91-FIC-1511 throttles the pump minimum flow control valve
91-FV-1511.
Control Loop:
Controller
Tag
91-FIC-1511
Control Description
Lean Amine Pumps
discharge
Alarm
Unit
Operating
Set Point
Low
High
m3/hr
375
330
NA
Low low flow (91-FALL-1515) alarm set at 300 m3/hr trips the Lean Amine Pumps
9103-P-13A/B.
4.1.2.3.22 Amine Sump Pressure Control
A split range pressure controller 91-PIC-1527 is provided to maintain the vapour space
of the tank under a slightly positive pressure. On rising pressure in the tank, 91-PIC1527 closes (0-50%) the nitrogen flow to tank via the control valve 91-PV-1527A, on
further rising pressure, the pressure controller 91-PIC-1527 opens (50-100%) the vent
valve 91-PV-1527B to release gases to the atmosphere.
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The below drawing shows the split range operation of 91-PV-1527A & 91-PV-1527B:
Fig. 16 – 91-PIC-1527 Controller Output
Control Loop:
Controller
Tag
91-PIC-1527
Control Description
Amine Sump pressure
control
Alarm
Unit
Operating
Set Point
Low
High
bar(g)
0.05
0.027
0.07
•
Amine sump 9103-V-10 nitrogen line control valve 91-PV-1527A closes on
instrument air failure
•
Amine Sump 9103-V-10 nitrogen control valve 91-PV-1527B opens on instrument air
failure.
4.1.2.3.23 Lean Amine Pumps Flow to Filter
Lean Amine Pumps (9103-P-13A/B) discharge flow to Lean Amine Filter (9103-S-11) is
controlled by 91-FIC-1507.
Output of the controller 91-FIC-1507 resets the control valve 91-FV-1507.
Controller
Tag
91-FIC-1507
Alarm
Control Description
Unit
Operating
Set Point
Low
High
Lean Amine Pumps to Lean
Amine Filter
m3/hr
155.6
125
NA
Lean Amine Pumps 9103-P-13A/B flow control valve 91-FV-1507 to filter closes on
instrument air failure.
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TITLE: OPERATION AND MAINTENANCE MANUAL
4.2
4.2.1
SULPHUR RECOVERY UNIT
Equipment Details
Process Air Blowers
Equipment Tag No.
Process Medium
Rated Capacity (Dry Base), kg/hr
9101-K-01A/B
Air
29478
Inlet Pressure, bar(a)
1.01
Inlet Temperature, °C
43
Discharge Pressure, bar(a)
1.90
Discharge Temperature, °C
49
Design Temperature, °C
120
Drive Type
Motor
Sulphur Degassing Pumps
Equipment Tag No.
Pump Type
9101-P-03A/B
Vertical Centrifugal
Process Medium
3
Liquid Sulphur
Capacity, m /hr (Normal/Rated)
130/130
Suction Pressure, bar(a), Rated/Max.
1.0/1.61
Discharge Pressure, bar(a)
Operating Temperature, °C, Normal/Max.
Design Temperature, °C
Driver Type
8.6
140/160
185
Motor
Rated Power, kW
Material of Construction, Casing/Impeller
45
Duplex SS
Sulphur Product Pumps
Equipment Tag No.
Pump Type
9101-P-04A/B
Vertical Centrifugal
Process Medium
3
Liquid Sulphur
Capacity, m /hr (Normal/Rated)
130/130
Suction Pressure, bar(a), Rated/Max.
1.0/1.61
Discharge Pressure, bar(a)
Operating Temperature, °C, Normal/Max.
Design Temperature, °C
Driver Type
Rated Power, kW
Material of Construction, Casing/Impeller
8.6
140/160
185
Motor
45
Duplex SS
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TITLE: OPERATION AND MAINTENANCE MANUAL
Sulphur Tank Pumps
Equipment Tag No.
9101-P-15A/B
Process Medium
Liquid Sulphur
3
Capacity, m /hr (Normal/Rated)
7.4/8.14
Suction Pressure, bar(a), Rated/Max.
0.9/2.5
Discharge Pressure, bar(a)
9.6
Operating Temperature, °C, Normal/Max.
160
Design Temperature, °C
185
Driver Type
Motor
Rated Power, kW
Material of Construction, Casing/Impeller
11
A216WCB
Sulphur Degassing Pit
Equipment Tag No.
9101-T-01B
Size, (L/W/D), mm
10800/7000/3000
Process Medium
Operating Temperature, °C, Normal/Min.
Liquid Sulphur
140/127
Operating Pressure, bar(g)
ATM
Design Temperature, °C
185
Design Pressure, bar(g)
0.02/-0.005
Material of Construction
Reinforced Concrete
Sulphur Degassing Pumps
Equipment Tag No.
Pump Type
9101-P-09A/B
Vertical Centrifugal
Process Medium
3
Liquid Sulphur
Capacity, m /hr (Normal/Rated)
130/130
Suction Pressure, bar(a), Rated/Max.
1.0/1.61
Discharge Pressure, bar(a)
Operating Temperature, °C, Normal/Max.
Design Temperature, °C
Driver Type
Rated Power, kW
Material of Construction, Casing/Impeller
8.6
140/160
185
Motor
45
A 995 1B/A 995 1B
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TITLE: OPERATION AND MAINTENANCE MANUAL
Sulphur Product Pumps
Equipment Tag No.
Pump Type
9101-P-10A/B
Vertical Centrifugal
Process Medium
3
Liquid Sulphur
Capacity, m /hr (Normal/Rated)
130/130
Suction Pressure, bar(a), Rated/Max.
1.0/1.61
Discharge Pressure, bar(a)
Operating Temperature, °C, Normal/Max.
Design Temperature, °C
Driver Type
8.6
140/160
185
Motor
Rated Power, kW
Material of Construction, Casing/Impeller
45
Duplex SS
Catalyst Tank
Equipment Tag No.
9101-T-09
Size, (ID/Ht), mm
700/1000
Process Medium
Catalyst
Design Temperature, °C
85
Design Pressure, bar(g)
ATM
Catalyst Metering Pumps
Equipment Tag No.
Process Medium
9101-P-11A/B
Catalyst
Design Temperature, °C
85
Design Pressure, bar(g)
2.0
Drive
Motor
Rated Power, kW
0.55
Steam Ejector
Equipment Tag No.
3
4.2.2
9101-X-03
Capacity, Nm /hr
500
Design Temperature, °C
185
Differential Pressure, bar
0.1
Revamped Claus Unit Process Chemistry
The function of a SRU is to process H2S rich acid gases to produce liquid elemental
Sulphur. The sulphur recovery Claus process combines 2 mols of H2S with 1 mol. of SO2
to form elemental sulphur.
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TITLE: OPERATION AND MAINTENANCE MANUAL
In the modified Claus process some of the H2S rich acid gas is burnt with the correct
amount of Oxygen (from air) to oxidise one third of the H2S to SO2:
Main Reactions:
H2S + 3/2O2 —> SO2 + H2O
This reaction produces a high enough temperature to trigger the Claus reaction
thermally:
2H2S + SO2 —> 3S + 2H2O
The Claus reaction is continued at progressively lower temperatures in the two
catalytic stages where the remaining H2S then combines with the SO2 & produce
elemental Sulphur.
4.2.3
Revamped Claus Unit Process Description
The acid gas stream from the gas treating plant enters the Acid Gas KO Drum (9101-V04) where acid water is knocked out and pumped to Amine Sump 9103-V-10 by the
Acid Water Pumps 9101-P-01A/B. The gas stream flows to Acid Gas Preheater (9101-E06) for preheating before entering the Reaction Furnace (9101-F-01), where the acid
gas is burnt by the high intensity burner with a controlled amount of air. Air is
supplied by an electrically driven Process Air Blower (9101-K-01A/B) & preheated by
Air Preheater (9101-E-05).
The products of the combustion are cooled in passing through the tube section of the
Reaction Furnace Boiler (9101-E-07) where a 24 bar(g) steam is generated in the shell
side. Gases and any condensed liquid sulphur from the Reaction Furnace Boiler flow to
the Reaction Furnace Condenser (9101-E-01) where the gases are cooled and the
additional sulphur is condensed. The gases then passes through the 1st Stage Auxiliary
Burner (9101-F-02) where they are reheated by burning a split stream of acid gas (or
fuel gas) with air, before entering the 1st Stage Converter (9101-V-01).
In this converter the gases flow downwards through a bed of CR 4/8 mm activated
alumina, top loaded with a layer of AM 4/8 catalyst. In the converter, additional
elemental sulphur is produced and carried over in vapour phase by the hot gases. The
exothermic Claus reaction results in a temperature increase through the adiabatic
converter. The hot gases leaving the first converter are cooled in the 1st Stage
Condenser (9101-E-02) by generating 5 barg steam, the condensed sulphur flows to the
Sulphur Degassing Pit (9101-T-01/01B) through Sultraps.
The gases from the Sulphur Condenser (9101-E-02) flow through a coalescer equipped
with SS wire mesh pads for the removal of any entrained sulphur. The gases then
passes through the 2nd Stage Auxiliary Burner (9101-F-03) where they are reheated by
burning a split stream of acid gas (or fuel gas) with air, before entering the 2nd Stage
Converter (9101-V-02), loaded with a more active catalyst CRS 31 and a layer of AM
4/8 mm catalyst on the top of the bed.
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TITLE: OPERATION AND MAINTENANCE MANUAL
The Last Condenser (9101-E-04) ensures cooling of the process gases by preheating the
Boiler Feed Water which is used in the Reaction Furnace Boiler (9101-E-07) and the
two LP steam producing Reaction Furnace Condenser (9101-E-01) & 1st Stage
Condenser (9101-E-02). The process gases from Last Condenser passes through a Final
Separator (9101-V-05) to achieve complete removal of liquid sulphur drops from the
process gases. A coalescer is provided in Final Separator (9101-V-05).
From final separator, the process gas is routed to Tail Gas Treatment Unit, where the
hydrogen sulphide concentration in the tail gas is reduced to a level corresponding to
>99.5% total sulphur recovery.
The sulphur produced in the process is extracted from all sulphur condensers through
sultraps and is routed to the Sulphur Degassing Pits (9101-T-01/9101-T-01B). The
sulphur is degassed through AQUISULF sulphur degassing process. The degassed sulphur
is then transferred to the Sulphur Storage Tank 9101-T-02 by Sulphur Product Pumps
(9101-P-04A/B & 9101-P-10A/B).
4.2.4
Sulphur Recovery Unit Process Control
4.2.4.1
Pipe Separator Level Control
The acid gas stream from NGL-3 AGRU-1 & 2 enters the pipe separator where the acid
gas is routed to the top of the separator to AGEU acid gas coolers and the bottom
liquid is drained to amine drain distribution header.
Level in the vessel is maintained by regulating the control valve 91-LV-1053, in the
pipe separator bottom to amine drain distribution header through 91-LIC-1053.
Control Loops:
Controller
Tag
91-LIC-1053
Alarm
Control Description
Unit
Operating
Set Point
Low
High
Pipe separator level control
%
50
14
98
•
Low low level alarm (91-LALL-1054) set at 33% in the pipe separator closes the
liquid outlet block valve 91-XV-1109.
•
Pipe separator level control valve 91-LV-1503 to amine drain distribution header
closes on instrument air failure.
4.2.4.2
BFW Pre-heater Temperature Control
Temperature of the heated water outlet from the BFW pre heater is monitored by
91-TT-1091 and controlled by 91-TIC-1091.
Temperature control is achieved by regulating the LP steam flow control valve
91-FV-1057 to BFW Preheater by 91-FIC-1057. The MASTER temperature controller
91-TIC-1091 is cascaded with SLAVE steam flow controller 91-FIC-1057.
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TITLE: OPERATION AND MAINTENANCE MANUAL
Controller
Tag
Control Description
Alarm
Unit
Operating
Set Point
Low
High
91-TIC-1091
BFW Preheater outlet
temperature
°C
120
115
125
91-FIC-1057
LP steam flow to BFW
Preheater
Kg/hr
860
775
947
LP steam control valve 91-FV-1057 closes on instrument air failure.
4.2.4.3
Last Condenser Outlet Tail Gas Control
Tail gas from the Last Condenser is routed to the Incinerator through 91-XV-1097
during start-up and during normal operation tail gas is routed to TGTU through 91-XV1098.
This diversion is achieved by activating the selector switch 91-HS-1052A. This opens
the valve 91-XV-1098, when 91-XV-1098 is fully open the valve 91-XV-1097 closes.
This ensures that at least one path is fully open for the tail gas to pass through without
pressuring the upstream reaction furnace.
•
High high pressure alarm 91-PAHH-1055 set at 0.73 barg opens the valve 91-XV1097 to Incinerator and closes the valve 91-XV-1098 to RGG
•
ESD valve 91-XV-1097 opens on instrument air failure
•
ESD valve 91-XV-1098 closes on instrument air failure
4.2.4.4
New Sulphur Degassing Pit Level Control
New Sulphur Degassing Pit (9101-T-01B) level is measured by 91-LT-1051 which sends
the signal to the level controller 91-LIC-1051.
Level control is achieved by regulating the control valve 91-LV-1051 to the sulphur
storage tank (9101-T-02).
Controller
Tag
91-LIC-1051
Alarm
Control Description
Unit
Operating
Set Point
Low
High
Sulphur Degassing Pit level
%
50
17
80
•
Low low level alarm 91-LALL-1052 set at 10% trips the Sulphur Degassing Pumps
(9101-P-09A/B) and Sulphur Product Pumps (9101-P-10A/B)
•
Sulphur Degassing Pit level control valve 91-LV-1051 closes on instrument air
failure.
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TITLE: OPERATION AND MAINTENANCE MANUAL
4.2.4.5
Combustion Control for 1st Stage Auxiliary Burner
During normal operation the Air/Acid Gas ratio controller maintains the temperature
of the process gas and when the acid gas flow decreases, the temperature of the
process gas is maintained by the Air to Fuel gas ratio controller. Selection of this
controller can be either manual through 91-HS-1028A or automatically when the
temperature 91-TICA-1007 of the 1st stage burner outlet reduces below the desired set
point (210°C). This reduction in temperature stops the acid gas flow in the 1st stage
auxiliary burner.
Acid gas flow to 1st stage auxiliary burner is controlled by 91-FIC-1019 and fuel gas flow
is controlled by 91-FIC-1020, set point for both the controllers is provided by 91-TICA1007 via selector switch 91-HS-1028A. 91-FIC-1019 commands the acid gas flow valve
91-FV-1019 and 91-FIC-1020 commands the fuel gas control valve 91-FV-1020.
Ratio set point (air/fuel gas) and (air/acid gas) is provided via 91-HIC-1018A and
91-HIC-1018B, respectively.
Combustion air flow is controlled by 91-FIC-1018. Set point for the controller is
provided by air/acid gas or air/fuel gas ratio calculation as per selection through
91-HS-1028B and output of the combustion air flow controller 91-FIC-1018 directly
commands the air damper valve 91-FV-1018.
Controller
Tag
Control Description
Alarm
Unit
Operating
Set Point
Low
High
°C
230
210
250
st
91-TICA-1007
1 Stage Auxiliary Burner
temperature
91-FIC-1019
acid gas flow
Sm3/hr
281.939
111
332
comb air flow
3
Sm /hr
908.768
NA
981
3
159.635
8
170
91-FIC-1018
91-FIC-1020
fuel gas flow
Sm /hr
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TITLE: OPERATION AND MAINTENANCE MANUAL
The schematic diagram for 1st stage auxiliary burner temperature control is shown
below:
Fig. 17 – 1st Stage Auxiliary Burner Temperature Control
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TITLE: OPERATION AND MAINTENANCE MANUAL
1st Stage Auxiliary Burner combustion air flow (91-FI-1133) low low alarm set at
253 Sm3/hr, acid gas flow (91-FI-1134) low low alarm set at 105 Sm3/hr and Fuel
gas Flow (91-FI-1135) low low alarm set at 7 Sm3/hr activates the following:
•
4.2.4.6
•
Closure of Fuel gas block valves 91-XV-1028 and 91-XV-1031.
•
Opening of fuel gas vent valve 91-XV-1132
•
Closure of fuel gas control valve 91-FV-1020
•
Closure of acid gas control valve 91-FV-1019
•
Closure of combustion air control valve 91-FV-1018
•
1st stage combustion air damper/control valve 91-FV-1018 opens on instrument air
failure
•
1st stage acid gas control valve 91-FV-1019 closes on instrument air failure
•
1st stage fuel gas control valve 91-FV-1020 closes on instrument air failure.
Combustion Control for 2nd Stage Auxiliary Burner
During normal operation the Air/Acid Gas ratio control maintains the temperature of
the process gas flowing through the catalytic converter and then to sulphur condenser.
When the Acid gas flow decreases, the temperature of the process gas is maintained
by the Air to Fuel gas ratio controller. The selection of this controller can be either
manual through 91-HS-1029A or automatically when the temperature 91-TIC-1019
reduces below the desired set point (210°C). This reduction in temperature stops acid
gas flow and introduce fuel gas flow in the 2nd stage Auxiliary burner.
Acid gas flow to 2nd Stage Auxiliary Burner is controlled by 91-FIC-1026 and the fuel gas
flow is controlled by 91-FIC-1027. Set point for both the controllers is provided by 2nd
Stage Auxiliary Burner temperature controller 91-TIC-1019 via selector switch
91-HS-1029A. Output of the controller 91-FIC-1026 commands the acid gas flow control
valve 91-FV-1026 and Output of the controller 91-FIC-1027 commands the fuel gas
control valve 91-FV-1027.
Ratio set point (air/fuel gas) and (air/acid gas) is provided by operator via 91-HIC1025A and 91-HIC-1025B, respectively.
Combustion air flow is controlled by 91-FIC-1025. Set point for the controller is
provided by air/acid gas or air/fuel gas ratio calculation as per selection through
91-HS-1029B. Output of the combustion air flow controller 91-FIC-1025 commands the
air damper valve 91-FV-1025.
Controller
Tag
Control Description
Alarm
Unit
Operating
Set Point
Low
High
°C
210
190
230
nd
91-TICA-1019
2 stage auxiliary burner
temperature
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TITLE: OPERATION AND MAINTENANCE MANUAL
Controller
Tag
91-FIC-1026
91-FIC-1025
91-FIC-1027
•
Control Description
Acid gas flow
combustion air flow
fuel gas flow
Alarm
Operating
Set Point
Low
High
3
Sm /hr
155.382
80
175
3
Sm /hr
519.541
NA
523
3
159.635
8
170
Unit
Sm /hr
2nd stage burner combustion air flow (91-FI-1136) low low alarm set 180 Sm3/hr,
acid gas flow (91-FI-1137) low low alarm set at 76 Sm3/hr and Fuel gas Flow (91-FI1138) low low alarm set at 7 Sm3/hr activates the following:
•
closure of Fuel gas block valves 91-XV-1031 and 91-XV-1133
•
opening of fuel gas vent valve 91-XV-1134
•
closure of fuel gas control valve 91-FV-1027
•
closure of acid gas control valve 91-FV-1026
•
closure of combustion air control valve 91-FV-1025
•
2nd stage combustion air damper/control valve 91-FV-1025 closes on instrument air
failure.
•
2nd stage acid gas control valve 91-FV-1026 closes on instrument air failure
•
2nd stage fuel gas control valve 91-FV-1027 closes on instrument air failure
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The schematic diagram for 2nd stage auxiliary burner temperature control is shown
below:
Fig. 18 - 2nd Stage Auxiliary Burner Temperature Control
9101-V-02
2
X
Air
Ratio HIC
1025B
Acid Gas
SP
FY
1025B PV
FIC
PV
1026
nd
Stage Converter
Selector
MV
HS
1029A
TICA
1019
FT
1026
Acid Gas to
2nd Stage
Burner
FV-1026
SP
FIC
PV 1027
MV
FT
1027
Fuel Gas to
2nd Stage
Burner
FV-1027
PV
Air
Ratio HIC
Fuel Gas
1025A
X
FY
1025A
HS
1029B
Selector
FT
1025
Combustion
Air to 2nd
Stage Burner
PV
Comp
PT
1002
TT
1004
SP
FY
1025
FIC
1025
MV
FV-1025
9101-F-03
2nd Stage
Auxiliary
Burner
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TITLE: OPERATION AND MAINTENANCE MANUAL
4.2.4.7
Combustion Control for Reaction Furnace
Combustion temperature in the Reaction Furnace is maintained by controlling the ratio
of fuel gas, combustion air flow rates during start-up and by acid gas, combustion air
flow rates during normal operations.
Fuel gas flow to reaction furnace is controlled by 91-FIC-1009 which commands the
fuel gas control valve 91-FV-1009. Secondary combustion air flow to reaction furnace
is controlled by 91-FIC-1002B; Set point for the controller is calculated in the block
91-FY-1009 by multiplying fuel gas flow with AIR/FG ratio, which is manually provided
via 91-HIC-1009. Secondary air flow is regulated by 91-FV-1002B.
Trim air (make-up) flow is controlled by 91-FIC-1003; set point for the controller is
provided by analyzer controller 91-AIC-1001 which measures the H2S/SO2 ratio (4:1).
91-FIC-1003 throttles the damper 91-FV-1003.
Air selection to the reaction furnace is done by 91-HS-1142 (Secondary air during
start-up and trim air during normal operations).
Acid gas flow to the reaction furnace is measured by 91-FT-1001 which determines the
quantity of combustion air to the reaction furnace. Pressure, temperature
Compensated acid gas flow to reaction furnace is indicated by 91-FI-1001A.
Acid gas analyzer value in the reflux drum is measured by 91-AI-1502. 91-HIC-1001 bias
range (80%-120%) is manually provided as (Main air flow)/(total air flow) * 100.
Main combustion air flow is controlled by 91-FIC-1002, and set point for the main
combustion air flow controller is calculated in the block 91-FFY-1001A as: 2.38*(91-AI1502/100)* (91-FI-1001A)*(91-HIC-1001)/100.
91-FFY-1001B a bias block receives the remote set point from 91-FFY-1001A, which adds
or subtracts the bias value received from the selector/auto trigger switch 91-HS-1142.
When the manipulated variable received by 91-HS-1142 is >=80%, then it adds 1.25% of
91-FIC-1002 set point at each 30sec to the bias block 91-FFY-1001B and when the
manipulated variable received by 91-HS-1142 is <=20%, then it subtracts 1.25% of
91-FIC-1002 set point at each 30 sec to the bias block 91-FFY-1001B.
Controller
Tag
91-FIC-1009
91-FIC-1002
91-FIC-1002B
91-FIC-1003
•
Control Description
Fuel gas flow
Main comb air flow
Sec comb air flow
Trim air flow
Alarm
Operating
Set Point
Low
High
3
Sm /hr
357.802
330
380
3
Sm /hr
21124.6
18437
22534
3
Sm /hr
5744.1
NA
NA
3
2057.59
NA
NA
Unit
Sm /hr
Reaction Furnace combustion air damper/control valve 91-FV-1002, 91-FV1002B and 91-FV-1003 closes on instrument air failure.
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•
Reaction furnace 9101-F-01 acid gas control valve 91-FV-1019 closes on
instrument air failure.
•
Reaction furnace 9101-F-01 fuel gas control valve 91-FV-1009 closes on
instrument air failure.
•
Reaction furnace combustion air flow low low alarm (91-FI-1129) set at
16722 sm3/hr, acid gas flow low low alarm (91-FI-1140) set at 10912 sm3/hr and
fuel gas flow low low alarm (91-FI-1130) set at 64 sm3/hr activates the tripping
of reaction furnace, 1st stage auxiliary burner and 2nd stage auxiliary burners.
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The schematic representation of Reaction Furnace control is shown below:
Fig. 19 – Reaction Furnace Combustion control
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4.3
4.3.1
TAIL GAS TREATMENT UNIT
Tail Gas Treatment Unit Equipment Specification
Combustion Air Blowers
Equipment Tag No.
Process Medium
Rated Capacity, kg/hr, Rated/Normal/
Turndown
9102-K-11A/B
Air
3175/2886/606
Design Temperature, °C
150
Inlet Pressure, bara
1.01
Discharge Pressure, bara
1.55
Drive Type
Diver Power, kW
Material of Construction, Impeller
Motor
145
SS Grade 15-5PH
Reducing Gas Generator
Equipment Tag No.
9102-F-11
Size (ID/T/T), mm
1500/4300
Operating Pressure, barg
0.44
Operating Temperature, °C
290
Design Temperature, Metal/Refractory, °C
340/1800
Design Pressure, barg
5
Material of Construction, Shell
CS
Hydrogenation Reactor
Equipment Tag No.
9102-V-11
Size (ID/T/T), mm
3100/6100
Design Temperature, Metal/Refractory, °C
340
Design Pressure, barg
3.5
Operating Pressure, barg
1.45
Operating Temperature, Inlet/Outlet °C
Material of Construction, Shell
290/327
CS, Refractory lined
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TITLE: OPERATION AND MAINTENANCE MANUAL
Reactor Effluent Cooler
Equipment Tag No.
Process Medium
9102-E-11
Process Gas
Design Pressure, Shell Side, barg
7.0/FV
Design Pressure, Tube Side, barg
7.0
Design Temperature, Shell Side, °C
185/0
Design Temperature, Tube Side, °C
340/0
Operating Pressure, Shell Side barg
6.0
Operating Pressure, Tube Side, barg
0.38
Operating Temperature, Shell Side, LP BFW/
LP Steam, °C
105/159
Operating Temperature, Tube Side (In/Out) °C
320/178
Design Duty, kW
Material of Construction, Shell & Tube
2152
CS
Start-up Gas Steam Ejector
Equipment Tag No.
9102-X-11
Design Temperature, °C
225
Design Pressure, barg
7.0
Motive Fluid
LP Steam
Steam Inlet Pressure, barg
4.5
Steam Inlet Temperature, °C
159
Material of Construction
CS
Desuperheater/Contact Condenser
Equipment Tag No.
9102-C-11
Size (ID X T/T), mm
2900/3400 X 27470
Design Temperature, °C
193/0
Design Pressure, barg
3.5/FV
Operating Pressure, Top/Bottom, barg
Operating Temperature, Top/Bottom, °C
Material of Construction, Shell/Internal
0.18/0.30
42/82
CS/SS316L
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TITLE: OPERATION AND MAINTENANCE MANUAL
Cooling Water Circulation Pumps
Equipment Tag No.
3
Capacity, m /hr (Normal/Rated)
Suction Pressure, bar(a) (Rated/Max.)
9102-P-12A/B
210.6/252.7
2.8/6.4
Discharge Pressure, bar(a)
8.4
Operating Temperature, °C
71
Design Temperature, °C (Max./Min.)
150/0
Driver Type
Motor
Rated Power, kW
Material of Construction, Casing/Impeller
75
A351-CF8M/SS316L
Desuperheater Circulation Pumps
Equipment Tag No.
3
Capacity, m /hr (Normal/Rated)
Suction Pressure, bar(a) (Rated/Max.)
9102-P-11A/B
240
1.5/5.1
Discharge Pressure, bar(a)
5.6
Operating Temperature, °C
80
Design Temperature, °C (Max./Min.)
150/0
Driver Type
Motor
Rated Power, kW
Material of Construction, Casing/Impeller
55
A351-CF8M/SS316L
Wash Water Filter
Equipment Tag No.
9102-S-15
Size (ID/T/T), mm
736/2080
Design Temperature, °C
Design Pressure, barg
3
150/0
9.6
Flow rate, m /hr
240
Operating Temperature, °C
82
Operating Pressure, barg
4.5
Clean Pressure Drop, bar
0.1
Max. Allowed Pressure Drop, bar
0.7
Size of particles to be removed, microns
5
Material of Construction
CS
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TITLE: OPERATION AND MAINTENANCE MANUAL
Contact Condenser Cooler
Equipment Tag No.
9102-E-12
Tube Side Design Pressure, barg
12.4
Tube Side Design Temperature, °C
150/0
Operating Pressure bar(a)
6.0
Operating Temperature, In/Out, °C
73/40
Design Duty, kW (Summer/Winter)
4593/7985
Material of Construction, Tubes
Alloy 825
Contact Condenser Trim Cooler
Equipment Tag No.
9102-E-13A/B
Design Pressure Shell Side, barg
12.4
Design Pressure Tube Side, barg
9.55
Design Temperature Shell Side, (Min./Max.), °C
150/0
Design Temperature Tube Side (Min./Max.)°C
85/0
Operating Pressure Shell/Tube Side barg
3.95/1.7
Operating Temperature, Shell Side, (In/Out), °C
54/40
Operating Temperature, Tube Side (In/Out) °C
35/45
Design Duty, kW
3387
Material of Construction, Shell/Tube
SS316L/Titanium Grade-2
Blowdown Pit
Equipment Tag No.
Size, (L/W/H), m
Design Pressure, barg
4.3.2
9102-T-01
1/1/1
0
Design Temperature, °C
185
Material of Construction
Concrete
Tail Gas Treatment Unit (TGTU) Process Description
The Tail Gas Treating Unit reduces the hydrogen sulphide concentration in the tail gas
to a level corresponding to >99.5% total sulphur recovery. All residual hydrogen
sulphide is oxidised to sulphur dioxide before it is released to the atmosphere.
The BSR/Amine process consists of a Reducing Gas Generator section, Hydrogenation
section, Desuperheater/Contactor section and a selective amine absorption section.
The process uses the BSR technology to reduce all sulphur compounds in the SRU tail
gas to hydrogen sulphide. This section includes water condensation and separation
upstream of the amine section with a caustic circulation system to protect against SO2
breakthrough, which degrades the amine and causes severe corrosion.
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TITLE: OPERATION AND MAINTENANCE MANUAL
The amine section uses an amine solution to remove most of the hydrogen sulphide
from the treated sulphur plant tail gas while minimising the co-absorption of carbon
dioxide.
The Claus tail gas from the Final Separator 9101-V-05 is fed to the Reducing Gas
Generator (RGG) 9102-F-11. The purpose of the Reducing Gas Generator is to generate
reducing gases (H2 and CO). This is achieved by the combustion of fuel gas with a substoichiometric quantity of air. The production of reducing gases is regulated by
controlling the flow of the fuel gas and air. Air flow is set by the outlet temperature of
the Reducing Gas Generator 9102-F-11 while the fuel gas flow rate is set to be a fixed
proportion of the air flow. LP steam is fed to the Reducing Gas Generator to suppress
the formation of carbon. The flow rate of the steam is ratio-controlled according to
the fuel gas flow rate. The tail gas from the Final Separator 9101-V-05 is mixed with
the hot combustion products in the Reducing Gas Generator to ensure a temperature
that will favour the desired reactions in the Hydrogenation Reactor (9102-V-11).
The Hydrogenation Reactor contains a fixed bed Cobalt/Molybdenum (CoMo) catalyst.
The reactions are exothermic resulting in a temperature rise across the reactor. The
gas is cooled by the generation of LP steam in the Reactor Effluent Cooler 9102-E-11.
The tail gas is then desuperheated and the excess water removed in the
Desuperheater/Contact Condenser (9102-C-11). This tower contains an upper packed
section, a chimney tray and a lower section containing packing and bubble cap trays.
In the lower packed section of the tower (Desuperheater section), tail gas is contacted
with a circulating stream of a mildly caustic water solution. This removes sulphur
dioxide and cools the tail gas down. The Desuperheater Circulation Pump (9102-P11A/B) pumps the caustic water solution from the bottom of the tower to the top of
the packing. Water make up is provided to the lower (Desuperheater) section, under
level control, from the top (Contact Condenser) section circulation.
The solution is maintained at an alkaline pH of around 9.0 to protect against SO2
breakthrough from the reactor. SO2 causes corrosive conditions in the Desuperheater
Contact Condenser and the Amine Absorber, and degrades the amine. The pH of the
circulating liquid is monitored by a continuous analyser and controlled by periodic,
manual addition of fresh caustic solution. An intermittent bleed from this section
removes accumulated contaminants from the circuit.
The desuperheated gas and water vapour then passes through the (wash) bubble cap
trays and the chimney tray into the upper (Contact Condenser) packed section. Here
the gas is cooled by direct contact with a circulating water stream. The water is
pumped by the Cooling Water Circulation Pump from the chimney tray, through the
Contact Condenser Cooler 9102-E-12 and Contact Condenser Trim Cooler 9102-E-13A/B
where it is cooled, and back to the top of the tower. The water that is condensed in
this section is slightly sour. Some is used as make up on demand to the lower
Desuperheater section and the remainder is taken off under level control and sent to
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effluent treatment. The condensed water loop is kept separate from the water in the
Desuperheater circulation loop to avoid contamination with salt products that may be
formed in the Desuperheater section.
The tail gas leaves the Desuperheater Contact Condenser (9102-C-11) at a temperature
of approximately 40°C and is sent to the Tail Gas Amine Absorber (9102-C-12) which
uses a lean amine solution to remove the hydrogen sulphide from the tail gas, while
minimising the co-absorption of carbon dioxide.
The gas enters at the bottom of the absorber and passes through a trayed section
counter current to the lean amine solution that preferentially absorbs H2S. The lean
amine solution is supplied from the Lean Amine Pumps 9103-P-13A/B.
The Tail Gas Rich Amine Pump (9102-P-16 A/B) pumps the rich solvent solution from
the bottom of the Tail Gas Amine Absorber (9102-C-12) to the Acid Gas Amine
Absorber (9103-C-11) before it is regenerated in the Amine regenerator (9103-C-12).
The amine regeneration facilities required for the Acid Gas Enrichment and Tail Gas
Treatment Units are shared with the use of a common solvent. The H2S that is stripped
from the rich amine solution in the Amine Regenerator is fed to the Sulphur Recovery
section, thus closing the recycle loop around the SRU and TGTU sections.
Treated gas from the Tail Gas Amine Absorber passes to the Incinerator along with
that from the Acid Gas Amine Absorber and from the Sulphur Pit.
4.3.3
Tail Gas Treatment Unit Control Description
4.3.3.1
Controls for RGG Combustion Air Blower (9102-K-11A/B)
4.3.3.1.1
Surge Protection
The basic objectives of the surge protection system are:
•
To prevent surge-induced compressor damage and process upsets without
sacrificing energy efficiency
•
To maintain selected process-limiting variables within safe or acceptable range
•
To achieve these objectives, the anti surge controller manipulates the position of
a blow-off valve and IGV (inlet pressure control)
4.3.3.1.2
Anti surge Protection
The regulation of the combustion air blower valves is implemented on the CCC Antisurge controller.
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CCC receives the following signals from the compressor skid (9102-K-11A/B) to perform
the pressure and anti-surge regulation:
Sl. #
9102-K-11A
Tag No.
9102-K-11B
Tag No.
Service
1.
91-PT-1452
91-PT-1712
Discharge air pressure
2.
91-TT-1454
91-TT-1714
Discharge air temperature
3.
91-FT-1452
91-FT-1712
Discharge air flow
4.
91-PT-1454
91-PT-1714
Compressor inlet air pressure
5.
91-TT-1455
91-TT-1715
Compressor inlet air temperature
6.
91-PT-1456
91-PT-1716
Discharge air pressure after check valve
7.
91-ZT-1453
91-ZT-1713
IGV valve position transmitter
8.
91-ZT-1451
91-ZT-1711
Blow-off valve position transmitter
9.
91-II-1470
91-II-1730
Main motor current signal
Note: 9102-K-11A controls are discussed in the following section.
After processing all the above signals, CCC controls the IGV 91-PCV-1453 and blow-off
valve 91-FCV-1451.
CCC also provides trip signal 91-XS-1464 for excessive surge to ESD to stop the
compressor.
When the blower is started IGV 91-PCV-1453 receives a minimum opening signal from
CCC which is a pre-set value on CCC and the blow-off valve 91-FCV-1451 remains open.
When the compressor is loaded, CCC modulates the IGV 91-PCV-1453 and blow-off
valve 91-FCV-1451 to maintain the discharge air pressure constant.
4.3.3.1.3
IGV 91-PCV-1453
The regulation system of compressor IGV valve 91-PCV-1453 is of the constant pressure
type.
After the loading of compressor the pressure regulation loop stabilizes and the IGV
91-PCV-1453 opens or closes only when the air required by the machine varies, so as to
maintain the discharge pressure of the blower within the set-point defined.
4.3.3.1.4
Blow-off Valve 91-FCV-1451
The anti-surge regulation loop provides to regulate the blow-off valve 91-FCV-1451 by
a continuous calculation of the discharge pressure 91-PT-1452 and discharge flow
91-FT-1452. When the flow is higher than the pressure the result of the calculation
closes the blow-off valve. When the pressure is higher than the flow the result of the
calculation opens the blow-off valve.
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TITLE: OPERATION AND MAINTENANCE MANUAL
4.3.3.2
Reducing Gas Generator Controls
4.3.3.2.1
Hydrogenation Reactor I/L Temperature Control
The Hydrogenation Reactor inlet temperature is controlled through 91-TIC-1307 by
adjusting the air and the fuel Gas flow rates to the Reducing Gas Generator.
The Hydrogenation Reactor inlet temperature is controlled by 91-TIC-1307, output of
the controller 91-TIC-1307 is directly fed to the combustion air flow controller 91-FIC1304 as a set point and output of the controller 91-FIC-1304 regulates the air flow
damper 91-FV-1304.
Fuel gas flow is controlled by 91-FIC-1311; set point for the fuel gas controller is
derived in the block 91-UY-1304 by multiplying the air flow with AIR/FG ratio set value
provided from 91-HIC-1304 (Range: 0.09 to 0.15).
Output of the controller 91-FIC-1311commands the fuel gas control valve 91-FV-1311.
If the Hydrogenation Reactor inlet temperature increases, then controller 91-TIC-1307
shall first decrease the Set point of combustion air flow controller 91-FIC-1304, which
in turn decrease the set point of fuel gas controller 91-FIC-1311 and vice versa.
4.3.3.2.2
Steam Flow Control
LP steam is injected directly in to the RGG burner in a ratio of steam to fuel gas to
suppress the formation of soot. Steam flow to RGG is measured by 91-FT-1310 which is
fed as a process variable to the steam flow controller 91-FIC-1310, set point for the
controller is calculated by multiplying the process variable from 91-FIC-1311(FG flow)
with the STEAM/FG ratio manually provided via 91-HIC-1311(2.0:1.0).
Output (0-100%) of the controller 91-FIC-1310 directly commands the control valve
91-FV-1310.
Alarm
Control Loop
Unit
Operating
Set Point
Low
High
91-TIC-1307
Hydrogenation reactor I/L
temperature
°C
290
285
295
91-FIC-1304
RGG comb air flow
Sm3/hr
2371.6
2134
2609
3
Sm /hr
263.7
237
290
kg/hr
400
360
440
Controller
91-FIC-1311
RGG fuel gas flow
91-FIC-1310
RGG quench steam flow
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Fig. 20 - Reducing Gas Generator Temperature Control
9102-V-11
SP
PV
X
Hydrogenation Reactor
FIC
1304 MV
Comp
FY
1304
FT
1304
TIC
1307
PT
1304
FV-1304
PV
Fuel Gas
Ratio HIC
Air
1304
MV
X
UY
1304
FIC
SP 1311
PV
FT
1311
Fuel Gas to
RGG
FV-1311
X
HIC
1311
SP
UY
1311
PV
SP
FIC
PV 1310
MV
FT
1310
Steam to
RGG
Tail Gas
TT
1304
Combustion
Air to RGG
Steam
Ratio
Fuel Gas
TT
1307
FV-1310
9102-F-11
Reducing
Gas
Generator
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4.3.3.3
Reactor Effluent Cooler Controls
4.3.3.3.1
Reactor Effluent Cooler Level Control
Hydrogenated process gases from the Hydrogenation Reactor are cooled in the Reactor
Effluent Cooler (9102-E-11) and generates LP steam in the shell side of the cooler.
The water level in the Reactor Effluent Cooler is maintained by level controller 91-LIC1302 by monitoring the level through 91-LT-1302, level control is achieved by
controlling the boiler feed water inlet to the Reactor Effluent Cooler through the
control valve 91-LV-1302.
Controller
Tag
Control Description
91-LIC-1302
Reactor Effluent Cooler
level Control
Alarm
Unit
Operating
Set Point
Low
High
%
85
81
92
•
Low low level alarm (91-LALL-1309) set at 76% in reactor effluent activates the
RGG (9102-F-11), TGTU and SRU shutdown
•
BFW inlet to reactor effluent control valve 91-LV-1302 opens on instrument air
failure.
4.3.3.3.2
Reactor Effluent Cooler Outlet Tail Gas Control
In normal operation tail gas from the Reactor Effluent Cooler will be routed to Contact
Condenser but during start-up tail gas is diverted to the Incinerator.
This diversion of tail gas is accomplished by activating the selector switch 91-HS1303A. This opens the valve 91-XV-1332 (tail gas going to the Contact Condenser) and
when it is fully open the valve 91-XV-1331 will close (tail gas going to the incinerator).
This ensures that at least one path is fully open for the tail gas to pass through without
pressuring the upstream reducing gas generator RGG.
4.3.3.4
4.3.3.4.1
Desuperheater/Contact Condenser Controls
Desuperheater/Contact Condenser Column Bottom Level Control
The Desuperheater Circulation Pump (9102-P-11A/B) takes suction from the
Desuperheater/Contact Condenser (9102-C-11) bottom and circulates water to the
column through Wash Water Filter (9102-S-15). The Desuperheater/Contact Condenser
column bottom level is maintained by the level controller 91-LIC-1307, regulating the
level control valve 91-LV-1307, which controls slip stream of water flow from the
Cooling Water Circulation Pumps (9101-P-12A/B) to the bottom section of the column
as top up water.
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Controller
Tag
91-LIC-1307
Control Description
Desuperheater/Contact
Condenser column bottom
level
Alarm
Unit
Operating
Set Point
Low
High
%
50
22
93
•
Low low level alarm (91-LALL-1306) in Desuperheater/Contact Condenser column
bottom trips the Desuperheater Circulation Pumps 9102-P-11A/B
•
Desuperheater/Contact Condenser column bottom level control valve 91-LV-1307
opens on instrument air failure.
4.3.3.4.2
Circulating Water Return Flow to Desuperheater Control
The Desuperheater Circulation Pump (9102-P-11A/B) takes suction from the column
(9102-C-11) bottom and circulates water to the column through Wash Water Filter
(9102-S-15). Flow from the Wash Water Filter to the column bottom is maintained by
the flow controller 91-FIC-1314 which regulates the flow control valve 91-FV-1314.
Controller
Tag
91-FIC-1314
Alarm
Control Description
Unit
Operating
Set Point
Low
High
Circulating water return to
Desuperheater
m3/hr
199
179
219
•
Low low flow alarm (91-FALL-1306) set at 30 m3/hr in circulating water return to
de super heater trips the de super heater circulation pumps 9102-P-11A/B
•
Circulating water return to de super heater flow control valve 91-FV-1314 opens
on instrument air failure.
4.3.3.4.3
Desuperheater/Contact Condenser Top Level Control
The cooling water circulation in the Contact Condenser top section is carried out by
Cooling Water Circulation Pump (9101-P-12A/B). The Contact Condenser (9102-C-11)
top level is maintained by the level controller 91-LIC-1305 through the level control
valve 91-LV-1305, which controls the excess water flow from the Cooling Water
Circulation Pumps discharge to the Waste Water Degasser (6922-V-07).
Controller
Tag
Control Description
91-LIC-1305
Desuperheater/Contact
Condenser top level
Alarm
Unit
Operating
Set Point
Low
High
%
50
32
90
•
Low low level alarm (91-LALL-1304) in Desuperheater/Contact Condenser column
top trips the Cooling Water Circulation Pump 9102-P-12 A/B
•
Desuperheater/Contact Condenser column top level control valve 91-LV-1305
closes on instrument air failure
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4.3.3.4.4
Desuperheater/Contact Condenser Top Circulating Water Flow Control
Cooled circulating water return from the Contact Condenser Trim Cooler (9102-E13A/B) flows to top of the de-super heater/contact condenser column (9102-C-11) is
measured by 91-FT-1307 and controlled by the flow controller 91-FIC-1307 which
regulates the flow control valve 91-FV-1307.
Controller
Tag
Control Description
91-FIC-1307
Desuperheater/ Contact
Condenser top CW
•
4.3.3.4.5
Alarm
Unit
Operating
Set Point
Low
High
m3/hr
197
177.3
216.7
Desuperheater/Contact Condenser column top cooling water control valve 91-FV1307 opens on instrument air failure
Desuperheater/Contact Condenser Top Pressure Control
In normal operation Desuperheater/Contact Condenser column (9102-C-11) tail gas
flows to the Tail Gas Amine Absorber 9102-C-12 but during start-up, flow will be
diverted to the Incinerator and the tail gas pressure is maintained by the pressure
controller 91-PIC-1308 by monitoring the pressure transmitter 91-PT-1308 located in
the start-up bypass line to Incinerator. If the pressure increases then the control valve
91-PV-1308 opening will increase to pass more gas to the Incinerator (9101-F-14).
Alarm
Controller
Tag
Control Description
Unit
Operating
Set Point
Low
High
91-PIC-1308
Desuperheater/ Contact
Condenser column top
pressure
bara
1.19
NA
NA
•
4.3.3.4.6
Desuperheater/Contact Condenser column top pressure control valve 91-PV-1308
to incinerator opens on instrument air failure
Contact Condenser Cooler Temperature Control
Temperature of the circulating water from the Cooling Water Circulation Pumps
(9102-P-12-A/B) is controlled by cooling the fluid to 54°C (maximum temperature) in
summer and not less than 40°C (minimum temperature) in winter using three fans: one
fixed speed fan (on/off) control (column 1), and another two VSD controlled fans
working simultaneously (in column 2 & 3).
The contact condenser cooler outlet temperature is measured at outlet of Contact
Condenser Trim Cooler by 91-TT-1301 and received by the temperature controller
91-TIC-1301. The output of this controller sends the control signal to control the three
fans and also to control the bypass control valve 91-TV-1301 of Contact Condenser
Trim Cooler.
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In auto mode, the temperature controller shall follow up the cooler outlet
temperature changes by changing the VSD (9102-EM-12AB/AC/BB/BC) rates to
maintain the temperature set point-1 = (54°C + 40°C)/2=47°C.
The fixed speed fan (9102-EM-12AA/BA) will operate on gap control set point between
the values Tmax=54°C & Tmin=42°C.
The temperature control valve will be used only in case the cooler outlet temperature
goes to pre-determined temperature T=42°C, then the control valve shall open
gradually to maintain the cooler temperature and keep it around the set point-2
(42°C).
4.3.3.5
Tail Gas Amine Absorber Controls
4.3.3.5.1
Tail Gas Absorber Level Control
The tail gas from the Desuperheater/Contact Condenser (9102-C-11) enters at the
bottom of Tail Gas Amine Absorber 9102-C-12. Bottom level in the Tail Gas Amine
Absorber (9102-C-12) is maintained by controlling the rich amine flow from the bottom
of the column to Acid Gas Amine Absorber (9103-C-11) through 9103-P-16A/B.
Tail gas absorber bottom level is controlled by 91-LIC-1308; Tail Gas Rich Amine Pumps
9102-P-16A/B discharge flow to Acid Gas Amine Absorber is measured by 91-FT-1325
and controlled by the flow controller 91-FIC-1325; set point for the SLAVE flow
controller 91-FIC-1325 is received from the tail gas absorber MASTER level controller
91-LIC-1308.
Output of the flow controller 91-FIC-1325 directly controls the control valve
91-FV-1325 in the Tail Gas Rich Amine Pumps 9102-P-16A/B discharge flow to the acid
gas amine absorber.
Controller
Tag
Control Description
91-LIC-1308
Tail Gas Amine Absorber
bottom level
91-FIC-1325
Rich amine flow to 9103-C11
Alarm
Unit
Operating
Set Point
Low
High
%
50
11
82
m3/hr
136
NA
NA
•
High high level alarm (91-LAHH-1310) in Tail Gas Amine Absorber bottom closes
the lean amine inlet valve 91-XV-1310 to Tail Gas Amine Absorber
•
Low low level alarm (91-LALL-1301) in Tail Gas Amine Absorber bottom trips the
Tail Gas Rich Amine Pumps (9102-P-16A/B) and closes tail gas rich amine valve
91-XV-1309.
•
Rich amine flow control valve 91-FV-1325 to Acid Gas Amine Absorber closes on
instrument air failure.
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4.3.3.5.2
Lean Amine to Tail Gas Amine Absorber Flow Control
Lean amine solution from Lean Amine Pumps (9103-P-13A/B) and tail gas from
Desuperheater/Contact Condenser (9102-C-11) enters the Tail Gas Amine Absorber
(9102-C-12).
Lean amine flow to the absorber is measured by 91-FT-1301 and controlled by
91-FIC-1301. Output of the flow controller directly regulates the lean amine flow
control valve 91-FV-1301.
Controller
Tag
91-FIC-1301
Alarm
Control Description
Unit
Operating
Set Point
Low
High
Lean amine flow to Tail Gas
Amine Absorber
m3/hr
135
110
148.5
•
High high level alarm (91-LAHH-1310) in Tail Gas Amine Absorber bottom closes
the lean amine inlet valve 91-XV-1310 to Tail Gas Amine Absorber located on the
downstream of 91-FV-1301.
•
Lean amine inlet valve 91-XV-1310 closes on activation of ESD-0, ESD-1 and ESD-2
shutdown.
4.3.3.5.3
Tail Gas Rich Amine Pumps Minimum Flow Control
Tail Gas Rich Amine Pumps (9102-P-16A/B) minimum flow to Tail Gas Amine Absorber
bottom is controlled by 91-FIC-1303.
Output of the controller 91-FIC-1303 controls the fail open control valve 91-FV-1303.
Controller
Tag
91-FIC-1303
•
4.4
4.4.1
Control Description
Tail Gas Rich Amine Pump
min flow
Alarm
Unit
Operating
Set Point
Low
High
m3/hr
31.25
27.5
NA
Tail Gas Rich Amine Pump discharge flow Low low alarm (91-FALL-1305) set at
25 m3/hr trips the Tail Gas Rich Amine pumps (9102-P-16A/B).
INCINERATOR
Equipment Specification
Incinerator Air Blowers
Equipment Tag No.
Process Medium
Rated Capacity, ACMH
9101-K-12A/B
Air
63,402
Design Temperature, (Min./Max.), °C
0/52
Drive Type
Motor
Driver Power, kW
Material of Construction, Impeller
94
Corten Steel
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Incinerator
Equipment Tag No.
9101-F-14
Size, (OD/L), m
3.886/17.374
Process Medium
Tail Gas/Air/Fuel Gas
Design Temperature, shell, °C
343
Design Pressure, barg
3.8
Burner
Model
Size
Quantity
Duty
GSLF-24J
82”
1
32.2 MW-H
Turndown
5:1
Pilot Type
AR/GS-1
Design Temperature, shell, °C
343
Design Pressure, barg
3.8
Incinerator Stack
Equipment Tag No.
Process Medium
9101-X-11
Flue Gas
Shell OD/Height, m
2.438/110
Design Temperature, (Shell/Refractory), °C
343/1538
Design Pressure, barg
Internal Lining
4.4.2
Process Description and Control
4.4.2.1
Tail Gas Incinerator Process Description
ATM.
YES, L.W. Castable
An Incinerator 9101-F-14 is provided to thermally oxidise all possible sulphur
compounds to SO2 in off gas effluents from the Acid Gas Amine Absorber 9103-C-11,
Tail Gas Amine Absorber 9102-C-12, SRU tail gases and vent gases from the Sulphur
Degassing Pit 9101-T-01/01B. Moreover all BTEX content of off gas effluent is also
destructed.
To ensure complete combustion of these sulphur compounds the Incinerator's
combustion chamber temperature is maintained at a temperature of about 800°C by
burning fuel gas supplied with combustion air in the unit's burner.
Combustion air is supplied from 2 x 100% Incinerator Air Blowers (9101-K-12 A/B, One
Operating and One Standby). The Blowers are driven by VFD motors. Each Blower is
provided with an Air Intake Stack with Bird Screen, Sand Filter and Rain Hood.
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Fuel gas to the Incinerator is supplied from the existing Fuel Gas network. A tapping is
taken from the existing fuel gas line 6”-6536-FG-101-C12P and fuel gas is supplied to
the Incinerator 9101-F-14 and Reducing Gas Generator 9102-F-11.
The flows of fuel gas and combustion air are each measured by flow and then ratio
controlled to ensure the correct amount of excess air is always maintained in the
Incinerator combustion chamber to allow the oxidation of the sulphur compounds in
the tail and vent gases to take place.
An Oxygen Analyser 91-AE-1051 located in the Incinerator outlet combustion gases
Stack 9101-X-11 monitors the excess O2 in the Incinerator combustion gases.
Adjustments may be made to the fuel gas to air ratio controller to ensure the correct
excess of O2 (3% by Mol) is seen in the stack gases.
A sulphur dioxide analyser AE-1052, located at the Incinerator Stack (9101-X-11),
monitors the Incinerator stack gases for SO2 content. A NOX analyser 91-AE-1053,
located at the Incinerator Stack (9101-X-11), monitors the Incinerator stack gases for
NOX content.
4.4.2.2
4.4.2.2.1
Tail Gas Incinerator Process Control
Incinerator Temperature control (91-TIC-1155)
Normal operating temperature of the Incinerator is 817⁰C; the temperature in the
Incinerator is controlled by modulating the flow of fuel gas and combustion air.
Temperature in the Incinerator is measured by 91-TT-1155 and controlled by 91-TIC1155. The output of the controller 91-TIC-1155 is fed to a splitter 91-TY-1155A where
the output is splitted into 0-50% which is fed to 91-TY-1155C for regulating the
combustion air flow and 50-100% which is fed to 91-TY-1155B for regulating the fuel
gas flow.
0-50% output of 91-TIC-1155 is scaled to 0-100% and is reversed in 91-TY-1155C (This is
for regulating the temperature of Incinerator during normal operation by varying the
speed of the air blower). This value is then fed to a high selector function block 91-FY1156C. The other input of 91-FY-1156C is received from 91-FY-1155A (This determines
the quantity of combustion air required based on fuel gas flow).
The combustion air flow rate from Air Blowers is measured in the common discharge
line by 91-FT-1156.
91-FIC-1156 receives the PV from 91-FT-1156 and set point (SP) from 91-FY-1156C. The
output (MV) of 91-FIC-1156 is then scaled to 4-20 mA. The scaled current signal is sent
to VSD panel of Duty Air Blower for controlling its speed. The speed of the Air Blower
determines the quantity of combustion air required.
The main fuel gas flowing to the burner is measured by 91-FT-1155 and the PV is sent
to 91-FIC-1155.
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The set point for 91-FIC-1155 is derived from the temperature controller 91-TIC-1155.
i.e. The output (MV) of 50-100% is scaled to 0-100% and is fed as SP through 91-TY1155B to 91-FIC-1155.
The ratio set point is manually entered by operator via 91-HIC-1155A. The fuel gas
flow value (PV) of 91-FIC-1155 is multiplied by ratio set point in function block 91-FY1155A. The ratio set point gives the correct ratio of air to fuel gas based on a manually
determined composition. The multiplication factor is a manual entry and is based on
the design composition of the feed gas. The output value of 91-FY-1155A is given to
the selector function block 91-FY-1156C.
The actual ratio of combustion air to fuel gas is displayed in function block 91-FY-1155A.
Fuel gas flow control is achieved via 91-FIC-1155 by controlling 91-FV-1155
This reversed output and air/fuel ratio provided via 91-HIC-1155A is allowed to pass
through the high demand selector 91-FY-1156C which provides the set point to
combustion air flow controller 91-FIC-1156. Output of the controller modulates the
combustion air flow by changing the Combustion air fan 9101-K-12A/B VFD set point.
50-100% output of 91-TIC-1155 is scaled to 0-100% in 91-TY-1155B, which provides the
set point to the fuel gas controller 91-FIC-1155 and output of the controller 91-FIC1155 commands the fuel gas control valve 91-FV-1155.
Controller
Tag
Control Description
Unit
91-TIC-1155
91-FIC-1155
Operating
Set Point
Alarm
Low
NA
NA
High
850
NA
Incinerator stack temp
°C
800
3
Incinerator Fuel gas flow
Sm /hr
2256.9
Incinerator combustion air
91-FIC-1156
Sm3/hr
46938.7
NA
NA
flow
• High high temperature alarm (91-TAHH-1160) set at 900°C, low low combustion air
flow alarm (91-FALL-1156B/C) set at 8383 Sm3/hr, low low fuel gas pressure alarm
(91-PALL-1156) set at 0 barg and high high fuel gas pressure alarm (91-PAHH-1156)
set at 4 barg at Incinerator
•
Closes the following valves:
•
Fuel gas block valve 91-XV-1555 to burner
•
Fuel gas block valve 91-XV-1557 to burner
•
Pilot gas block valve 91-XV-1558 to burner
•
Pilot gas block valve 91-XV-1560 to burner
•
Instrument air block valve 91-XV-1161
•
Pilot air block valve 91-XV-1162
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•
•
Opens the following valves:
•
Fuel gas vent valve 91-XV-1158
•
Pilot gas vent valve 91-XV-1159
Fuel gas supply control valve 91-FV-1155 to Incinerator furnace closes on
instrument air failure.
The schematic diagram for Incinerator temperature control is shown below:
Fig. 21 - Incinerator Temperature Control
Master
TE
1155
TT
1155
TIC
1155
Incinerator
9101-F-14
X
TY
1155B
Slave
MV
SP
50-100%
TY
1155A
Split
X
0-50%
FY
PV 1155A
FIC
1155
PV
X
Burner
TY
1155C
FT
1155
HIC Fuel Ratio
1155A Air
Combustion
Air
Fuel Gas to
Incinerator
FV
1155
Slave
FT
1156A
Combustion Air Fan
PV
FIC
1156
MV
VFD
FY-1156A
9101-K-12A
Combustion Air Fan
VFD
9101-K-12B
FY-1156B
>
SP
FY
1156C
High Selector
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4.5
INSTRUMENT AIR PACKAGE
4.5.1
Instrument Air Compressor Package
4.5.1.1
Equipment Specification
Screw Compressors
Tag No.
6837-K-02A/B
Rotary, Dry Screw, 2 stage,
Air-cooled
Type
No. of units
Two (1 Working + 1 Standby)
3
Capacity, Nm /hr (Total) @52°C & 100% RH
900
Design Pressure, barg
8.6
Design Temperature, °C
52/0
Compressor Inlet Pressure, barg
ATM
Compressor Inlet Temperature, °C
AMB (0-52)
Compressor Outlet Pressure, barg
8
Driver
Driver Power, kW
Motor
200
Pre-cooler
Tag No.
6837-E-03A
Design Pressure, barg
11
Design Temperature, °C
260
Inter-cooler
Tag No.
6837-E-03A
Design Pressure, barg
3.7
Design Temperature, °C
180
After-cooler
Tag No.
6837-E-03A
Design Pressure, barg
13.7
Design Temperature, °C
200
After-cooler
Tag No.
6837-E-04A
Design Pressure, barg
10.5
Design Temperature, °C
160
Max. Capacity, L/S
650
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Discharge Air Receiver
Tag No.
6837-V-10
Size, mm, (Dia x T/T)
2400 x 7200
Design Pressure, barg
9.7
Design Temperature, °C
85
Operating Pressure, barg
7
Operating Temperature, °C
60
Material of Construction
CS
4.5.2
Instrument Air Dryer Package
4.5.2.1
Equipment Specification
Air Dryer
Tag No.
Dryer Type
6837-A-03/04
Twin Tower, pressure swing
absorption with heatless
regeneration
Capacity, Nm3/hr
300
Design Pressure, barg
9.7
Design Temperature, °C
85/0
Operating Pressure, barg
8
Operating Temperature, °C
60
Desiccant Type
Activated Alumina/Molecular
Sieve
Pre-Filter
Tag No.
Size (Dia x L), mm
6837-S-07A/B & 6837-S-09A/B
190 x 621
Design Pressure, barg
9.7
Design Temperature, °C
85
Material of Construction
Cast Aluminium
Dryer Vessels
Tag No.
6837-V-14A/B & 6837-V-15A/B
Size (Dia x T/T), mm
550 x 1500
Design Pressure, barg
9.7
Design Temperature, °C
85
Material of Construction
CS
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After-Filters
Tag No.
6837-S-08A/B & 6837-S-10A/B
Size (Dia x L), mm
190 x 621
Design Pressure, barg
9.7
Design Temperature, °C
85
Material of Construction
Cast Aluminium
Instrument Air Receiver
Tag No.
4.5.3
6837-V-11
Size mm, (Dia x T/T)
3700 x 7400
Design Pressure, barg
9.7
Design Temperature, °C
85/0
Operating Pressure, barg
7.1
Operating Temperature, °C
60
Material of Construction
CS
Instrument Air Package Description
The new air compressor package consists of the following:
1. Two (2x100%) single base frames mounted Air Compressors (6837-K-02A/B), each
having a capacity of 900 Nm3/hr (dry basis).
2. Each Compressor is supplied with an individual After Cooler.
3. One air compressor discharge drum, (6837-V-10) is provided.
4. Two Instrument air dryer packages, (6837-A-03/04) running at 2X50%, each dryer
capacity is 300 Nm3/hr (dry basis).
5. Pre and After Filters for each dryer.
6. One instrument air receiver (6837-V-11) with storage capacity to provide
instrument air for a period of 20 minutes following a compressor trip.
7. Dew point analyzers are provided for individual dryer package.
The compressors are air-cooled, oil free, rotary screw type and are sized 100% of duty.
Both Compressors operate in Duty/Standby configuration (with automatic changeover
of the standby unit compressor).
The dryer consists of two 50% heater-less desiccant dryers each consisting of two
vessels (one drying, one regenerating), a set of duplex pre and after filters. Each dryer
is 50% of design capacity (Single Compressor supply).
Compressors and Dryers have locally mounted instruments and junction boxes and
operate from the UCP, with DCS and ESD remote monitoring, through TCP/IP.
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Based on air demand only one compressor under normal conditions will be loaded, the
second unit can start but will have load inhibitors to ensure only one unit is loaded.
Each dryer has a sonic nozzle at the discharge header to ensure the protection against
the greater flow.
Each compressor is monitored and controlled by the Package Controller (UCP) which
provides information to the ICSS. There is only a push button station available at each
equipment station in the field (LCP). However this LCP still only communicates with
the UCP which then sends signals to the DCS. All the signals are hardwired to UCP. The
subsystems MCC, ESD and ICSS are hardwired to the UCP and linked also through a
redundant modbus TCP/IP communication link.
Compressor instrumentation and solenoids are all wired to junction boxes, the UCP
system receives an external net air pressure signal and then starts, loads/unloads and
stops the available compressor based on its own selecton routine. The ICSS supervises
the system status via the UCP connected to the junction boxes shown in the Electrical
Service Diagram.
The new Air System will supply instrument and plant air with the following supply
battery limit conditions for both instrument and plant air:
Design
Operating
Pressure bar (g)
9.7
7.0
Temperature (°C)
85
55/60
The new instrument and plant air headers are connected to the existing NGL-3
instrument and plant air headers respectively through cross over connection lines with
(manual isolation valves) for operation flexibility.
4.5.4
Instrument Air Package Control Description
A. Loading/Unloading
The compressor always starts to run in unloaded condition, up to first 20 seconds
known as the load delay, this is to ensure the oil pressure is stabilised. After the load
delay compressor will load unless either the operator manually selects to unload or
there is no air demand. If there is no air demand the compressor runs unloaded and is
said to be idle.
To load the compressor the solenoid valve 68-XY-1401 shall be energized, similarly to
unload the compressor solenoid valve 68-XY-1401 shall be de-energised and solenoid
valve 68-XY-1403 shall be energised.
When the compressor is in remote mode, loading/unloading of every compressor is
based on the net air pressure signal 68-PT-1311.
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When the compressor is in local mode loading/unloading of every compressor is based
on the compressor O/L pressure signal transmitter 68-PT-1406.
If the air demand is low, i.e. when the pressure transmitter signal is above the load
set point then UCP unloads the compressor and if the air demand is high, i.e. when the
pressure transmitter signal is below the load set point then UCP loads the compressor.
The loading/unloading set pressure in barg is given below:
Compressor
Control
Loading
Unloading
Status
Compressor A
lead
XX
XX
running
Compressor B
lag
XX
XX
standby
Note: XX – Loading and Unloading set points will be set at site while commissioning the
Air Compressor.
B. Lead/Lag Control in Remote Mode
Only in Remote-Auto mode the compressors shall follow the Lead, Lag logic. The
purpose of Lead/Lag control is to allow two compressors to operate at once, with one
operating as LEAD and maintaining system pressure, and the other operating as LAG
and loading only as necessary when system pressure drops.
When air demand is lower or equal to the air generation from one compressor, only
the Lead compressor gets loaded. When the air demand increases above the capacity
of one compressor, the lag Compressors gets loaded in sequence as per demand
requirements.
C. Compressor Auto changeover
Compressor auto change over occurs on the 2 following conditions:
1. If the stand-by compressor was selected in remote mode then after 24 hours of
duty compressor usage stand-by compressor will start automatically.
2. Duty compressor failure will start the standby compressor immediately.
If the failed compressor was loaded and the air demand is still required, the unit will
go in to loaded mode straight away after the starting delay (20 seconds).
D. Dry Air Purge
When the compressor is in “standby mode”, solenoid 68-XY-1407 is activated and this
opens the purge air line allowing a small flow of dry air protecting the compressor
during stand-by, also immediately when the status stand-by is changed to duty,
solenoid 68-XY-1407 is de-energised.
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E. Water Separators Level Control
Inter cooler and after cooler water Separators level is maintained by level indicators
(68-XI-1402 and 68-XI-1406) via opening or closing of valves 68-XY-1402 and 68-XY-1406
respectively.
F. Instrument Air Header Pressure Control
The pressure on the discharge line from the instrument air receiver is monitored by a
transmitter 68-PT-1310; pressure on the discharge line of the plant air header is
controlled by 68-PIC-1310.
Decrease in the instrument pressure signal will tends to close the control valve
68-PCV-1310 in the plant air line.
Controller
Tag
68-PIC-1310
4.6
4.6.1
Inst air header
pressure control
Alarm
Unit
Operating
Set Point
Low
High
bar(g)
6
5.5
NA
Control Description
•
Instrument Air pressure 68-PI-1312A/B/C/low low alarm set at 5 barg activates
ESD Level-2 shutdown.
•
Instrument air pressure control valve 68-PCV-1310 closes on instrument air failure.
EFFLUENT & WASTE WATER TREATMENT
Equipment Specification
Waste Water Degasser
Equipment Tag No.
Process Medium
Size (ID/T/T), mm
6922-V-07
Waste/Sour Water
1500/4500
Design Temperature, °C
165/0
Design Pressure, barg
3.5/FV
Operating Temperature, °C
73
Operating Pressure, barg
1
Material of Construction
CS
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Waste Water Degasser Pumps
Equipment Tag No.
6922-P-08A/B
Pump Type
Horizontal, Centrifugal
Process Medium
Waste/Sour Water
3
Capacity, Normal/Rated, m /hr
Shut off Pressure, bar(g)
Suction Pressure, bar(a), Normal/Rated
Discharge Pressure, bar(a)
Design Temperature, °C
Operating Temperature, °C
Driver Type
Rated Power, kW
Material of Construction, Casing/Internals
8.62/9.48
14.6
0.99/4.66
8.8
95/0
73
Motor
15
Duplex SS/Duplex SS
Sour Water Filter
Equipment Tag No.
6922-S-06
Process Medium
Sour Water
Size (ID/T/T), mm
1500/4500
Design Throughput, m3/hr
9.48
Design Temperature, °C
95/0
Design Pressure, barg
14.6
Operating Temperature, °C
73
Operating Pressure, barg
7
Material of Construction
CS
Sour/Stripped Water Exchanger
Equipment Tag No.
Process Medium
Design Pressure Shell Side (Stripped Water), barg
Design Pressure Tube Side (Sour Water), barg
Design Temperature Shell Side (Stripped Water), °C
Design Temperature Tube Side (Sour Water), °C
Operating Pressure Shell Side (Stripped Water), bar(a)
Operating Pressure Tube Side (Sour Water), bar(a)
Operating Temperature, Shell Side (Stripped Water),
(In/Out) °C
Operating Temperature, Tube Side (Sour Water),
(In/Out) °C
Design Duty, kW
Material of Construction, Shell/Tube
6922-E-01
Sour/Stripped Water
11.3
14.6
160/0
160/0
6.80
7.4
126/104
73/96
276
CS/SS
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Sour Water Stripper
Equipment Tag No.
6922-C-01
Design Pressure, barg (Max./Min.)
3.5/FV
Design Temperature, °C (Max./Min.)
165/0
Process Medium
Sour Water
Max. Liquid Level, Top Section, mm
700
Max. Liquid Level, Bottom Section, mm
1200
Tray Nos.
38
Tower Diameter, mm
1000
Tower Height, mm
25000
Operating Pressure, bar(a)
1.20
Operating Temperature, °C, Top/Bottom
Material of Construction, Top section
Material of Construction, Bottom section
Material of Construction, Internals
82.2/126.1
CS+SS316L CLAD
CS
SS316L
Stripped Water Pumps
Equipment Tag No.
6922-P-10A/B
Pump Type
Horizontal, Centrifugal
Process Medium
Stripped Water
3
Capacity, Normal/Rated, m /hr
Shut off Pressure, bar(g)
Suction Pressure, bar(a), Rated/Design
Discharge Pressure, bar(a)
Design Temperature, °C
Operating Temperature, °C
Driver Type
Rated Power, kW
Material of Construction, Casing/Internals
9.31/13.03
11.2
2.81/5.11
8.6
160/0
126
Motor
11
Duplex SS/Duplex SS
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Stripper Overhead Circulation Pumps
Equipment Tag No.
6922-P-11A/B
Pump Type
Horizontal, Centrifugal
Process Medium
Water
3
Capacity, Normal/Rated, m /hr
Suction Pressure, bar(a), Rated/Max.
Discharge Pressure, bar(a)
Design Temperature, °C
Operating Temperature, °C
Driver Type
13.23/19.85
3.9/7
8.0
150/0
121
Motor
Rated Power, kW
7.5
Material of Construction, Casing/Internals
Duplex SS/Duplex SS
Sour Water Stripper Reboiler
Equipment Tag No.
6922-E-04
Process Medium
Sour Water
Design Pressure, Shell Side barg
7.0/FV
Design Pressure, Tube Side barg
7.0/FV
Design Temperature, Shell side °C
165/0
Design Temperature, Tube side °C
185/0
Operating Pressure, Shell, Side barg
1.40
Operating Pressure, Tube Side barg
3.5
Operating Temperature, Shell side °C
126.1
Operating Temperature, Tube side °C
147.7
Design Duty, kW
1803 kW
Material of Construction, Shell side
CS
Material of Construction, Tube side
SS316L
Re boiler Condensate Drum
Equipment Tag No.
6922-V-09
Process Medium
Steam Condensate
Size (ID/T/T), mm
800/2400
3
Design Throughput, m /hr
9.48
Design Temperature, °C
185/0
Design Pressure, barg
7/FV
Operating Temperature, °C
155
Operating Pressure, barg
4.5
Material of Construction
CS
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Stripper Overhead Cooler
Equipment Tag No.
Type
Process Medium
6922-E-03
Forced Draft
Stripper Overhead Vapours
Design Pressure, barg
11.1
Design Temperature, °C
150/0
Operating Pressure, barg
2.7
Operating Temperature, °C
121/55
Design Duty, kW
998
Material of Construction
CS
Number of Fans
2
Driver Type
Motor
Rated Power, kW
15
Stripped Water Cooler
Equipment Tag No.
Type
Process Medium
6922-E-02
Forced Draft
Stripped Water
Design Pressure, barg
Design Temperature, °C
130/0
Operating Pressure, bar(g)
5.7
Operating Temperature, °C
104/52
Design Duty, kW
630
Material of Construction
CS
Number of Fans
2
Driver Type
Rated Power, kW
4.6.2
11.2
Motor
11
Effluent and Waste Water Treatment Process Description
Sour water from various sources is collected in the Waste Water Degasser 6922-V-07,
which provides over 20 minutes of hold-up for the waste water. The flow of waste
water from TGTU Cooling Water Circulation Pumps 9102-P-12A/B is continuous at a
rate of 8.7 m3/hr. The pressurised drain from Cooling Water Circulation Pumps 9102-P12A/B and the flow from Regenerator Reflux Drum Pumps 9103-P-11A/B are
intermittent. The sour water from the Waste Water Degasser 6922-V-07 is continuously
pumped under flow control by Waste Water Degasser Pumps (6922-P-08A/B) to the
Sour Water Stripper 6922-C-01 for treatment.
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In the event the Sour Water Treatment System is unavailable due to a process upset,
provision exists for manually routing the Waste Water Degasser liquids directly to the
Observation Sump (6922-X-04).
A balance line between Waste Water Degasser 6922-V-07 and Sour Water Stripper
6922-C-01 means that the pressure in the Waste Water Degasser 6922-V-07 floats on
the Sour Water Stripper 6922-C-01 operating pressure (i.e. 1.0 barg). A nitrogen supply
line is provided to maintain pressure in the Waste Water Degasser 6922-V-07 if it falls
below a certain minimum as liquids are pumped out.
The sour water from Waste Water Degasser 6922-V-07 is filtered in Sour Water Filter
(6922-S-06) to remove particle size of 10 micron e.g. sand, pipe scale and salts and
then preheated in Sour/Stripped Water Exchanger (6922-E-01) before feeding to Sour
Water Stripper. The Sour Water Stripper operates at 1.0 barg and has an upper section
and a lower tray section. The upper section is provided with temperature indication
locally as well as in DCS. A differential pressure transmitter is also provided across
trays 33 to 38 with indication in DCS. The middle section of the column is also
provided with a temperature indication locally as well as in DCS. A differential
pressure transmitter is also provided across trays 1 to 32 with indication in DCS. The
bottom section of the column is provided with temperature and level indications
locally as well as in DCS.
The sour water is stripped by the vapours generated from the Sour Water Stripper
Reboiler 6922-E-04. The Reboiler utilises LP steam to heat the sour water that comes
from the bottom of the Sour Water Stripper to 126⁰C. The condensed steam from the
Reboiler is sent to the LP Condensate system through level control.
Reflux for the column is provided by a pump-around system. Water is taken from
below tray 33 pumped by Stripper Overheads Circulation Pumps (6922-P-11A/B) under
flow control, cooled in Stripper Overheads Cooler (6922-E-03) and then returned to the
top tray.
The stripper overhead acid gases are routed to the TGTU (upstream of
Desuperheater/Contact Condenser, 9102-C-11). In the event of high column pressure,
excess gases are diverted to LP Acid Gas Flare.
The stripped water from the stripper is pumped under level control cascaded to a flow
controller via Stripper Water Pump (6922-P-10A/B) to the Sour/Stripped Water
Exchanger (6922-E-01) to preheat the feed to the stripper. The water is then routed to
the Stripped Water Cooler (6922-E-02) where it is cooled to 55°C before discharge to
the Observation Sump.
An analyser is provided in the line to the Observation Sump to monitor the sulphide
content of the stripped water stream.
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4.6.3
Effluent & Waste Water Treatment Control Description
4.6.3.1
Waste Water Degasser Pressure Control
Waste Water Degasser (6922-V-07) pressure is maintained by the pressure controller
69-PIC-1307 by monitoring the pressure through 69-PT-1307 located at the top of the
vessel. The pressure is maintained by regulating the pressure control valve 69-PV-1307
in the nitrogen line to the Waste Water Degasser.
69-PIC-1307 opens the nitrogen control valve 69-PV-1307 on falling pressure in the
Waste Water Degasser.
Controller
Tag
69-PIC-1307
Control Description
Waste Water Degasser top
pressure
Alarm
Unit
Operating
Set Point
Low
High
barg
1
0.8
1.2
•
High high pressure alarm (69-PAHH-1311) set at 1.3 barg in Waste Water Degasser
closes the nitrogen inlet valve 69-XV-1315
•
High high level alarm (69-LAHH-1311) set at 77% in Degasser closes the nitrogen
inlet valve 69-XV-1315
•
Waste Water Degasser 6922-V-07 nitrogen pressure control valve 69-PV-1307 closes
on instrument air failure.
4.6.3.2
Waste Water Degasser Level Control
Waste Water Degasser (6922-V-07) level is monitored by 69-LT-1301 and controlled by
69-LIC-1301. Level in the Degasser is controlled by controlling the sour water outlet
from Sour/Stripped Water Exchanger (6922-E-01). Master controller 69-LIC-1301 acts in
cascade and provides the set point to sour water flow Slave controller 69-FIC-1314
which regulates the control valve 69-FV-1314 in the outlet of Sour/Stripped Water
Exchanger 6922-E-01.
Controller
Tag
Alarm
Control Description
Unit
Operating
Set Point
Low
High
69-LIC-1301
Waste Water Degasser level
%
50
33
53
69-FIC-1314
Sour water to Stripper
column
m3/hr
8.2
7.4
9
•
High high level alarm (69-LAHH-1311) set at 77% in Degasser closes the nitrogen
inlet valve 69-XV-1315 and waste water valve 69-XV-1312 from the Cooling Water
Circulation Pumps 9102-P-12A/B
•
Low low level alarm (69-LALL-1311) set at 20% in Degasser 6922-V-07 trips the
Waste Water Degasser Pumps 6922-P-08A/B
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•
4.6.3.3
Sour water to Stripper column control valve 69-FV-1314 closes on instrument air
failure.
Sour Water Stripper Pressure Control
A split range pressure controller 69-PIC-1315 is provided to maintain the top pressure
of Sour Water Stripper (6922-C-01) by throttling the sour gas to TGTU control valve
69-PV-1315A (0-50%) and sour gas to LP acid gas flare drum control valve 69-PV-1315B
(50-100%).
On rising pressure 69-PIC-1315 first opens the sour gas to TGTU control valve 69-PV1315A; further increase in pressure causes the pressure controller to open the vent
valve 69-PV-1315B to release gases to the LP Acid Gas Flare.
Fig. 22 – 69-PIC-1315 Controller Output
The above drawing shows the split range operation of 69-PV-1315A & 69-PV-1315B.
•
69-XV-1313 located at the downstream of sour water stripper top pressure control
valve 69-PV-1315A to TGTU closes on activation on ESD-0 and ESD-1 shutdown
•
Sour Water Stripper Column 6922-C-01 control valve 69-PV-1315A to TGTU closes
on instrument air failure
•
Sour Water Stripper Column 6922-C-01 control valve 69-PV-1315B to LP flare opens
on instrument air failure.
Controller
Tag
Control Description
69-PIC-1315
Sour Water Stripper top
pressure
Alarm
Unit
Operating
Set Point
Low
High
bar(g)
1
0.8
1.2
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4.6.3.4
Sour Water Stripper Bottom Level Control
Stripped water from the bottom of the Sour Water Stripper 6922-C-01 is pumped via
Stripped Water Pumps (6922-P-10A/B) to the Sour/Stripped Water Exchanger (6922-E01). Outlet from the Sour/Stripped Water Exchanger 6922-E-01 enters in to the
Stripped Water Cooler (6922-E-02) and the cooled stripped water is sent to
Observation and Buffer Sump.
Sour Water Stripper (6922-C-01) bottom level is controlled by regulating the stripped
water cooler outlet to the Observation and Buffer Sump.
Sour Water Stripper ‘MASTER’ level controller 69-LIC-1306 acts in cascade and provides
the set point to the Stripped Water Cooler outlet ‘SLAVE’ flow controller 69-FIC-1317
which regulates the flow control valve 69-FV-1317.
Controller
Tag
4.6.3.5
Alarm
Control Description
Unit
Operating
Set Point
Low
High
69-LIC-1306
Sour Water Stripper bottom
level
%
50
21
73
69-FIC-1317
Stripped Water Cooler
outlet flow
m3/hr
8
6
10
•
Low low level alarm (69-LALL-1316) in Sour Water Stripper 6922-C-01 bottom trips
the Stripped Water Pumps 6922-P-10A/B and closes the stripper outlet valve
69-XV-1339.
•
High high level alarm (69-LAHH-1316) Sour Water Stripper 6922-C-01 bottom trips
the Waste Water Degasser Pumps 6922-P-08A/B and closes the Waste Water
Degasser 6922-V-07 outlet valve 69-XV-1316.
•
Stripped Water Cooler 6922-E-02 outlet valve 69-FV-1317 to buffer sump closes on
instrument air failure.
Sour Water Stripper 6922-C-01 Top Level Control
Water from the Stripper Overheads Cooler (6922-E-03) is circulated to the top of the
Stripper through the Stripper Overhead Circulation Pumps (6922-P-11A/B). Stripper top
level is maintained by controlling the start-up-water which is mixed with the
circulated water from the Sour Water Stripper column at the suction of the Stripper
Overheads Circulation Pumps (6922-P-11A/B).
Stripper top level is monitored and controlled by 69-LIC-1325 which directly controls
the control valve 6922-LV-1325 in the start-up-water line.
Controller
Tag
Control Description
69-LIC-1325
Sour Water Stripper top
level
Alarm
Unit
Operating
Set Point
Low
High
%
50
30
74
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•
Low low level alarm (69-LALL-1315) in Sour Water Stripper top trips the Stripper
Overhead Circulation Pump 6922-P-11A/B
•
Start-up water control valve 69-LV-1325 closes on instrument air failure.
4.6.3.6
Circulating Water Flow to Stripper Overhead Cooler Control
Circulated water from the Sour Water Stripper (6922-C-01) top is pumped by Striper
Overhead Circulation Pumps (6922-P-11A/B) to Stripper Overhead Cooler (6922-E-03).
Circulated water flow to stripper overheads is measured by 69-FT-1316 and controlled
by the flow controller 69-FIC-1316 which directly controls the flow control valve
69-FV-1316 located in the common discharge of 6922-P-11A/B.
•
4.6.3.7
Controller
Tag
Control Description
69-FIC-1316
CW to Stripper Overhead
Cooler
Alarm
Unit
Operating
Set Point
Low
High
m3/hr
13.6
12.2
15
Circulating water flow control valve 69-FV-1316 to Stripper Overhead Condenser
opens on instrument air failure
Sour Water Stripper Reboiler Temperature Control
Temperature control is achieved by controlling the steam flow to the stripper reboiler.
LP steam flow to the Sour Water Stripper Reboiler 6922-E-04 is controlled by 69-FIC1315 which regulates the LP steam flow control valve 69-FV-1315.
Set point for the steam flow control is received from the calculation block 69-UY-1315,
where the sour water flow from 91-FIC-1314 is multiplied with manually set ratio (193)
between LP steam and sour water which is provided via 69-HIC-1315.
Controller
Tag
69-FIC-1315
Control Description
LP steam flow to the
Stripper Reboiler
Alarm
Unit
Operating
Set Point
Low
High
kg/hr
2154
1725
3015
•
LP steam valve 69-XV-1314 located on the upstream of the control valve 69-FV1315 closes on activation of Waste Water Degasser pressure high high alarm set at
1.3 barg.
•
LP steam flow control valve 69-FV-1315 to reboiler closes on instrument air
failure.
4.6.3.8
Stripper Reboiler Steam Temperature Control
Temperature control of LP steam is achieved by passing the LP steam to
Desuperheater (6922-X-01), where the temperature is maintained by injecting Boiler
Feed Water.
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LP steam outlet temperature from the Desuperheater is monitored by 69-TT-1327 and
controlled by 69-TIC-1327.
Temperature Controller 69-TIC-1327 directly regulates the boiler feed water flow via
69-TV-1327 located at the inlet of De-super heater.
Controller
Tag
69-TIC-1327
•
4.6.3.9
Control Description
LP steam temperature to
the Stripper Reboiler
Alarm
Unit
Operating
Set Point
Low
High
°C
148
NA
153
BFW control valve 69-TV-1327 to LP steam closes on instrument air failure
Re-boiler Condensate Level Control
LP condensate from the Sour Water Stripper Reboiler 6922-E-04 is collected in Reboiler Condensate Drum (6922-V-09). Condensate level is monitored by 69-LT-1327 and
controlled by 69-LIC-1327. Condensate level is maintained by throttling the control
valve 69-LV-1327 which regulates the condensate flow to the LP condensate header.
Controller
Tag
69-LIC-1327
•
Alarm
Control Description
Unit
Operating
Set Point
Low
High
Re-boiler Condensate Drum
level
%
50
17
75
Re boiler condensate control valve 69-LV-1327 to LP condensate header closes on
instrument air failure
4.6.3.10 Stripper Overheads Cooler Temperature Control
Circulating water from the Stripper Overheads Circulation Pumps (6922-P-11A/B)
enters in to the Stripper Overheads Cooler (6922-E-03) where the water is cooled and
passes to the Sour Water Stripper.
Temperature of the circulating water to the Sour Water Stripper (6922-C-01) is
monitored at the outlet of the Stripper Overheads Cooler by 91-TT-1315 and controlled
by 69-TIC-1315.
Temperature controller 69-TIC-1315 output controls the speed of the stripper
overhead cooler fans VSDs at the same time.
The temperature controller, 69-TIC-1315 regulates the speed of the sour water
Stripper Overheads Cooler VSDs (6922-EM-03AA, 6922-EM-03AB) to maintain the
temperature of circulation water to Sour Water Stripper.
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Alarm
Controller
Tag
Control Description
Unit
Operating
Set Point
Low
High
69-TIC-1315
Stripper overheads cooler to
sour water stripper
°C
55
50
60
Details of control tags for VSD’s are tabulated below:
S No.
Motor-no
Control Tag
Remarks
1.
6922-EM-03AA
69-SY-1324
VSD
2.
6922-EM-03AB
69-SY-1329
VSD
High high vibration alarm of each fan trips the respective fan motors
4.7
LP FUEL GAS
4.7.1
Equipment Specification
LP Fuel Gas KO Drum
Tag No.
6236-V-05
Size, mm, (Dia x T/T)
1100 x 2400
Design Pressure, barg
9.0
Design Temperature, °C
Operating Pressure, (Normal/Max), barg
Operating Temperature, °C
Material of Construction
4.7.2
Fuel Gas System Process Description
4.7.2.1
Introduction
100/0
6/7
25-50
CS
LP Fuel Gas is required for New Steam Generation Boiler Packages 6848-A-02A/B/C.
4.7.2.2
Process Description
The new Fuel Gas requirements under the SRU upgrade project will be secured from
two separate sources as follows.
Source 1 Supply
The main normal LP Fuel Gas supply for the new MP Steam Boiler Package (6848-A02A/B/C) is supplied from the first stage suction of the existing Booster Compressors
(6701-K-10/20/30) in NGL-3. In addition, two back up sources are provided; the first is
the fuel gas from 6103-K-01A/B with a second backup from existing 30” line (T-10).
The new fuel gas supply system will consist of a letdown station, Fuel Gas KO Drum
(6236-V-05) and a supply header to the steam boilers. The source pressure from the
take-off point will be let down to 7 barg through the pressure control valve 62-PV-
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1301A before entering the LP Fuel Gas KO Drum. The source pressure of the fuel gas
from 6103-K-01 A/B is 20 barg whilst that of feed gas from the 30” line is 45 barg. The
former is let down to 7 barg through the pressure control valve 62-PV-1301B and the
latter via 62-PV-1302.
Source 2 Supply
LP fuel gas for SRU upgrade new users (Reducing Gas Generator 9102-F-11 and new
Incinerator, 9101-F-14) will be sourced from the existing LP fuel gas header at NGL-3
as there is sufficient spare capacity available for there.
4.7.2.3
Operating and Control System
The fuel gas for the LP fuel gas system is taken from the first stage suction of the Lean
Gas Booster Compressors (6701-K-10/20/30), through 62-PV-1301A via pressure
controller 62-PIC-1301 located in the top of the LP Fuel Gas KO Drum (6236-V-05).
In the event of loss of lean gas supply from the Booster Compressors, the pressure
controller 62-PIC-1301 signal is routed to 62-PV-1301B via soft valve selector 62-PY1301. In addition if there is an emergency shutdown of NGL Extraction unit (from
where fuel gas is ultimately supplied) valve selector 62-PY-1301 is overridden and the
signal from 62-PIC-1301 is automatically routed to 62-PV-1301B. This allows back up
fuel gas taken from 6103-K-01A/B.
The takeoff for the second back up supply is from 30" existing line (T-10) routed
through 62-PV-1302 via pressure controller 62-PIC-1302.
A fast acting pressure control valve 62-PV-1303 controlled by pressure controller
62-PC-1303 is provided on the overhead line from 6236-V-05 to route fuel gas to LP
flare in the event the pressure in the KO drum continues to increase beyond the
normal operating range.
Alarm
Controller
Tag
Control Description
Unit
Operating
Set Point
Low
High
62-PIC-1301
LP fuel gas from existing
Booster compressors
bar g
7
5.3
7.8
62-PIC-1302
LP fuel gas to new SRU
bar g
7
5.3
7.8
62-PIC-1303
Fuel gas to LP flare
bar g
7
NA
7.8
•
High high pressure alarm (62-PAHH-1304) set at 8.2 barg in LP fuel gas trips the
boiler packages and closes the fuel gas inlet on/off valves 62-XV-1301, 62-XV-1302
and 62-XV-1303.
•
LP fuel gas inlet pressure control valves 62-PV-1301A, 62-PV-1301B and 62-PV-1302
close on instrument air failure.
•
Fuel Gas vent to LP flare pressure control valve 62-PV-1303 opens on instrument
air failure.
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4.8
4.8.1
SEA COOLING WATER SYSTEM
Equipment Specification
Sea Cooling Water Pumps
Equipment Tag No.
Pump Type
Process Medium
Capacity, m3/hr
Suction Pressure, barg, Normal/Max.
Discharge Pressure, barg
Design Pressure, bar(g)
Design Temperature, °C
Operating Temperature, °C
Driver Type
Rated Power, kW
Material of Construction, Casing/Internals
6932-P-04A/B
Vertical, Centrifugal
Sea Water
1600
0.07/0.25
5.0
8.0
85/0
35
Motor
340
Duplex SS/Duplex SS
Sea Cooling Water Filters
Equipment Tag No.
Process Medium
Size (ID/T/T), mm
Design Throughput, m3/hr
Design Temperature, °C
Design Pressure, barg
Operating Temperature, °C
Operating Pressure, barg
Material of Construction
6932-S-02A/B
Sea Water
610/1016
1600
85/0
8
15-40
5
Duplex SS
Local Biocide Drain Pit
Equipment Tag No.
6932-T-06
Size (L/W/H), mm
1000/1000/1000
Design Temperature, °C
Design Pressure, barg
Material of Construction
85/0
0
Concrete
Local Chemical Drain Pit
Equipment Tag No.
6932-T-01
Size (L/W/H), mm
1000/1000/1000
Design Temperature, °C
Design Pressure, barg
Material of Construction
85/0
0
Concrete
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4.8.2
Sea Cooling Water System Process Description
Sea Cooling Water system is required to supply cooling water for the coolers in the SRU
upgrade facilities. A part of sea cooling water is also supplied to existing sea water
supply system. The Sea Cooling Water system includes two Sea Cooling Water Pumps
(6932-P-04A/B, one operating and one standby), one Electro Chlorination Package
(6932-A-05), one Biocide Injection Package (6932-A-06) and one Scale Inhibitor
Injection Package (6932-A-07).
Two Sea cooling Water Pumps 6932-P-04A/B are installed on a new jetty and take
suction from the sea. The pumps are vertical-shaft, constant speed centrifugal pumps
and are electric motor driven. The sea water cooling pumps have a design capacity of
1600 m3/h (each) at a discharge pressure of 5.0 barg.
To meet the design flow requirements, one pump will be normally running, whilst the
other is on standby. Each pump is capable of supplying a normal flow of 1200 m3/h to
the users for SRU upgrade.
The water enters the pump body through a suction pipe (stilling tube) shaped to
reduce turbulence. A coarse mesh bar suction screen is installed at each pump to
prevent seaweed and other debris from entering the sea water system.
From the common discharge of seawater cooling pumps, seawater stream flows via a
new dedicated 24” main supply header to the new filtration package unit (6932-S02A/B). The self cleaning rotary type Sea Water Filters (one in operation and one on
standby) are capable of removing particle sizes greater than 1000 microns from
seawater and each unit is designed for a flow of 1600 m3/h. The filtered water from
filters is routed to the heat exchangers located in AGEU/TGTU another users.
A small portion of the main seawater (cooling water) flow is diverted downstream of
the filters to provide seawater supply for the Electro Chlorination Unit (6932-A-05).
The Electro Chlorination unit generates sodium hypochlorite solution. The sodium
hypochlorite solution is injected into Sea Cooling Water system. There is one
dedicated new Electro Chlorination Unit.
In addition, a dedicated Biocide Injection Unit (6932-A-06) for effective control of
growth of marine organisms and a dedicated Scale Inhibitor Injection Unit (6932-A-07)
to prevent formation of mineral scales in the Sea Cooling Water system are also
provided for existing as well as new sea cooling water systems.
The new cooling water system is a once through system and the sea water returned
from the SRU upgrade facilities is discharged into existing Seawater Observation Sump
(6932-X-01) which has a retention capacity of 60 m3. From the sump the seawater
overflows to the sea.
To prevent fouling the temperature of cooling water from each exchanger outlet
should not exceed the maximum allowable temperature limit of 45°C.
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A tie in to the existing NGL-3/4 seawater supply system is also provided to supply
seawater from the new seawater pumps.
4.8.3
Sea Cooling Water Control
4.8.3.1
Sea Cooling Water Pumps (6932-P-04A/B)
The cooling water pumps can be started and stopped from the DCS by means of one of
the hand switches 69-HS-1311/1322. The running status indication of the pumps is
provided in the DCS. In addition, pump discharge low pressure alarms with indication
in the DCS (69-PIA-1301/1303), a pressure transmitter (69-PT-1301/1303), and a
sample connection (69-SC-013/014) are provided for each pump.
The chlorination, biocide and scale inhibitor lines to the pumps are provided with flow
indicators to monitor injection of these chemicals into the pump suction.
The cooling water flow through each heat exchanger may be manually regulated by
butterfly valves located upstream/downstream of the exchanger. The valves are
within view of the respective process side temperature indicator locations.
For operational flexibility a 18” crossover connection between sea cooling water pump
discharge line 24”-6932-SW-259-A7A2 is provided to supply sea cooling water to NGL3/4. The crossover line contains two 18” butterfly valves which are normally closed.
4.8.3.2
Filtration System
The Sea Cooling Water Filtration system comprises of two self cleaning rotary type
Cooling Water Filters (6932-S-02A/B), one operating and one standby. Each filter is
designed for a flow of 1600 m3/hr and is capable of removing particle sizes greater
than 1000 microns. In addition each filter is equipped with an automatic back flushing
mechanism which operates on an intermittent basis when filter cleaning is required.
Across a cleaner seawater filter the normal pressure drop is 0.2 bar. During normal
operation the filter will become dirty over a period of time and the pressure drop
across it will increase. To ensure periodic cleaning of the online filter, a timer facility
within the filter control panel automatically initiates the cleaning cycle after a preset
interval and terminates it after a preset duration. The cleaning sequence involves the
start of the cleaning gear and opening of the drain ON/OFF valve 69-XV-1340/1341.
The former causes the debris trapped across the filter mesh to be loosened as the
mesh rotates against static scrapers whilst the latter allows the loosened debris to be
discharged back to the sea. The cleaning cycle lasts for approximately 90 seconds
after which the drain ON/OFF valve closes and the cleaning gear stops by
de-energising the contactor.
In addition to the timer, a differential pressure transmitter (PDT-1309/1310) can also
initiate the cleaning cycle when the filter pressure drop reaches a specified value
(0.5 barg). After the completion of the cleaning sequence the timer is also reset.
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The cleaning sequence may be stopped via hand switch (69-HS-1309/1310).
In the event the cleaning gear is stuck, a common alarm 69-XA-1309/1310 is initiated.
In addition a high high pressure drop alarm (69-PDAH-1309/1310) is also provided to
alert the operator in the event of problems with the cleaning of the filter.
The downstream isolation valves of both (operating and standby) filters are kept open
at all the times during normal operation. The inlet isolation valve (MOV-1303/1304) of
the standby filter is kept in closed position during normal operation.
The selection of the operating filter must be made from the DCS via hand switches
(HS-1309/1310).
4.8.3.3
Sea Cooling Water Outlet Pressure Control
Sea Cooling Water Pumps (6932-P-04A/B) outlet is routed to Sea Cooling Water Filters
(6932-S-02A/B) and the outlet pressure is maintained by the pressure controller
69-PIC-1306 by monitoring the pressure through 69-PT-1306 located in the common
discharge of the Sea Cooling Water Pumps. The pressure is maintained by regulating
the pressure control valve 69-PV-1306 in the cooling water drain line connected to the
sea.
69-PIC-1306 opens the drain line control valve 69-PV-1306 on rising pressure in the
outlet of Sea Cooling Water Pumps common discharge.
Controller
Tag
69-PIC-1306
•
4.9
4.9.1
Control Description
Sea Cooling Water Pumps
outlet pressure
Alarm
Unit
Operating
Set Point
Low
High
barg
6
NA
6.5
Sea cooling water drain control valve 69-PV-1306 opens on instrument air failure
ELECTROCHLORINATION PACKAGE
Equipment Specification
Electro Chlorination Package
Equipment Tag No.
6932-A-05
Process Medium
Sea Water
Design Throughput, kg/hr
Design Temperature, °C
Design Pressure, barg
10
85/0
8
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Auto Backwash Filter
Equipment Tag No.
Process Medium
Type
Design Throughput, m3/hr
Design Temperature, °C
Design Pressure, barg
6932-S-03A/B
Sea Water
Auto Self Cleaning, Backwash
type
14
85/0
6
Filtration Rate, Microns
500
Pressure Drop, Clean, bar
0.1
Pressure Drop, Dry, bar
0.22
Material of Construction, Body/Internal
GRP/Monel
Transformer Rectifier
Equipment Tag No.
Rating, kVA
Power Supply
6932-RC-101A/B
52.7
415 V, 3ph, 50 Hz
Output Voltage
44V DC
Output Current
922 Amps DC
Cooling
Design Temperature, °C
Air Natural Air Forced
85/0
Electrolyser
Equipment Tag No.
Type
Capacity Per Cell, kg/hr
Design Pressure, barg
Design Temperature, °C
Orientation
Casing
Anode
Cathode
6932-G-01A/B
Panchlor (Bi Polar)
10
6.0
85/0
Horizontal
GRP with uPVC Lining
Titanium Coated with Coating
of Platinum group Mixed oxide
Titanium
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Degassing Tank
Equipment Tag No.
Process Medium
Capacity, m3/hr
Design Temperature, °C
Design Pressure, barg
Residence Time, mins.
Material of Construction
6932-T-02
Sea Water
5.0
80/0
Atmospheric + Fully Filled
Liquid
15
Glass Reinforced Vinyl Ester
Hydrogen Dilution Blowers
Equipment Tag No.
Process Medium
6932-K-01A/B
Air
3
Capacity, m /hr
362
Design Temperature, °C
85/0
Design Pressure, mmWG
150
Motor Rating, kW
1.1
Material of Construction
SS316L
Dosing Pumps
Equipment Tag No.
Type
6932-P-05A/B
Centrifugal
3
7.0/14.0
Design Temperature, °C
85/0
Capacity, m /hr, Continuous/Shock Dosing
Design Pressure, barg
7.5
Motor Rating, kW
5.5
Material of Construction
Titanium
Acid Wash Tank
Equipment Tag No.
Type
6932-T-03
Vertical
Process Medium
HCl
3
2.0
Design Temperature, °C
80/0
Capacity, m
Design Pressure, barg
Working Pressure
Material of Construction
Atmospheric + Fully Filled
Liquid
ATM.
Glass Reinforced Vinyl Ester
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Acid Wash Pump
Equipment Tag No.
6932-P-06
Type
Magnetic Drive
Process Medium
HCl
3
5.0
Design Temperature, °C
85/0
Capacity, m /hr, Continuous/Shock Dosing
Design Pressure, barg
6.0
Motor Rating, kW
2.2
Material of Construction
Poly Propylene
Acid Bund
Material of Construction
4.9.2
GRP
Electro Chlorination System Description
During normal operation the Electro Chlorination Unit supplies Sodium Hypochlorite
that is injected into the suction lines of the Seawater Supply Pumps (6932-P-04A/B).
The hypochlorite controls the growth of marine organisms in sea cooling water system.
A small portion of the main sea cooling water flow to the new units of SRU is diverted
downstream of the filters 6932-S-02A/B and this provides the sea water supply for the
Electro Chlorination Unit 6932-A-05.
The required flow of sea water is fed to each electrolyser module designed to produce
10kg/h of active chlorine. Direct current is passed through the sea water producing a
sodium hypochlorite solution and hydrogen. The amount of active chlorine (sodium
hypochlorite) produced, is directly proportional to the current passed through the
cells. Hence, sea water is not normally varied. Any required reduction in active
chlorine demand can be achieved by manually adjusting electrical current to the
electrolysers at the local control panel.
4.9.2.1
Biocide and Scale Inhibitor Injection Packages
During normal operation, the biocide from the Biocide Injection Package is directly
injected into the hypochlorite injection line from Electro Chlorination Package just
before the injection point into the Sea Cooling Water Pump Suction of existing
(P-3001A/B/C & P-1618AR/BR/CR) and new 6932-P-04A/B sea cooling water systems.
The injection is to be carried out at a concentration of 6.6 ppm three times daily for a
15 minute period. The biocide filling into the Biocide Storage Tank inside the package
is a manual operation using flexible hose.
During normal operation the scale inhibitor from the Scale Inhibitor Injection Package
is injected into Sea Cooling Water Pump suction of existing (P-3001A/B/C &
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P-1618AR/BR/CR) and new 6932-P-04A/B Sea Cooling Water Pumps. The injection is
carried out continuously at a concentration of 1.5 ppm. The scale inhibitor filling into
the storage tank inside the package is a manual operation using flexible hose.
4.9.3
Electro chlorination Package Control
4.9.3.1
Changeover of Auto Back Wash Filter
Sea water is supplied to the skid at a rate of 14 m3/hr. 69-PCV-1463 maintains the
system sea water pressure at 3.5 bar g from the inlet pressure of 5 bar (g).
Sea water is filtered to 500 microns to supply to the electrolyser. An auto back wash
filter (6932-S03A/6932-S-03B) is installed which operates on a duty/stand by basis,
During the initiation of changeover/backwash the actuated discharge valve (69-XV1453/69-XV-1456) of duty filter will close, the actuated backwash valve of duty filter
(69-XV-1452/69-XV-1455) will open and the actuated discharge valve (69-XV-1453/
69-XV-1456) of stand by filter will open which ensures the filter changeover was
happened.
Following are the causes for filter change over to occur:
Sl. #
Tag No.
1.
69-PDI-1452
2.
3.
4.
4.9.3.2
Limit
Unit
Value
DP across 6932-S-03A
High-high
barg
0.2
69-PDI-1453
DP across 6932-S-03B
High-high
barg
0.2
69-PI-1455
Filter common discharge
Low-low
barg
2.75
69-FI-1456
Service
Electrolyser common I/L
Low-low
3
m /hr
8.0
Changeover of Electrolyser
Electrolyser stream (6932-G-01A/6932-G-01B) operates on duty/standby basis.
Following are the causes for electrolyser changeover to occur:
Sl. #
I.
Tag No.
69-FI-1451
Service
Inlet flow to 6932-G01A
Limit
Low-low
Unit
Value
3
10
3
m /hr
II.
69-FI-1452
Inlet flow to 6932-G01B
Low-low
m /hr
10
III.
69-PI-1455
Filter common discharge
High-high
barg
4.5
Also if the temperature difference between electrolyser upstream temperature (69TT-1451) and downstream of the individual electrolyser temperature (69-TT-1452/69TT-1453) is 5°C then controlled shutdown is initiated and the standby electrolyser unit
is started.
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4.9.3.3
Dosing Pumps Discharge Flow Control
Dosing pumps (6932-P-05A/B) discharge flow is controlled via flow controller 69-FIC-1453.
Dosing pump discharge flow rate is measured by magnetic flow transmitter 69-FT-1453
and controlled by 69-FIC-1453, set point is locally provided on the HMI.
Output of 69-FIC-1453 directly commands the control valve 69-FV-1453.
Controller
Tag
Control Description
68-FIC-1453
Dosing pumps discharge
flow control
Alarm
Unit
Operating
Set Point
Low
High
m3/hr
2 & 11
1.8
13.0
Note: The controller 68-FIC-1453 has 2 Set Points based on the Continuous Dosing and
Shock Dosing. When continuously dosed, set point is 2m3/hr whereas for Shock Dosing,
set point is 11m3/hr.
4.9.3.4
Acid Pumps Control
The acid wash system is a manual system.
To maintain the efficiency of the electrolyser streams, regular washing with dilute HCL
is required to remove the hydroxide deposits.
Following are the causes for tripping of Acid Wash Pump 6932-P-06:
Sl. #
4.10
4.10.1
Tag No.
Service
Limit
Unit
Value
1.
69-LI-1454
Acid Wash Tank level
Low-low
mm
370
2.
69-AI-1451
Conductivity of acid wash
solution
High-high
µS/cm
77000
NGL-4 SEA WATER FILTERS
Equipment Specification
Sea Water Filters
Equipment Tag No.
S-8840A/B
Process Medium
Sea Water
Capacity, kg/hr, Min./Max.
Design Temperature, °C
Design Pressure, barg
138240/309760
85/0
7.0
Operating Temperature
40/15
Operating Pressure, barg
4
Material of Construction, Casing/Elements
SA240UNS S31803/Duplex SS
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4.10.2
NGL-4 Sea Water Filters S-8840A/B Description
Two Sea Water Filters S-8840A/B are installed in the existing sea water from cooling
water supply line 8”-88-32-WR-0066-001W.
The filter consists of a pressure containment body with inlet, outlet, drain/backwash
outlet, PSV and vent connections. Filter Basket has been sized for the design flow
conditions. Access to the filter basket is via the bolted cover at the top of the
assembly. Sealing of the cover to the body is via a spiral wound gasket and stud bolts.
A simple devit arm is provided to allow removal and support of the cover during
maintenance operations.
Across a clean Seawater Filter S-8840A/B the normal pressure drop is 0.2 bar. During
normal operation the filter will become dirty over a period of time and the pressure
drop across it will increase. The differential pressure transmitter (88-PDT-801) raises
an alarm when the filter pressure drop reaches a specified value (0.4 bar). This means
the filter needs cleaning and the clean filter is brought on line.
4.11
4.11.1
DEMINERALISED WATER SYSTEM
Equipment specification
DM Water Package
Equipment Tag No.
6834-A-07
Process Medium
DM Water
3
8.0
Design Temperature, °C
85/0
Design Pressure, barg
12.3
Capacity, m /hr
Cationic Exchangers Bed
Equipment Tag No.
Process Medium
ID, mm
6834-S-21A/B
Fresh Water
600
3
Capacity, m /hr
3
Flow Rate, m /hr
10.5
7.0
Design Temperature, °C
85/0
Design Pressure, barg
12.3
Operating Temperature, °C
49
Operating Pressure, bar
4.0
Material of Construction, Casing/Elements
CS
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Anionic Exchangers Bed
Equipment Tag No.
Process Medium
6834-S-22A/B
Fresh Water
ID, mm
950
3
Capacity, m /hr
10.5
3
Flow Rate, m /hr
7.0
Design Temperature, °C
85/0
Design Pressure, barg
12.3
Operating Temperature, °C
49
Operating Pressure, bar
4.5
Material of Construction, Casing/Elements
CS
DM Water Recycle Pumps
Equipment Tag No.
Process Medium
6834-P-37A/B
DM Water
3
Capacity, m /hr, Normal/Rated
3
10.5/10.5
Minimum flow, m /hr
1.11
Design Pressure, barg
12.3
Design Temperature, °C
85/0
Suction Pressure, bara, Rated
2
Operating Temperature, °C
43
Operating Pressure, bara
6
Driver Type
Driver Power, kW
Material of Construction, Casing/Elements
Motor
5.5
SS316L
Resin Trap
Equipment Tag No.
6834-SP-11A/B/C/D
Diameter, mm
60.3
Length, mm
300
Design Temperature, °C
85/0
Design Pressure, barg
12.3
Material of Construction, Casing/Elements
SS316L
Mesh Size, mm
0.202
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DM Water Feed Pumps
Equipment Tag No.
6834-P-24A/B
Process Medium
DM Water
3
Capacity, m /hr
12.0
Design Pressure, barg
5.1
Design Temperature, °C
Suction Pressure, bara, Design/Rated
85/0
1.57/0.96
Operating Temperature, °C
43
Operating Pressure, bara
4.7
Material of Construction, Casing/Elements
A743CF3M/SS316L
DM Water Regeneration Pump
Equipment Tag No.
Process Medium
6834-P-36A/B
DM Water
3
Capacity, m /hr
3.0
Suction Pressure, bara
1
Operating Temperature, °C
30
Operating Pressure, bara
5
Drive Type
Motor
Driver Power, kW
5.5
Material of Construction, Casing/Elements
SS
DM Water Neutralization Pumps
Equipment Tag No.
Process Medium
6834-P-38A/B
DM Water
3
Capacity, m /hr, Normal/Rated
3
10.0/10.0
Minimum flow, m /hr
1.0
Design Pressure, barg
2.2
Design Temperature, °C
Suction Pressure, kg/cm2(a), Design/Rated
85/0
0.8/0.78
Operating Temperature, °C
30
Operating Pressure, bara
2.6
Drive Type
Drive Power, kW
Material of Construction, Casing/Impeller
Motor
4.0
PP/PP
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HCl Dosing Pumps
Equipment Tag No.
Process Medium
6834-P-35A/B
HCl
Double Hydraulic Diaphragm
Metering Pump
Type
Capacity, Lit/hr
180
Design Pressure, barg
3.7
Design Temperature, °C
85/0
Operating Temperature, °C
30
Operating Pressure, bara
3.0
Driver Type
Motor
Driver Power, kW
1.1
Material of Construction
PP
HCl Storage Tank
Equipment Tag No.
6834-T-16
Process Medium
HCl
ID/Height, mm
1400/2730
3
Capacity, m
4
Design Pressure, barg
ATM
Design Temperature, °C
85/0
Material of Construction
GRP
HCl Unloading Pump
Equipment Tag No.
6834-P-38
Process Medium
HCl
Capacity, L/hr
150
Design Pressure, barg
3.5
Design Temperature, °C
85/0
Material of Construction
PTFE/PVDF
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NaOH Dosing Pumps
Equipment Tag No.
6834-P-34A/B/C
Process Medium
NaOH
Double Hydraulic Diaphragm
Metering Pump
Type
Capacity, Lit/hr
301
Design Pressure, barg
3.7
Design Temperature, °C
85/0
Suction Pressure, bara
1
Discharge Pressure, bara
3
Operating Temperature, °C
30
Driver Type
Motor
Driver Power, kW
Material of Construction
2.2
SS316L/PTFE
NaOH Storage Tank
Equipment Tag No.
6834-T-15
Process Medium
HCl
ID/Height, mm
1400/2730
3
Capacity, m
4
Design Pressure, barg
ATM
Design Temperature, °C
85/0
Material of Construction
SS
NaOH Unloading Pump
Equipment Tag No.
Process Medium
Capacity, L/hr
Design Pressure, barg
Design Temperature, °C
Material of Construction
4.11.2
6834-P-39
NaOH
150
3.5
85/0
PTFE/PVDF
Demineralised Water System Process Description
Demineralised Water Package Unit 6834-A-07 (one operating, one standby/
regenerating), is designed to produce flow of 7 m3/h of demineralised water. The
Demineralised water is supplied to the new heating system and connectivity to the
existing DMW header is also provided to allow operation flexibility.
Demineralised water unit will provide DMW to the following users:
•
Make up water to Steam Condensate Flash Drum (6834-V-05)
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•
Amine Surge Tank (9103-T-11)
•
Make up water to Cooling Water Circulation Pump (9102-P-12A/B)
•
Start-up water to Stripped Overhead Circulation Pump (9102-P-11A/B)
•
Make up water to Amine Regenerator Reflux Drum (9103-V-12)
•
Existing DMW network system (for operational flexibility, normally no flow)
4.11.2.1 Demineralised Water Package
The Demineralised Water Package is based on ion exchange technology (similar to the
existing DMW package) and consists of two identical trains.
The DMW package operates continuously and automatically and thus requires minimum
intervention. The package includes the necessary control and safety devices. The
Demineralised Water from the DMW package is routed to Demineralised Water Storage
Tank (6834-T-08). Capacity of Demineralised Water Storage Tank is 83 m3.
Fresh water is sent to the new users (DMW package & utility) continuously by means of
the Drinking Water Feed Pumps (6834-P-23A/B, one operating, one standby) each
having a design capacity of 10 m3/h. The duty/standby is selected via a selector switch
in the DCS. The pumps are manually started and stopped through hand switches 68-HS1305/1306 and operated continuously.
A minimum continuous flow recycle line with a restriction orifice (6834-RO-1303)
ensures that there is always a minimum flow through the pump.
Low low level alarms (68-LALL-006/007, via existing manual selector 68-HS-008) will
shutdown the operating pump in the event of low-low level in Drinking Water Storage
Tanks.
The control ensures a safe and continuous operation and is summarized below:
A. Flow Totaliser
A flow totaliser placed in the main fresh inlet line to each ion exchange train sums the
total water passing through the DMW unit. In normal operation, the end of a treatment
cycle is determined on a volumetric basis by the totaliser which generates the order to
switch from the online train to standby train. Following the switch over the
regeneration sequence is commenced for the offline train.
B. Conductivity Meter
If high conductivity is reached before the end of the volumetric cycle, then the
respective conductivity meter initiates the same automatic switch over order as
generated by the volumetric cycle. If, in spite of this order, the conductivity continues
to increase, then a separate high-high conductivity meter initiates a complete
shutdown.
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C. Differential Pressure
A differential pressure transmitter switch installed across the ion exchangers, also
initiates the same switchover as the above volumetric cycle.
D. Regeneration
Demineralised water is used as service water for regeneration. From the storage tank
(6834-T-08), regeneration DMW is delivered by means of the Regeneration Water
Pumps 6834-P-36A/B.
A solution of Caustic Soda is used to regenerate the anion resins. Concentrated Caustic
Soda is stored in a storage tank. Before injection into the exchanger bed, the caustic
soda is diluted by means of an in-line mixer.
A solution of Hydrochloric Acid is used for cation resin regeneration. It is stored in the
HCl storage Tank. The required dilution before injection into the exchanger bed is
made by means of an in-line mixer.
The regeneration effluents are collected in the concrete Neutralisation Pit where they
are neutralised before being pumped out for disposal to effluent treatment plant.
The pit is fitted with a pH-meter controller which controls acid dosing or caustic
dosing to achieve neutralisation. Neutralisation Pit Pump re-circulates the effluent
mixture for homogenisation. Plant air diffusion is also provided to enhance mixing.
E. DMW Storage Tank (6834-T-08)
The DMW package outlet line includes an automatic ON/OFF valve which is actuated
by means of a signal coming from low/high level signal (68-LT-1305) on the DMW
Storage Tank (6834-T-08).
De-mineralized water from the DMW storage tank is directed, at a pressure and
temperature of 3.7 barg and ambient temperature respectively by means of DMW Feed
Pumps (6834-P-24A/B) to condensate flash drum (6834-V-05).
The DMW storage tank is equipped with level alarms, High-High/Low-Low liquid level
(LAHH-1306/LALL-1307). The former generates a High-High liquid level alarm in the
control room, whilst the latter initiates Low low liquid level trip which shuts down the
Regeneration Pumps 6834-P-36A/B in the DMW Package and DMW Feed Pumps.
F. Demineralised Water Feed Pumps (6834-P-24A/B)
Centrifugal type, DMW feed pumps (one running, one standby) are used to supply
demineralised water at 3.7 barg pressure and ambient temperature, from DMW storage
tank.
Each pump is designed for a flow of 12 m3/hr based in heating system start-up (Filling
inventory vessels such as condensates flash drum, De-aerator and Boilers in one shift).
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A minimum flow recycle line with a restriction orifice (6834-RO-1301) ensures that
there is always a minimum flow through the pump.
These pumps can be stopped automatically, by the low low alarm (68-LALL-1307) or
manually, from the central control room using hand switch (68-HS-1307B/1308B) or
local panel (68-HS-1307A/1308A).
In the event of non ESD trip of operating pump, standby pumps will start
automatically.
4.11.3
Demineralised Water System Control description
4.11.3.1 Demineralised Water Flow Control 68-FIC1828
Demineralised water outlet to the DM water storage tank (6834-T-08) is controlled by
68-FIC-1828.
Fresh water flow to the Train-1 & 2 is measured by 68-FT-1825 and 68-FT-1827
respectively and final treated DM water to the DM water storage tank is measured by
68-FT-1828.
Flow controller 68-FIC-1828 takes any of the above transmitter’s value as per the train
selection, for calculating the output which directly commands the DM water storage
tank control valve 68-LCV-1827.
DM water storage tank MASTER level controller 68-LIC-1305 cascaded with SLAVE
68-FIC-1828 for allowing a maximum flow rate equal to the inlet flow rate available to
DM package in order to guarantee a minimum recirculation flow rate.
Alarm
Controller
Tag
Control Description
Unit
Operating
Set Point
Low
High
68-LIC-1305
DM Water Storage
Tank level
%
XX
XX
XX
68-FIC-1828
DM Water package
O/L flow
m3/hr
XX
XX
XX
•
DM Water Package flow low low alarm 68-FALL-1830 set at XXXX trips the
Recirculation Pump 6834-P-37A/B
•
DM Water Storage Tank level control valve 68-LCV-1827 closes on instrument air
failure.
4.11.3.2 Recirculation Water Flow Control 68-FIC-1826/68-FIC1829
Recycling fresh water flow controller 68-FIC-1826 (Train-A), 68-FIC-1829 (Train-B)
determines the amount of recirculation flow passes through the control valve 68-FV1826 (Train-A), 68-FV-1829 (Train-B) to the cationic exchangers bed during phase no 1
(Service) and phase no 6 (Final rinse with recirculation).
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Recycle water pumped from 6834-P-37A is measured by a vortex type flow meter
68-FT-1826 (Train-A) and 68-FT-1829 (Train-B).
Set points for the above controllers are provided locally.
Alarm
Controller
Tag
Control Description
Unit
Operating
Set Point
Low
High
68-FIC-1826
Train-A recirculation
flow control
m3/hr
XX
XX
XX
68-FIC-1829
Train-B recirculation
flow control
m3/hr
XX
XX
XX
•
Recirculation Pump 6834-P-37A discharge flow low low alarm 68-FALL-1837 trips
the Recirculation Pump 6834-P-37A in MCC.
•
Recirculation Pump 6834-P-37B discharge flow low low alarm 68-FALL-1838 trips
the Recirculation Pump 6834-P-37B in MCC.
•
Recirculation flow control valve 68-FV-1826 (Train-A) and 68-FV-1829 (Train-B)
closes on instrument air failure.
4.11.3.3 Regeneration Water Flow Control
Regeneration water from the DM Water Storage Tank (6834-T-08) to static mixers
6834-M-02A and 6834-M-02B is controlled by the flow controller 68-FIC-1835 and
68-FIC-1836 respectively.
Regeneration water to static mixer 6834-M-02A and 6834-M-02B is measured by 68-FT1835 and 68-FT-1836. Set points for both the controllers are provided locally.
Output of the controllers 68-FIC-1835 and 68-FIC-1836 directly commands the control
valve 68-FV-1835 and 68-FV-1836, respectively.
Alarm
Controller
Tag
Control Description
Unit
Operating
Set Point
Low
High
68-FIC-1835
Regeneration Pump discharge
to Static Mixer 6834-M-02A
m3/hr
XX
XX
XX
68-FIC-1836
Regenerated Pump discharge
to Static Mixer 6834-M-02B
m3/hr
XX
XX
XX
•
Regeneration Pump 6834-P-36A/B discharge flow low low alarm 68-FALL-1839 trips
the Regeneration Pump 6834-P-36A/B, HCl Dosing Pumps 6834-P-35A/B and
Caustic Dosing Pump 6834-P-34A/B.
•
Regeneration water flow control valves 68-FV-1835 and 68-FV-1836 closes on
instrument air failure.
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4.11.3.4 Pump ON/OFF Controls
1. Acid Dosing Pumps
Tag/Alarm
68-PI-1825
68-PI-1826
68-PI-1827
68-LI-1825
68-FI-1839
68-LI-1307
68-AI-1831
68-LI-1830
Description
Pump diaphragm
failure
Pump diaphragm
failure
Pump diaphragm
failure
HCL storage tank
level low
Regeneration Pump
discharge flow low
low
DMW Storage Tank
level low
Neutralisation Pump
discharge
Neutralisation Pit
low level
Pump Tag No.
6834-P-35A
6834-P-35B
6834-P-35C
Action
Trips the pump and
start the stand by pump
Trips the pump and
start the stand by pump
Trips the pump and
start the stand by pump
6834-P-35A, B & C
Trips the running pumps
6834-P-35A, B & C
Trips all the running
pumps
6834-P-35A, B & C
Trips all the running
pumps
6834-P-35A, B & C
Starts the duty pump
6834-P-35 B & C
Trips the pump
2. Caustic Dosing Pumps
Tag/Alarm
68-PI-1828
68-PI-1829
68-PI-1830
68-LI-1827
68-FI-1839
68-LI-1307
68-AI-1831
68-LI-1830
Description
pump diaphragm
failure
pump diaphragm
failure
pump diaphragm
failure
NaOH Storage Tank
level low low
Regeneration Pump
discharge
DMW storage tank
level low
Neutralisation Pump
discharge
Neutralisation Pit
low level
Pump Tag No.
6834-P-34A
6834-P-34B
6834-P-34C
6834-P-34A, B & C
6834-P-34A, B & C
6834-P-34A, B & C
Action
Trips the pump and
start the stand by pump
Trips the pump and
start the stand by pump
Trips the pump and
start the stand by pump
Trips the running pumps
Trips all the running
pumps
Trips all the running
pumps
6834-P-34A, B & C
Starts the duty pump
6834-P-34 B & C
Trips the pump
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3. Regeneration Pumps
Tag/Alarm
Description
Pump Tag No.
Action
68-LI-1307
DMW storage tank
level low-low
6834-P-36A & B
Trips both the pump
68-FI-1839
Regeneration Pump
flow low-low
6834-P-36A & B
Trips both the pump
68-FI-1835
Static Mixer 6834-M02A inlet DM Water
flow low
6834-P-36A & B
Starts the stand-by
pump
68-FI-1836
Static Mixer 6834-M02B inlet DM Water
flow low
6834-P-36A & B
Starts the stand-by
pump
4. Recirculation Pumps
Tag/Alarm
Description
Pump Tag No.
Action
68-FI-1837
Recirculation pump
flow low low
6834-P-37A
Trips the pump
68-FI-1838
Recirculation pump
flow low low
6834-P-37B
Trips the pump
5. Neutralization Pumps
Tag/Alarm
4.12
4.12.1
Description
Pump Tag No.
Action
68-LI-1831
Neutralisation tank
level high
6834-P-38A/B
Starts the duty pump
68-LI-1830
Neutralisation tank
level low
6834-P-38A/B
Trips both the pump
BOILER FEED WATER DEAERATOR SYSTEM
Equipment specification
Steam Condensate Flash Drum
Equipment Tag No.
6834-V-05
Size, (ID X T/T), mm
2600/7800
Design Pressure, barg
3.5/FV
Design Temperature, °C, Min./Max.
0/150
Operating Pressure, barg
0.1
Operating Temperature, °C,
102
Material of Construction
CS + 1.5mm CA
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De-aerator Feed Pumps
Equipment Tag No.
6834-P-20A/B
Type
Horizontal Centrifugal
3
Design Capacity, m /hr
221
Design Pressure, barg
8.5
Design Temperature, °C, Min./Max.
Suction Pressure, bara, Normal/Rated
0/150
1.82/5.54
Discharge Pressure, bara
4.51
Operating Temperature, °C
102
Driver Type
Motor
Driver Rating, kW
30
Material of Construction, Casing/Impeller
CS/SS316
Steam Condensate Cooler
Equipment Tag No.
6834-E-02
Type
Forced Draft
Design Duty, kW
5422
Design Pressure, barg
Design Temperature, °C, Min./Max.
Inlet Pressure, barg
Operating Temperature, °C, In/Out
No. of Fans
8.5
0/150
1.75
102/59
3
Fan Driver Type
Motor
Driver Rating, kW
15
Material of Construction, Casing/Impeller
CS
BFW De-aerator Package
Equipment Tag No.
6834-A-08
3
Design Capacity, m /hr
110
Design Pressure, barg
3.5/FV
Design Temperature, °C, Min./Max.
0/185
Operating Pressure, barg
0.2
Operating Temperature, °C
105
Material of Construction, Casing/Impeller
CS + 3mm CA
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Boiler Feed Water Pumps
Equipment Tag No.
Type
Centrifugal
3
Flow Rate, m /hr
55
Design Pressure, barg
31
Design Temperature, °C, Min./Max.
0/185
Suction Pressure, barg, Max./Rated
5.55/1.92
Discharge Pressure, bara
21.8
Operating Temperature, °C
105
Driver Type
Driver Rating, kW
Material of Construction, Casing/Impeller
4.12.2
6834-P-22A/B/C
Motor
110
CS/SS316
Boiler Feed Water De-aerator Description
4.12.2.1 Steam Condensate Flash Drum (6834-V-05)
The LP steam condensates mixtures are collected in the Steam Condensate Flash
Drum. The purpose of this vessel is to stabilise the steam condensate entering the
drum and to cool down the inventory to 102°C to prevent cavitations in De-aerator
Feed Pumps.
The Flash Drum receives fluids from two phase steam condensates from condensate
distribution header and DMW from DMW Feed Pumps 6834-P-24A/B.
The operating pressure in the Flash Drum is 0.1 barg. During normal operation,
minimum or no flow across 68-RO-1302 is expected and which is sized for steam
condensate cooler failure case. Pressure relief valves (68-RV-1091A/B, one operating
and one spare) protect the drum against overpressure. The RVs relieve to the
atmosphere and are set at 3.5 barg.
4.12.2.2 Steam Condensate Cooler (6834-E-02)
The relatively cool (43°C) DMW feed make-up entering the mixing compartment of the
Steam Condensate Flash Drum picks up heat from the incoming hot condensate
stream. To maintain its liquid state, the demineralised water/condensate mixture in
the drum is continuously circulated through the Seam Condensate Cooler by the
De-aerator Feed Pump 6834-P-20A/B. The temperature is controlled at 102°C by using
temperature control valve (68-TV-1301) prior to forwarding the water to the Boiler
Feed Water De-aerator unit for further treatment.
4.12.2.3 De aerator Feed Pumps (6834-P-20A/B)
Centrifugal type, De-aerator Feed Pumps (6834-P-20A/B, one running, one standby)
has a dual purpose: first to recycle approximately 49.8 % of the total normal discharge
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flow back to the flash drum via the Steam Condensate Cooler. The second is to feed
the balance of the pump discharge flow to the Boiler Feed De-aerator package
(6834-A-08) for further treatment.
These pumps will be stopped automatically, by the low-low alarm (68-LALL-1309) or
manually, from the central control room using hand switch (68-HS-1309/1310) or local
panel (68-HS-1309).
In the event of a non ESD trip of the operating pump, the standby pump will start
automatically.
4.12.2.4 Boiler Feed Water De-aerator Package (6834-A-08)
The boiler feed water stream enters the BFW De-aerator Package (6834-A-08) at the
top of the De-aerator column. It is contacted counter-currently with stripping steam,
which heats and scrubs the incoming feed, forcing the water to give up its CO2 and
most of its O2 content. Oxygen Scavenger is added to the water in the hold up section
of the De-aerator to further reduce the O2 content.
The De-aerator pressure is controlled at 0.2 barg by means of a pressure controller
(68-PIC-1304) which acts on pressure control valve (68-PV-1304) located in the LP
stripping steam line.
The De-aerator is protected from over pressure by a set of pressure relief valves
(68-PSV-1337A/B), set at 3.5 barg. The De-aerator package is designed for FV. The
liquid level in the De-aerator drum is maintained by 68-LIC-1302 through 68-LV-1302 in
the BFW feed inlet line.
The Boiler Feed Water pumps (6834-P-22 A/B/C) take suction from a common
manifold. The discharge pressure of Boiler Feed Water Pump is 20.8 barg. The
minimum flow is controlled by 68-FIC-1305 using 68-FV-1305 and discharged liquid
back to De-aerator drum.
4.12.2.5 Chemical Injection Package (6834-A-09)
The BFW Chemical injection Package is used to inject Boiler Feed water with O2
Scavenger and a Complex Product. The Complex Product is administrated to increase
pH value of the boiler feed water from 7 to between 9.0 and 10.5 to protect the
internal walls of the steam drums against corrosion and scaling. The amount of
complex product solution is proportional to the boiler feed water flow and is injected
at the discharge of Boiler Feed Water pumps.
The package includes for each chemical, a set of Chemical Storage Tank, Chemical
Injections Pumps and Chemical Unloading Pump.
Chemical Injection Pumps are of reciprocating, positive displacement, automatic
metering type i.e. the amount of chemical injected is proportional to the boiler feed
water flow as measured by the dedicated chemical pumps speed variation controllers.
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There are two sets of Chemical Injection Pumps (each comprising two electric motor
driven gear pumps) provided for each chemical as follows;
•
Two Oxygen Scavenger Injection Pumps 6834-P-39A/B for De-aerator (6834-A08) treatment
•
Two Complex Product Injection Pumps 6834-P-41A/B for Steam Boiler (6834-A02A/B/C) Feed Water treatment
4.12.2.6 Boiler Feed Water Pumps (6834-P-22A/B/C)
Centrifugal type Boiler Feed Water Pumps (two running, one standby) have dual
purpose; the first is to supply Boiler Feed Water at 18.5 barg and 105°C to Steam
Generation Package and the second is to supply BFW to the TGTU. A small stream is
also connected to Sour Water Stripper Reboiler 6922-E-04 for desuperheating purpose.
The pumps are designed to supply a normal continuous flow of oxygen free and pH
controlled Boiler Feed Water to the Steam Boilers 6834-A-02 A/B/C and Reactor
Effluent Cooler (9102-E-11).
The minimum flow is controlled by flow controller 68-FIC-1305 by acting on flow
control valve 68-FV-1305 which returns part of the pump discharge flow back to the
Deaerator.
In the event of a non ESD trip of the operating pump, the standby pump will start
automatically.
4.12.3
Boiler Feed Water Deaerator Control Description
4.12.3.1 Steam Condensate Flash Drum Level Control
Level in the Steam Condensate Flash Drum 6834-V-05 is maintained by 68-LIC-1301 by
monitoring the level through the transmitter 68-LT-1301. Level is controlled by
regulating the makeup DMW through the control valve 68-LV-1301.
Controller
Tag
68-LIC-1301
Alarm
Control Description
Unit
Operating
Set Point
Low
High
Steam Condensate Flash
Drum level
%
50
18
79
•
High high level alarm 68-LAHH-1308 in Steam Condensate Flash Drum trips the DM
Water Feed Pumps 6834-P-24A/B.
•
Low low level alarm 68-LALL-1309 in Steam Condensate Flash Drum trips the
Deaerator Feed Pumps 6834-P-20A/B.
•
Steam Condensate Flash Drum level control valve 68-LV-1301 closes on instrument
air failure.
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4.12.3.2 Steam Condensate Flash Drum Outlet Temperature Control
Steam Condensate Flash Drum 6834-V-05 outlet temperature is monitored by 68-TT1301 and controlled by 68-TIC-1301 located in the suction of Deaerator Feed Pumps
6834/P-20A/B.
Temperature control is achieved by regulating the steam condensate from the cooler
6834-E-02 through the control valve 68-TV-1301 located in the Steam Condensate
Cooler outlet line entering in to the Steam Condensate Flash Drum.
Controller
Tag
68-TIC-1301
•
Alarm
Control Description
Unit
Operating
Set Point
Low
High
Steam Condensate Flash
Drum temperature
°C
102
97
107
Steam Condensate Flash Drum temperature control valve 68-TV-1301 opens on
instrument air failure
4.12.3.3 Deaerator Feed Pumps Minimum Flow Control
Deaerator feed pumps 6834-P-20A/B discharge one stream is routed to BFW Deaerator
package and other stream is routed to Steam Condensate Cooler for maintaining
temperature in the flash drum.
Deaerator Feed Pumps 6834-P-20A/B minimum flow control is achieved by regulating
the control valve 68-FV-1301 (located in the bypass of 68-TV-1301) which allows the
minimum flow to pass even when the 68-TV-1301 is fully closed.
Controller
Tag
Control Description
68-FIC-1301
Deaerator Feed Pumps
flow control
•
Alarm
Unit
Operating
Set Point
Low
High
m3/hr
83
66.6
NA
De-aerator feed pumps minimum flow control valve 68-FV-1301 opens on
instrument air failure
4.12.3.4 Deaerator Level Control
Level in the Deaerator is monitored by the level transmitter 68-LT-1302 and controlled
by the level controller 68-LIC-1302.
Level control is achieved by regulating the control valve 68-LV-1302 located in the
Deaerator Feed Pumps flow to the Deaerator.
Controller
Tag
Control Description
68-LIC-1302
Deaerator level control
Alarm
Unit
Operating
Set Point
Low
High
%
50
16
86
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•
High high Level alarm 68-LAHH-1312 in Deaerator closes the Deaerator inlet
ON/OFF valve 68-XV-1301.
•
Low low level alarm 68-LALL-1310 in Deaerator executes the following actions:
•
•
Boiler 6848-A-02A fuel gas inlet ON/OFF valve 68-XV-1302 close
•
Boiler 6848-A-02B fuel gas inlet ON/OFF valve 68-XV-1303 close
•
Boiler 6848-A-02C fuel gas inlet ON/OFF valve 68-XV-1304 close
•
BFW Pumps 6834-P-22A/B/C trip
•
De-aerator Feed Pumps 6834-P-20A/B trip
•
Steam Condensate Cooler Fans 6834-EM-2A1/2A2/2B1/2B2/2C1/2C2 trip
•
Boilers 6848-A-02A/B/C shutdown
68-LV-1302 closes on instrument air failure.
4.12.3.5 Boiler Feed Water Pumps Minimum Flow Control
Boiler Feed Water Pumps 6834-P-22A/B/C discharge flow to the Steam Generation
units is measured by 68-FT-1305 and minimum recirculation flow to Deaerator is
controlled by 68-FIC-1305.
The controller 68-FIC-1305 throttles the fail open control valve 68-FV-1305.
Controller
Tag
68-FIC-1305
Control Description
BFW Pumps minimum
flow
Alarm
Unit
Operating
Set Point
Low
High
m3/hr
35
30
NA
4.12.3.6 Deaerator Pressure Control
Deaerator 6834-A-08 pressure is monitored by 68-PT-1304 and controlled by the
pressure controller 68-PIC-1304. The pressure is maintained through the pressure
control valve 68-PV-1304 in the LP stripping steam inlet to the top of the Deaerator
tank.
68-PIC-1304 opens the steam control valve 68-PV-1304 on falling pressure in the
Deaerator.
Controller
Tag
68-PIC-1304
Control Description
De-aerator top pressure
control
Alarm
Unit
Operating
Set Point
Low
High
barg
0.2
NA
0.3
Steam control valve 68-PV-1304 closes on instrument air failure.
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4.13
4.13.1
STEAM GENERATION PACKAGE
Equipment Specifications
Equipment Tag No.
6848-A-02A/B/C
Water Tube Steam
Generator
Type
Capacity, T/hr (Each Boiler)
45
Design Pressure, barg
22
Design Temperature, °C
220
Steam Outlet Temperature at LP Header, °C
163
Feed Water Temperature, °C, Min./Normal
43/105
Saturated Steam Outlet Pressure at LP Header, barg
5
Steam Pressure at Drum, barg
16.4
Feed Water Pressure, barg
18.5
Feed Water Flow, T/hr
45.409
Desuperheater Water Flow, kg/hr
541
Type of Fuel
Natural Gas
3
Fuel Flow, Nm /hr
3296
Fuel Temperature, °C, (Operating/Design)
Fuel Pressure, barg, (Operating/Design)
Excess Air, %
25-50/100
6-7/9
10
3
Air Flow, Nm /hr
33860
Air Temperature at Air Heater Inlet, °C
25
Flue Gas Temperature at Furnace Outlet, °C
1037
Flue Gas Temperature at Economizer Inlet, °C
278
Flue Gas Temperature at Economizer Outlet, °C
157
Flue Gas Temperature at Stack, °C
157
Pressure Drop in Air Duct, mmWC
110
Air Pressure Drop in Burners, mmWC
160
Flue Gas Pressure Drop in Convection Coil, mmWC
67
Flue Gas Pressure Drop in Economizer, mmWC
42
Air Pressure at Fan Outlet, mmWC
364
Radiant Loss, %LHV
0.55
Unburned Loss, %LHV
0
Heat Loss in Flue Gas Stack, %LHV
4.72
Efficiency Calculated, (With Economizer), %LHV
93.49
Efficiency Calculated Without Drain, %LHV
93
Heat Introduced in Furnace, Kcal/h
27.2E6
2
269306
Heat Density in Furnace, Kcal/h.m
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Drums
Drum
Outside Diameter, mm
Cylindrical Length, mm
Thickness, mm
Material
Type of Head
Upper
1326
9550
28
SA 515 Gr 70
Elliptical
Lower
908
9550
22
SA 515 Gr 70
Elliptical
Combustion Chamber
Size, L X W X H, m
Type of Screen
Tubes Outer Diameter and Thickness, mm
Tube Fixation Type
Projected Surface, m2
Screen Header Numbers
Header Outer Diameter x Thickness, mm
8.787 X 2.727 X 3.778
Membrane Water Tube Type
76.1 x 4
Expanded/Welded
98.74
4
219.1 x 12.7
Desuperheater
Type
Location
Multi Nozzle Spray
Steam Pressure Reducing and
Desuperheating Station
Convection Coil
Surface, m2
Location
Type
Tubes Outer Diameter x Length, mm
Pitch Trans. x Length, mm
Material
729
Furnace Side/Parallel to
Drums
Expanded Tubes
51 x 3400
96 x 95
ASTM A 210 Gr A1
Economizer
Surface, m2
Location
Type
724
In the Flue Gas Duct
Finned Tube Type
Tubes Outer Diameter x Length, mm
48 x 2220
Pitch Trans. x Length, mm
114.3 x 90
Material
SA210GrA1
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Casing
Boiler Material/Thickness, mm
Insulation
CS
Mineral Wool with Cladding
Type
Expanded Tubes
Refractory, Combustion Chamber, Front Wall
Refractory Cement Bricks
Refractory, Combustion Chamber, Other Walls
Refractory Cement Bricks
Material
ASTM A 210 Gr A1
Burners
Number
1
Type
Low NOx
Location/Arrangement
Front Wall
Pilots or Igniters
1
Flame Failure Detector
2
Fan
Number
1
Type
Centrifugal
3
Air Flow Normal, Nm /hr
Static Pressure, mmWC
Driver
51000
500
Electric Motor
Driver Power, kW
110
Speed, RPM
1550
Coupling
Air Regulating
Material
Flexible Coupling
Inlet Damper
CS
Air Duct
Material
CS
Thickness, mm
4
Flue Gas
Discharge Flow Rate, kg/hr
46112.4
Discharge Temperature, °C
155
Molecular Weight
27.59
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Flue Gas Duct
Material
Thickness, mm
CS (Rated for High
Temperature Service)
6
Stack
Type
Height/Top Dia/Bottom Dia, m
Material
Thickness, mm, (min.)
Self Supporting
30/1/2
CS (Rated for High Temp.
Service)
5
Boiler Blow Down Pit
Tag No.
Dimension
Design Pressure, barg
6848-T-02
2200 x 1800 x 1000
0
Design Temperature, °C
220
Material of Construction
Concrete
4.13.2
Steam Generation Package Process Description
Auxiliary Steam Boiler Package is essentially constituted by: Three water tube –
Clajtub type saturated steam boilers.
4.13.2.1 Steam Generation Package 6848-A-02A
The main purpose of Steam Generation Package 6848-A-02A is to generate steam and
supply steam to the Customer steam network grid at the required pressure and
temperature.
4.13.2.1.1 Water/Steam Circuit
The Water/Steam circuit of the Steam Generator is realised in the following way:
•
Boiler Feed Water enters into the external Economiser (6848-E-01A), which is a
heat exchanger (water/flue gas) constituted by finned tubes. In this section, the
feed water temperature is increased by absorption of the flue gas thermal heat.
•
When Sour fuel gas is used, the Boiler Feed Water is first sent to a preheating
water circuit installed inside the water drum, before entering the Economiser
(6848-E-01A). This preheating circuit prevents acid condensation inside the flue
gas system (including the Economiser [6848-E-01A] outer surface) by keeping the
temperature of the flue gas above the dew point of the acid gas.
•
From the Economiser (6848-E-01A) outlet, the feed water enters into steam drum
6848-V-02A.
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•
Boiler functions on the basis of “steam/water natural circulation”, with
evaporating rising circuits formed by the hottest tubes of boiler. Remaining tubes
act as down comers, which feed the rising circuits. All the evaporating tubes are
(except, where indicated in the boiler pressure parts drawings) expanded on both
steam drum and water drum.
•
In the boiler evaporating tubes, a mixture of saturated water & steam is
produced. Then the saturated steam is separated from the water droplets in the
Steam Drum 6848-V-02A Separators.
•
The saturated steam from the steam drum is then sent to a temperature and
pressure controlling section;
•
Pressure of the saturated steam is controlled by the Pressure Control Valve 68-PV1524 which gets the input from the Pressure Indicator Controller 68-PIC-1819. A
pressure transmitter 68-PT-1819 senses the pressure in the steam header and
provides the input to the 68-PIC-1819.
•
The temperature of the saturated steam is controlled by the Desuperheater (6848X-03A). Boiler Feed Water from the Boiler Feed Water Pumps 6834-P-22A/B/C
discharge is injected into the Desuperheater 6848-X-03A. The flow of the Boiler
Feed Water is controlled by a Temperature control valve 68-TV-1522. The
temperature control valve gets the temperature input from 68-TIC-1522 which in
turn gets the input from the Temperature Transmitter 68-TT-1522 which measures
the temperature of the saturated steam.
•
The steam from the Desuperheater 6848-X-03A is then routed to the Main LP
steam header.
4.13.2.1.2 Air/Flue Gas Circuit
•
The air/flue gas ducts of each of the three steam generator is arranged in the
following way:
•
Combustion air is taken from the atmosphere by means of a Forced Draft Fan
(6848-K02A), driven by an electric motor (6848-KM-02A). At the suction the
combustion air passes through a Grid Filter 6848-S-03A, Sand Filter (6848-S-02A)
and vertical air Silencer (6848-X-06A) and then a goose type vertical duct designed
to have multiple stage inertial filtration of the entering combustion air. The inlet
Sand Filter 6848-S-02A does not need any kind of maintenance or cleaning (self
discharging type), goose neck type duct is advisable to be inspected through its
lower manhole at least once in 6 months
•
Downstream of the Silencer 6848-X-06A, the air passes through the modulating
inlet control damper (68-FV-1626) (pneumatically actuated); downstream of the
Forced Draft Fan 6848-K-02A, the combustion air passes through a duct that
delivers air to the wind-box
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•
Combustion air measuring device 68-FE-1526 (AIR-FOIL type) is installed
downstream of the Forced Draft Fan 6848-K-02A
•
In the wind box the air is evenly distributed to the burner in order to optimise the
combustion
•
Once the combustion takes place in the burner, the high temperature flue gases
pass through the boiler furnace, enclosed by water cooled tubes. The water tubes
assure a perfect tightness for the flue gases. At the end of combustion chamber,
the flue gases turn to 180° entering through the evaporating convective section.
The convective section is located on the right side of the furnace. At boiler outlet,
the flue gases go through a connection duct and then pass through the external
Economiser 6848-E-01A, where the flue gas temperature decreases by means of a
heat transfer to Boiler Feed Water
•
Downstream of the Economiser 6848-E-01A, the flue gases pass through flue gas
duct that connects the Economiser 6848-E-01A to the stack
•
Then the flue gases are discharged through the stack into the atmosphere
•
Air/flue gas circuit is provided also with a recirculation flue gas duct, that re
circulates flue gas from Economiser outlet to AIR FOIL 68-FE-1526 and
subsequently to burner wind-box inlet. The flue gas recirculation fan (FGRF)
6848-K-03A is installed in the Flue Gas Recirculation duct
4.13.2.1.3 Steam Generator Design & Process Main Data
The Steam Generator data are summarised in the following table. These data are
applicable to the Maximum operating Continuous Rate (MCR):
Operating Data @ MCR
Sl. #
Data
Unit
Value
Operating Data
1.
Steam flow at boiler outlet
t/h
44.96
2.
Steam flow at battery limit (net to
Customer)
t/h
45
3.
Steam temperature at battery limit
°C
163
4.
Steam pressure at battery limit
barg
5
5.
Feed water temperature
°C
105
Design Data
1.
Design pressure (boiler - economiser)
barg
22
2.
Hydraulic test pressure (boiler economiser)
barg
33
3.
Design Code
ASME I EDITION 2007
ADDENDA 2009
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4.13.2.1.4 Boiler Drums
•
The Water Drum 6848-V-03A and steam drum 6848-V-02A are symmetrically
located on right side of the boiler when viewed from the burner side
•
The drums are manufactured with high quality steel according to ASME Code with
submerged arc automatic welding
•
The drums are provided with manholes at both ends allowing a full inspection of
the boiler and accessibility to all tubes for easy maintenance
•
From the upper part of water drum all water tubes converge into the lower part of
the steam drum, ensuring the natural circulation
•
The Steam Drum 6848-V-02A is provided with internal Separators/Dryers, that
ensure a very high steam purity, flanged nozzles for continuous blow down (CBD)
outlet, Boiler Feed Water inlet, saturated steam outlet to common header, safety
valves, level indicators and transmitters, pressure gauges and pressure
transmitter, chemical injection inlet nozzle, nitrogen inlet and some spare
connections (provided with blind flanges)
•
The water drum is provided with two nozzles to drain the boiler (to be opened
only when the water inside the boiler is at ambient temperature)
4.13.2.1.5 Steam Drum
Sl. #
Data
Unit
Value
Steam Drum
1.
Internal diameter
mm
1270
2.
Shell thickness
mm
28
3.
Material
SA516 Gr.70
Water Drum
1.
Internal diameter
mm
864
2.
Shell thickness
mm
28
3.
Material
SA516 Gr.70
Note: Before closing the steam drum manholes, Operator must verify that demisters
are correctly installed inside the steam drum as shown in the following figure. That is
with the perforated plate positioned above the wire mesh filters.
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Fig. 23 - Steam Drum
4.13.2.1.6 Boiler Furnace
•
All the furnace walls are constituted by water-cooled membraned tubes. These
tubes are seamless type
•
The tubes constituting the “D” shape are directly connected to the drums by
mechanical expansion and seal welding. The front and rear wall tubes are welded
to dedicated lower and upper headers
•
The front tubes are bent to create the burners throats, while the rear tubes are
bent to allocate an inspection access door and two peep holes
•
The furnace dimensions are designed to assure an adequate cooling of the
combustion gases
•
All tubes of the furnace are equally shaped and its membranes are welded each
other to assure very high flue gas tightness and an equilibrated circulation of
boiling water
•
Lower and upper headers of front and rear wall tubes are connected to both drums
by external suppliers and risers tubes
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Sl. #
Data
Unit
Value
Furnace Tubes
1.
Outer diameter
mm
76.1
2.
Thickness
mm
4
3.
Material
ASTM A210 Gr.A1
Furnace Headers
1.
Outer diameter
mm
219.1
2.
Thickness
mm
12.7
3.
Material
ASTM A106 Gr.B
4.13.2.1.7 Evaporating Tube Bank
The evaporating tube bundle is located in the convective section, which is formed by
adequately spaced tubes, heated by the cross flow of flue gas.
The outer tubes, forming the external enveloping walls, are welded over the whole
length thus providing a continuous tight gas enclosure membraned wall.
A few tubes, in the enveloping external wall, have been bent in order to create the
free area to locate two inspection doors (one in SH bank and the other in the middle
of the convective section) for access and/or maintenance purposes.
Sl. #
Data
Unit
Value
Convective Bank Tubes
1.
Outer diameter
mm
51
2.
Thickness
mm
3.2
3.
Material
ASTM A210 Gr.A1
Enclosure Tubes
1.
Outer diameter
mm
76.1
2.
Thickness
mm
4
3.
Material
ASTM A210 Gr.A1
4.13.2.1.8 Economiser
•
At the outlet of the flue gas from the steam generator, an external Economiser
6848-E-01A is located
•
This thermal heat exchanger consists of seamless tubes adequately finned and
spaced so as to increase heat transfer coefficient
•
The flue gas heats the economizer tubes in cross flow
•
All the tubes are welded to the inlet and outlet horizontal headers. In order to
separate the feed water circuitry, some baffles are installed inside the inlet and
outlet headers
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•
A carbon steel casing, externally insulated, constitutes the enveloping economizer
enclosure
•
The Economiser 6848-E-01A is provided with adequate drain and vent valves. The
Economiser 6848-E-01A cannot be by-passed, so it is not necessary to provide a
dedicated pressure safety valve.
Sl. #
Data
Unit
Value
Economiser Tubes
1.
Outer diameter
mm
48.3
2.
Thickness
mm
3.2
3.
Material
ASTM A210 Gr.A1
Economiser Fins
1.
Height
mm
19
2.
Thickness
mm
1.5
3.
Number of fins per meter
4.
Material
200
Fe P04 UNI EN 10130
Economiser Headers
1.
Outer diameter
mm
114.3
2.
Thickness
mm
11.13
3.
Material
ASTM A106 Gr.B
4.13.2.1.9 Refractory
•
Refractory tiles are used to cover the furnace floor of the steam generator, both
to reduce the absorbed thermal heat (increasing the natural circulation) and to
allow future accessibility for any maintenance and/or inspection reasons
•
Refractory tiles are also used to protect the burner throats where combustion
takes place
•
These refractory tiles are manufactured with high Alumina content and are
suitable for high temperature operation.
4.13.2.1.10
External Insulation and Cladding
The steam generator is insulated with high-density mineral wool panels of suitable
thickness entirely applied to all external walls.
Sl. #
Data
Unit
Value
Boiler Thermal Insulation
1.
Material
2.
Thickness
3.
Density
Mineral wool
mm
140 (2 layers, 70 mm
each)
kg/m3
120
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The external insulation panels are enclosed in a cladding, made of painted aluminium,
properly spaced and fixed through screws to allow an easy removal.
4.13.2.1.11 Air and Flue Gas Ducts
•
The steam generator is provided with combustion air ducts, located at the suction
and at the delivery of the Forced Draft Fan 6848-K-02A that convey the
combustion air from ambient to boiler wind-box
•
The steam generator is provided also with flue gas ducts that convey the flue gas
from boiler outlet to Economiser 6848-E-01A inlet and from Economiser 6848-E01A outlet to steel stack
•
The steam generator is provided also with recirculation flue gas ducts, located at
the suction and at the delivery of the Flue Gas Recirculation Fan 6848-6848-K-03A
that re-circulates the required flow rate of flue gas from Economiser 6848-E-01A
outlet to Boiler wind-box inlet through a dedicated entrance in Air-Foil 68-FE-1526
duct
Sl. #
Data
Unit
Value
Combustion Air Ducts
1.
Material
S275 JR EN 10025
2.
Thickness (all air ducts except intake
air duct)
mm
4
3.
Thickness (intake air duct)
mm
7
Flue Gas and Flue Gas Recirculation Ducts
1.
Material
2.
Thickness
S275 JR EN 10025
mm
5
Boiler Base Frame
The steam generator body is mounted on a steel base-frame, which supports it with a
uniform load distribution.
Ladders, Platforms and Stairways
The Boiler, the Deaerator, the Stack and the air intake duct are provided with stairs,
platforms and ladders in order to allow an easy access to the equipment and/or to the
instruments installed on the equipments.
Platforms area is completed with open grating, guards and handrails.
Burners
•
One burner 6848-X-05A is installed in the Steam Generator, designed to burn both
Sour type and Sweet type (FG2 and FG1) of fuel gas
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•
Burner is designed to have a turndown of 10:1
•
Burner is provided with a pilot (Class 3 type) that can be fed by FG2 and FG1
•
The pilot ignitor is of high energy type
•
During pilot operation, the combustion air to pilot is provided by the Forced Draft
Fan 6848-K-02A, providing the minimum combustion air flow rate
•
In order to meet the specified low emissions target, at high boiler load, the
burners can be operated in flue gas recirculation mode. The combustion air is
mixed with a proper flue gas flow rate (about 15% of nominal flow rate), upstream
of the boiler wind-box. The recirculation flue gas flow rate is provided by the Flue
Gas Recirculation Fan 6848-K-03A
The burner is mainly composed of the following equipment:
•
Air swirler adjustable manually by Operator from external burner front, by means
of proper handle. The air register deliver the combustion air at the desired
velocity and rotation into the burner throat
•
Burner front plate assembly complete with one viewing port and two openings for
flame detectors (complete with ball swivels)
•
FG distribution system, complete with multiple gas lances and relevant nozzles
•
Central gas gun, complete with diffuser
•
One pilot complete with high energy ignitor, relevant transformer (installed in a
dedicated junction box) and cable
•
Two flame detectors both to sense the burner main flame and the pilot flame
•
One observation peep hole
•
Burner refractory throat made of several pre formed bricks
•
Flexible hoses for FG both for pilot, distribution system to gas lances and central
gas gun
During boiler operation, in order to optimise the combustion, the FG flow rate is fed
both to distribution system to multiple gas lances and to central gas gun.
Forced Draft Air Fan (6848-K-02A)
The Steam Generator is provided with one Forced Draft Air Fan (6848-K-02A) and its
electric motor 6848-KM-02A.
The combustion air flow rate is controlled by means of a modulating inlet control
damper (pneumatically actuated) installed upstream of the Forced Draft Air Fan
(6848-K-02A) suction.
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The unit basically includes:
•
Grid Filter 6848-S-03A at inlet duct (installed at inlet section of the air intake
duct)
•
Sand Filter 6848-S-02A at inlet duct (installed at inlet section of the air intake
duct)
•
Combustion air Silencer 6848-X-06A (installed after Sand Filter 6848-S-02A)
•
Split housing (for rotor removal) provided with one inspection door and one
plugged drain
•
Impeller (wheel and hub) statically and dynamically balanced in the manufacturer
workshop to reduce vibration and noise
•
Shaft and relevant guard
•
Shaft seal
•
Flexible coupling and relevant guard
•
Anti-friction bearings
•
Electric motor 6848-KM-02A
•
Inlet vane control damper 6848-FV-1626 complete with pneumatic actuator
•
Thermal insulation on fan casing
•
flexible connections at suction and discharge sections
•
basement common for fan and electric motor
Flue Gas Recirculation Fan
The Steam Generator is provided with one Flue Gas Recirculation Fan (FGRF) 6848-K03A, coupled with its electric motor 6848-KM-03A.
The flue gas recirculation flow rate is controlled by means of a modulating inlet
control damper 6848-FV-1524 (pneumatically actuated), installed upstream of the Flue
Gas Recirculation Fan 6848-K-03A suction connection.
The unit basically includes:
•
Housing, provided with one inspection door and one drain
•
Impeller (wheel and hub), statically and dynamically balanced in the manufacturer
workshop to reduce vibration and noise
•
Shaft and relevant guard
•
Shaft seal
•
Transmission belts and pulley and relevant guard
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•
Anti-friction bearings
•
Electric motor 6848-KM-03A
•
Inlet vane control damper 6848-FV-1524, complete with pneumatic actuator
•
Outlet non return damper
•
Flexible connections, at suction and discharge sections
•
Thermal insulation on fan casing
•
Basement, common for fan and electric motor
Chemical Dosing Units
Each Steam Generator is provided with one Phosphate chemical dosing unit, whose
purpose is to inject Phosphate into boiler Steam Drum 6848-V-02A.
Each unit basically includes:
•
One Phosphate Storage Tank 6848-T-03A
•
Two Phosphate Dosing Pumps 6848-P-01A/02A, one working and the other stand-by
and respective electric motors 6848-PM-01A/02A, piping, valves and instruments
•
One tank mixer 6848-M-01A and its electric motor 6848-MM-01A
•
One steel catch basin
Sampling System
•
Each Steam Generator is provided with one sampling system for two samples: one
for boiler feed water at Economiser 6848-E-01A inlet, one for saturated steam
•
The sampling system consists of sample conditioning bench, relevant piping,
measurement and safety instruments, all mounted on a common panel
•
All samplings are manual type sample
•
All the samples of the sampling system are cooled by Demineralised Water. The
required cooling water flow rate is taken from raw water line supply.
Stack
•
Each Steam Generator is provided with a double dedicated steel stack 6848-X-01A,
that discharges the flue gas from boiler to the atmosphere
•
The stack is cylindrical self-supporting type, manufactured into three sections for
shipping reasons
•
Each section is connected to the other by means of coupling flanges
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The stack has the following characteristics:
Sl. #
Data
Unit
Value
Steel Stack 6848-X-01A
1.
Material
S275 JR
2.
Internal Diameter
Mm
1240
3.
Outer Diameter
Mm
1700 till 11.45m
1500 up to top
4.
Thickness (Inner Duct)
Mm
8
5.
Thickness (Outer Duct)
Mm
8
6.
Total Height
M
30
•
The Stack 6848-X-01A is provided with proper insulation between the two jackets
•
Platform is provided at 6 m and 12 m elevation and ladders are provided for
approaching the platforms
•
A manhole is provided at the bottom of the Stack for internal inspection
•
The Stack 6848-X-01A is also provided with nozzles necessary for instruments
installation including CEMS installation
•
A drain is provided at the bottom of the Stack
•
An internal plate conveys the possible condensate (from flue gas condensation or
external atmospheric events) to the drain system
•
This drain must be periodically opened to empty the stack of any condensate
accumulation
Steam Silencer
Each Steam Generator is provided with one Steam Silencer 6848-X-02A for start-up
vent in order to respect the required noise limit.
4.13.3
Control Description
The Steam Generator is provided with a Boiler Control Panel containing the Burner
Management System (BMS) and the Boiler Control System (BCS).
The Steam Generator is provided with its own Local Panel (LP) connected to the Boiler
Control Panel.
Boiler control system (BCS) is responsible for the continuous control of the boilers and
all the below mentioned controls are implemented in BCS (PLC).
4.13.3.1 Boiler Level Control
The boiler level control is performed with single or three elements philosophy.
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If the steam flow (68-FT-1524) is greater than the settable threshold then the boiler
level control is allowed to work in three element controls.
If the steam flow (68-FT-1524) is less than the settable threshold then the boiler level
control is allowed to work in single element behaviour.
But there is also a provision to select three element controls at any time.
Single Element Control
When the single element philosophy is active the Inverse acting level controller 68-LIC1522 regulates the feed water flow control valve 68-LV-1522 to maintain the boiler
level.
The boiler drum level is measured by 68-LIT-1522 and controlled by 68-LIC-1522; set
point is set locally and 0-100% output of 68-LIC-1522 directly controls the level control
valve 68-LV-1522.
Three Element Control
Three elements used in this controls are Feed water flow (68-FT-1522), boiler level
(68-LT-1522) and steam flow (68-FT-1524).
When the three element philosophy is active the Inverse acting feed water flow
controller 68-FIC-1522 regulates the feed water flow control valve 68-LV-1522 to
maintain the boiler drum level.
The main compensated steam flow 68-FT-1524 is applied to the output of the level
controller 68-LIC-1522 to adjust the set point to the feed water control 68-FIC-1522
proportional to varying steam demands.
0-100% output of 68-FIC-1522 directly commands the level control valve 68-LV-1522.
Controller
68-LIC-1522
68-FIC-1522
Alarm
Unit
Operating
Set point
Low
High
Boiler drum level
%
50
34
62
Boiler Feed Water flow
3
XX
NA
NA
Control Loop
m /hr
High high level alarm (68-LAHH-1523A/B/C) set at 72% and low low level alarm
(68-LALL-1523A/B/C) set at 23% in boiler drum.
1. Closes the following valves:
2.
•
Main fuel gas shutoff valves 68-XV-1528 & 68-XV-1529
•
Pilot gas shut off valves 68-XV-1531 & 68-XV-1532
Opens the following valves:
•
Main fuel gas vent valve 68-XV-1530
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•
3.
Pilot gas venting valve 68-XV-1533
Trips the following:
•
FD fan 6848-K-01A
•
Re-circulation Glue Gas Fan 6848-K-02A
•
Boiler feed water level control valve 68-LV-1522 closes on instrument air
failure.
Schematic diagram of level control is shown below.
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Fig. 24 – Schematic of Boiler 1 Element/3 Element Drum Level
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4.13.3.2 SH Steam Temperature Control
Super heated steam temperature control is achieved by direct acting temperature
controller 68-TIC-1552 which regulates the water flow to the Desuperheater.
SH steam temperature is controlled by 68-TIC-1522. Set point of 68-TIC-1522 set by
operator on the HMI and is corrected by output of LP steam header direct acting
temperature controller 68-TIC-1820 and commands the Desuperheater control valve
68-TV-1522.
Controller
Tag.
Control Loop
Alarm
Unit
Operating
Set Point
Low
High
68-TIC-1522
SH steam temperature
°C
163
158
168
68-TIC-1820
Steam header
°C
XX
158
168
•
Desuperheater control valve 68-TV-1522 closes on instrument air failure
4.13.3.3 Boiler Steam Pressure Control
The Steam Drum 6848-V-02A pressure is maintained by inverse acting pressure
controller 68-PIC-1523A which determines the burner load to maintain the drum
pressure.
Boiler drum steam pressure is measured by 68-PT-1523 which is fed as a Process
variable to 68-PIC-1523A and the set point is set by operator on the HMI. 0-100% CV of
the controller 68-PIC-1523A is the power that burner should produce to maintain the
steam pressure to the set point value. The required power is expressed as
MWreq=CV*Pmax [MW]
Where
Pmax–maximum power that can be produced with the burner lighted at the maximum
load (set by the supplier).
Controller
68-PIC-1523A
•
Alarm
Control Loop
Unit
Operating
Set Point
Low
High
Boiler drum pressure
bar
16.4
19
20
High high steam pressure alarm (68-PAHH-1522A/B/C) in Boiler Drum
1.
Closes the following valves:
•
Main fuel gas shutoff valves 68-XV-1528 & 68-XV-1529
•
Pilot gas shut off valves 68-XV-1531 & 68-XV-1532
2. Opens the following valves:
•
Main fuel gas vent valve 68-XV-1530
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•
Pilot gas venting valve 68-XV-1533
3. Trips the following:
•
FD Fan 6848-K-01A
•
Re-circulation Flue Gas Fan 6848-K-02A
4.13.3.4 Fuel Gas Flow Control
Fuel gas flow to produce the required power MWreq is determined by the Inverse
acting flow controller 68-FIC-1525.
Fuel gas flow is measured by the transmitter 68-FT-1525A and controlled by 68-FIC1525.
Set point is the required FG flow, which is calculated from the formula
QNG REQ =min {3.6 *106 * MWREQ/HVFG, QFG STOICH} [kg/h],
Where
HVFG [kJ/kg] - Fuel gas heat value
QFG STOICH - stoichiometric fuel gas flow required for actual combustion air flow.
MWREQ- Required power for the burner is calculated from steam pressure controller
68-PIC-1523A.
Output (0-100%) of 68-FIC-1525 directly commands the fuel gas control valve
68-FV-1525.
68-FIC-1525 is turned on to manual mode after 5 seconds the 68-FIC-1526 (combustion
air flow controller) has been turned on manual mode.
Controller
68-FIC-1525
Control Loop
Fuel gas flow to boiler
Alarm
Unit
Operating
Set Point
High 1
High 2
kg/hr
XX
2800
2900
High high-1 flow alarm (68-FAHH-1525B/C/D) set at 2900 Kg/hr and high high-2 flow
alarm (68-FAHH-1525 B/C/D) set at 3020 Kg/hr in boiler
1.
2.
Closes the following valves:
•
Main fuel gas shutoff valves 68-XV-1528 & 68-XV-1529.
•
Pilot gas shut off valves 68-XV-1531 & 68-XV-1532.
Opens the following valves:
•
Main fuel gas vent valve 68-XV-1530.
•
Pilot gas venting valve 68-XV-1533.
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3.
Trips the following:
•
FD fan 6848-K-01A.
•
Re-circulation Flue Gas Fan 6848-K-02A
Fuel gas flow control valve 68-FV-1525 to boiler closes on instrument air failure.
4.13.3.5 Combustion Air Flow Control
Combustion air flow required to burn the amount of fuel gas is determined by the
Inverse acting air flow controller 68-FIC-1526.
Combustion air flow is measured from the transmitter 68-FT-1526A and controlled by
68-FIC-1526; the set point is determined by the formula
QAIR REQ = (QFG * STOICH) [kg/h],
Where
QFG =max {QFG req, QFG meas} [kg/h],
STOICH [KG/KG]-Air/FG stoichiometric ratio.
QFG req is calculated from the fuel gas controller set point 68-FIC-1525 and QFG mean
value is taken from the fuel gas flow transmitter 68-FIT-1525.
O2 correction calculated from 68-AIC-1522 is also applied for adjusting airflow set
point.
Output (0-100%) of 68-FIC-1526B directly commands the air control damper
68-FV-1526.
68-FIC-1526 is turned on to manual mode after 5 seconds the 68-FIC-1525A (fuel gas
flow controller) has been turned on manual mode.
Controller
68-FIC-1526
Control Loop
Combustion air flow to
boiler
Alarm
Unit
Operating
Set Point
Low
High
kg/hr
XX
NA
NA
•
Low low combustion air flow alarm (68-FALL-1525 B/C/D) set at 38,500 Kg/hr in
boiler
1.
Closes the following valves:
2.
•
Main fuel gas shutoff valves 68-XV-1528 & 68-XV-1529.
•
Pilot gas shut off valves 68-XV-1531 & 68-XV-1532.
Opens the following valves:
•
Main fuel gas vent valve 68-XV-1530.
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•
3.
•
Pilot gas venting valve 68-XV-1533.
Trips the following:
•
FD Fan 6848-K-01A
•
Re-circulation Flue Gas Fan 6848-K-02A
combustion air flow control valve 68-FV-1525 to boiler locks at the position on
instrument air failure
4.13.3.6 Oxygen Control
Oxygen concentration in the stack flue gas is maintained by the Inverse acting oxygen
controller 68-AIC-1522 which determines the increase/decrease factor of the excess
air which is used in the set point determination of 68- FIC-1526B (combustion air flow).
Set point is determined by the expected oxygen for the required load MW REQ and is
obtained by linear interpolation on the oxygen curve (provided by BONO).
Output (0-100%) of 68-AIC-1522 is scaled to the range 1.3 – 0.7 which is the correction
factor applied to the air excess in the calculation of the combustion air flow set point
(68-FIC-1526B).
Above control can be disabled/enabled from the HMI as required.
Controller
68-AIC-1522
Alarm
Control Loop
Unit
Operating
Set Point
Low
High
Oxygen analyzer controller
%
XX
2.2
6.7
4.13.3.7 Flue Gas Recirculation Control
The position of the flue gas recirculation damper 68-FV-1524 is measured by 68-FZT1524 and controlled by controller 68-ZIC-1524.
Set point is the desired position of the flue gas damper for the required load and is
obtained by linear interpolation on the flue gas recirculation curve (provided by
BONO).
Output (0-100%) of 68-ZIC-1524 directly commands the flue gas recirculation damper
68-FV-1524.
Flue gas control can be enabled/disabled by operator by means of software selector on
local HMI and on remote DCS.
Controller
68-ZIC-1524
Control Loop
Flue gas damper position
controller
Alarm
Unit
Operating
Set Point
Low
High
%
XX
NA
NA
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Flue gas flow control valve 68-FV-1524 to boiler locks at the position on instrument air
failure.
4.13.3.8 Boiler Steam Pressure (VENT) Control
Saturated steam flow through the vent valve to maintain the boiler steam pressure is
controlled by a direct acting pressure controller 68-PIC-1523B.
Steam drum pressure transmitter 68-PIT-1523; Set point is provided by the operator on
the HMI and output (0-100%) directly commands the vent control valve 68-PV-1523.
If the boiler steam pressure increases then the controller 68-PIC-1523B increases the
output to open the vent control valve 68-PV-1523, which maintains the steam pressure
nearer to the set value.
68-PIC-1523B
Alarm
Control Loop
Unit
Operating
Set Point
Low
High
Steam pressure vent
bar
17.4
NA
NA
Controller
•
High high steam pressure alarm (68-PAHH-1522A/B/C) set at 20barg in boiler drum
1.
Closes the following valves:
2.
3.
•
Main fuel gas shutoff valves 68-XV-1528 & 68-XV-1529.
•
Pilot gas shut off valves 68-XV-1531 & 68-XV-1532.
Opens the following valves:
•
Main fuel gas vent valve 68-XV-1530.
•
Pilot gas venting valve 68-XV-1533.
Trips the following:
•
FD Fan 6848-K-01A
•
Re-circulation Flue Gases Fan 6848-K-02A
•
Steam pressure vent control valve 68-PV-1523 closes on instrument air failure.
4.13.3.9 Header Steam Pressure Control
The three boilers supplied by BONO are connected via an Ethernet link and exchange
the data themselves to co-operate on MASTER/SLAVE logic to maintain the desired
pressure in the steam header. As per design only two boilers can feed the steam to the
header continuously.
Each boiler generates a signal named “consent to modulation for header PIC” and this
signal is set when the following conditions are verified:
•
Burner is lighted
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•
68-MOV-1522 located in super heated steam to LP steam header is not closed
•
The boiler pressure has reached the opening threshold for the 68-MOV-1522
•
At least one of the other two boiler control systems has not set the signal
“consent to modulation for header PIC”.
Header steam pressure direct acting controller 68-PIC-1819 purpose is to maintain the
steam header pressure and management is performed by the control system of the
“MASTER” boiler (first boiler which starts to feed the header through its 68-MOV-1522).
Steam header pressure is measured by 68-PIT-1819 and controlled by 68-PIC-1819, set
point is provided by the operator on the HMI of the “MASTER” boiler.
Output of the controller (0-100%) pass through the split range function 68-PY-1819,
where the two outputs of the split range function commands directly the header
pressure control valve 68-PV-1524 of the “MASTER”, “SLAVE” boilers (second boiler
which starts to feed the header through its 68-MOV-1522 is known as slave boiler) and
the commands of 68-PV-1523 to the third boiler is forced to 0%.
4.13.3.10
Fan Controls
Forced Draft Fan (6848-K-02A)
The FD Fan motor can be started only if all the following conditions are verified:
•
Presence of motor available signal (68-ZL-1548)
•
Absence of motor fault signal (68-ZA-1548)
•
Presence of close limit switch of combustion air damper 68-FV-1526 (68-ZSC-1526)
Fan motor can be started and stopped manually from the HMI.
Flue Gas Recirculation Fan (6848-K-03A)
The flue gas recirculation fan motor can be started only if all the following conditions
are verified:
•
Presence of motor available signal (68-ZL-1549)
•
Absence of motor fault signal (68-ZA-1549)
•
Presence of close limit switch of the flue air damper 68-FV-1524 (68-ZSC-1524)
Fan motor can be started and stopped manually from the HMI.
Start/stop tag details for Forced draft and recirculation fans are as follows:
Sl. #
Tag No.
Description
1.
68-HSOA-1548
Forced draft fan start
2.
68-HSCA-1548
Forced draft fan stop
3.
68-HSOA-1549
Recirculation air fan start
4.
68-HSCA-1549
Recirculation air fan stop
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4.13.3.11
Valve Management
ON/OFF MOV1522
Each boiler contains a MOV which feeds the steam to the header
Valve can be operated in Local/Remote by changing the selecting switch (68-HSR1522C) located in the local panel.
If the valve fault status signal (68-XA-1522) is active then the valve cannot be
controlled from BCS.
Automatic Mode
Automatic mode of the MOV can be selected from the HMI and if the valve is not in
fault mode then the valve will open automatically on the following conditions:
•
Burner is ON
•
Steam Drum pressure 68-PT-1523 is higher than threshold (68-PSH-1523C)
•
other two boilers have not yet set the consent to modulation for header PIC signal
If any of the above condition is not satisfied then the valve will close automatically.
Manual Mode
When the manual mode of MOV is selected from HMI then the valve can only be
operated from the HMI open/close commands (68-HSO-1522A/68-HSC-1522B).
On/Off Valve Controls
Boiler Blow Down Valve (68-XV-1525)
The valve is opened automatically if at least any one of the following conditions is
satisfied:
•
The burner is ON
•
Hot standby mode is active (enabled manually) and the boiler level is higher than
a opening threshold value
The valve is closed automatically if at least any one of the following conditions is
satisfied:
•
The burner is off
•
Hot standby mode is not active
•
Hot standby mode is active and the boiler level is lower than a closure threshold
value
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Hot Stand-by Boiler Pressure Valve (68-XV-1523)
The valve is opened automatically when all the following conditions are satisfied:
•
Hot standby mode is active
•
The Steam Drum pressure 68-PT-1523 is lower than an opening threshold
(PSL-1523)
The valve is closed automatically if at least any one of the following conditions is
satisfied:
•
Hot standby mode is not active
•
Hot standby mode is active and the upper drum boiler pressure 68-PT-1523 is
higher than a closure threshold (PSH-1523)
Pre heating Feed Water Valves (68-XV-1523, 68- XV-1524)
For commanding the above valves to permit feed water to boiler lower drum,
following conditions needs to be satisfied:
•
Burner is OFF
•
Operator has selected FG2 (H2S) from the HMI
4.13.3.12
LP Steam Header Pressure Control
Saturated steam from all the three boiler packages are connected in to the LP steam
header and the pressure in the header is measured by 68-PT-1306 and controlled by
the pressure controller 68-PIC-1306. Pressure in the header is maintained by the
control valve 68-PV-1306 located in the steam vent line to atmosphere.
Increase of pressure above the operating range will route the steam to the vent
through the control valve 68-PV-1306.
•
Alarm
Controller
Tag
Control Description
Unit
Operating
Set Point
Low
High
68-PIC-1306
LP steam header pressure
barg
5
4.5
5.5
LP steam header pressure low low pressure 2oo3 (68-PALL-1303A/B/C) alarm set
at 4 barg initiates the following:
•
Fuel gas on/off valve 68-XV-1302 to the boiler 6848-A-02A close
•
Fuel gas on/off valve 68-XV-1303 to the boiler 6848-A-02B close
•
Fuel gas on/off valve 68-XV-1304 to the boiler 6848-A-02C close
•
Deaerator Feed Pumps 6834-P-20A/B trip
•
BFW Pumps 6834-22A/B/C trip
•
Steam Condensate Cooler Fans trip
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•
•
4.14
4.14.1
Boiler Packages 6848-A-02A/B/C shutdown
Steam to vent valve 68-PV-1306 opens on instrument air failure
CHEMICAL INJECTION SYSTEMS
Antifoam Injection Package 9103-A-11
4.14.1.1 Equipment Specification
Antifoam Storage Tank
Equipment Tag No.
9103-T-12
Size, ID/Height, mm
1550/1600
Chemical
Antifoam
Design Pressure bar(a)
1.01
Design Temperature °C
85/0
Operating Pressure bar(g)
ATM.
Operating Temperature, °C
Material of Construction
52
AISI 316L
Antifoam Injection Pumps
Equipment Tag No.
Pump Type
Chemical
9103-P-16A/B
Double Diaphragm
Antifoam
Capacity, L/hr
55
Design Pressure, bar(g)
12
Discharge Pressure, bar(g)
8.5
Design Temperature, °C
120/0
Driver Type
Motor
Rated Power, kW
Material of Construction
0.37
SS316TI/PTFE
Antifoam Unloading Pump
Equipment Tag No.
Pump Type
Chemical
Capacity, L/hr
9103-P-19
Air Operated Pump
Antifoam
2000
Design Pressure, bar(g)
8.7
Discharge Pressure, bar(g)
1.2
Design Temperature, °C
85/0
Material of Construction
AISI 316L
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Antifoam Tank Agitator
Equipment Tag No.
9103-M-12
Speed, RPM
155
Driver Rating, kW
0.37
Material of Construction
AISI 316L6
4.14.1.2 Antifoam Package 9103-A-11 Description
Antifoam Package consists of an Antifoam Storage Tank 9103-T-12 and two numbers of
Antifoam Injection Pumps 9103-P-16A/B.
The Antifoam Storage Tank 9103-T-12 is having an agitator 9103-M-12. Antifoam from
drums are transferred to the tank through an unloading pump 9103-P-19.
The Antifoam Injection Pumps 9103-P-16A/B are having discharge pulsation dampner
and calibration pots at the suction line.
4.14.1.3 Antifoam Injection Package Control Description
The Antifoam Storage Tank (9103-T-12) level is monitored by 91-LI-1521 and antifoam
from the storage tanks is injected to the following areas via the injection pumps
(9103-P-16A/B):
•
Acid Gas Amine Absorber 9103-C-11
•
Lean/Rich Amine Exchangers 9103-E-11A/B
•
Amine Regenerator 9103-C-12
•
Tail Gas Amine Absorber 9102-C-12
Following parameters are to be monitored:
Tag No.
Description
Unit
91-FI-1533
9103-P-16A/B common discharge flow
91-PI-1559
Alarm
High
Low
LPH
40
70
9103-P-16A discharge pressure
barg
NA
9.5
91-PI-1560
9103-P-16B discharge pressure
barg
NA
9.5
91-LI-1521
antifoam storage tank level (9103-T12)
%
6
NA
Following are the details of the switches & alarm related to motor controls:
Tag No.
Description
91-HSOA-1582
Remote “ START” for the Pump 9103-P-16A
91-HSOA-1583
Remote “ START” for the Pump 9103-P-16B
91-HSCA-1582
Remote “ STOP” for the Pump 9103-P-16A
91-HSCA-1583
Remote “ STOP” for the Pump 9103-P-16B
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Tag No.
4.14.2
Description
91-ZL-1582
9103-P-16A Pump Available signal
91-ZL-1583
9103-P-16B Pump Available signal
91-XS-1582
9103-P-16A Pump ESD trip signal
91-XS-1583
9103-P-16B Pump ESD trip signal
91-ZI-1582
9103-P-16A Pump running indication
91-ZI-1583
9103-P-16B Pump running indication
•
Low low level alarm (91-LALL-1520) set at 3% in Antifoam Storage Tank 9103-T-12
trips the Antifoam Injection Pumps (9103-P-16A/B)
•
High high diaphragm pressure alarm (91-PAHH-1565) set at 8.5 barg in Antifoam
Injection Pump 9103-P-16A initiates the pump changeover
•
High high diaphragm pressure alarm (91-PAHH-1566) set at 8.5 barg in Antifoam
Injection Pump 9103-P-16B initiates the pump changeover
•
ESD-0, ESD-1, ESD-2 shutdown signals activates the tripping of both the Antifoam
Injection Pumps (9103-P-16A/B).
Caustic Injection Package 9103-A-13
4.14.2.1 Equipment Specification
Caustic Storage Tank
Equipment Tag No.
Size, ID/Height, mm
Chemical
Design Pressure bar(a)
Design Temperature °C
Operating Pressure bar(g)
Operating Temperature, °C
Material of Construction
9103-T-14
1550/1600
Caustic
1.01
85/0
ATM.
52/0
AISI 316L
Caustic Injection Pumps
Equipment Tag No.
Pump Type
Chemical
Capacity, L/hr
Design Pressure, bar(g)
Discharge Pressure, bar(g)
Design Temperature, °C
Driver Type
Rated Power, kW
Material of Construction
9103-P-103A/B
Double Diaphragm
Caustic
55
11.5
5
120/0
Motor
0.37
SS316TI/PTFE
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Caustic Unloading Pump
Equipment Tag No.
9103-P-104
Pump Type
Air Operated Pump
Chemical
Caustic
Capacity, L/hr
2000
Design Pressure, bar(g)
8.7
Discharge Pressure, bar(g)
1.2
Design Temperature, °C
85/0
Material of Construction
AISI 316L
Caustic Tank Agitator
Equipment Tag No.
9103-M-14
Chemical
Caustic
Speed, RPM
155
Material of Construction
AISI 316L
4.14.2.2 Caustic Package 9103-A-13 Description
Caustic is injected to the suction of Desuperheater Circulation Pumps 9102-P-11.
Caustic Package consists of a Caustic Storage Tank 9103-T-14 and two numbers of
Caustic Injection Pumps 9103-P-103A/B.
The Caustic Storage Tank 9103-T-14 is having an agitator 9103-M-14. Caustic from
drums are transferred to the tank through an unloading pump 9103-P-104.
The Caustic Pumps 9103-P-103A/B are having discharge pulsation dampner and
calibration pots at the suction line.
4.14.2.3 Caustic Injection Package Control Description
Following parameters are to be monitored:
Tag No.
Description
Unit
91-FI-1535
9103-P-103A/B common discharge flow
91-PI-1563
Alarm
Low
High
LPH
40
70
9103-P-103A discharge pressure
barg
NA
7.5
91-PI-1564
9103-P-103B discharge pressure
barg
NA
7.5
91-LI-1525
caustic storage tank level (9103-T14)
%
6
NA
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Following are the details of the switches & alarm related to motor controls:
Tag No.
4.14.3
Description
91-HSOA-1586
Remote “ START” for the Pump 9103-P-103A
91-HSOA-1587
Remote “ START” for the Pump 9103-P-103B
91-HSCA-1586
Remote “ STOP” for the Pump 9103-P-103A
91-HSCA-1587
Remote “ STOP” for the Pump 9103-P-103B
91-ZL-1586
9103-P-103A Pump Available signal
91-ZL-1587
9103-P-103B Pump Available signal
91-XS-1586
9103-P-103A Pump ESD trip signal
91-XS-1587
9103-P-103B Pump ESD trip signal
91-ZI-1586
9103-P-103A Pump running indication
91-ZI-1587
9103-P-103B Pump running indication
•
Low low level alarm (91-LALL-1524) Set at 3% in caustic storage tank 9103-T-14
trips the Caustic Injection Pumps (9103-P-103A/B)
•
High high diaphragm pressure alarm (91-PAHH-1569) set at 5 barg in Caustic
Injection Pump 9103-P-103A initiates the pump changeover
•
High high diaphragm pressure alarm (91-PAHH-1570) set at 5 barg in Caustic
Injection Pump 9103-P-103B initiates the pump changeover
•
ESD-0, ESD-1, ESD-2 shutdown signals activates the tripping of both the Caustic
Injection Pumps (9103-P-103A/B)
Corrosion Inhibitor Injection Package 9103-A-12
4.14.3.1 Equipment Specification
Corrosion Inhibitor Storage Tank
Equipment Tag No.
9103-T-13
Size, ID/Height, mm
3
Storage Capacity m
Chemical
1550/1600
3
Corrosion Inhibitor
Design Pressure bar(a)
1.2
Design Temperature °C
85/0
Operating Pressure bar(g)
ATM.
Operating Temperature, °C
52/0
Material of Construction
SS 316L
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Corrosion Inhibitor Injection Pumps
Equipment Tag No.
9103-P-101A/B
Pump Type
Double Diaphragm
Chemical
Corrosion Inhibitor
Capacity, L/hr
55
Design Pressure, bar(g)
12
Discharge Pressure, bar(g)
8.5
Design Temperature, °C
85/0
Driver Type
Motor
Rated Power, kW
Material of Construction
0.37
SS 316TI/PTFE
Corrosion Inhibitor Unloading Pump
Equipment Tag No.
9103-P-102
Pump Type
Air Operated Pump
Chemical
Corrosion Inhibitor
Capacity, L/hr
2000
Design Pressure, bar(g)
8.7
Discharge Pressure, bar(g)
1.2
Design Temperature, °C
85/0
Material of Construction
AISI 316L
Corrosion Inhibitor Tank Agitator
Equipment Tag No.
9103-M-13
Speed, RPM
155
Rated Power, kW
0.37
Material of Construction
AISI 316L
4.14.3.2 Corrosion Inhibitor Package 9103-A-12 Description
Corrosion Inhibitor Package consists of a Corrosion Inhibitor Storage Tank 9103-T-13
and two numbers of Corrosion Inhibitor Injection Pumps 9103-P-101A/B.
The Corrosion Inhibitor Storage Tank 9103-T-13 is having an agitator 9103-M-13.
Corrosion Inhibitor from drums is transferred to the tank through an unloading pump
9103-P-102.
The Corrosion Inhibitor Pumps 9103-P-101A/B are having discharge pulsation dampner
and calibration pots at the suction line.
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4.14.3.3 Corrosion Inhibitor Injection Package Control Description
Following parameters are to be monitored:
Tag No.
Description
Unit
Alarm
Low
High
91-FI-1534
9103-P-101A/B common discharge
flow
LPH
40
70
91-PI-1561
9103-P-101A discharge pressure
barg
NA
9.5
91-PI-1562
9103-P-101B discharge pressure
barg
NA
9.5
91-LT-1523
corrosion inhibitor storage tank
%
6
NA
Following are the details of the switches & alarm related to motor controls:
Tag No.
Description
91-HSOA-1584
Remote “ START” for the Pump 9103-P-101A
91-HSOA-1585
Remote “ START” for the Pump 9103-P-101B
91-HSCA-1584
Remote “ STOP” for the Pump 9103-P-101A
91-HSCA-1585
Remote “ STOP” for the Pump 9103-P-101B
91-ZL-1584
9103-P-101A Pump Available signal
91-ZL-1585
9103-P-101B Pump Available signal
91-XS-1584
9103-P-101A Pump ESD trip signal
91-XS-1585
9103-P-101B Pump ESD trip signal
91-ZI-1584
9103-P-101A Pump running indication
91-ZI-1585
9103-P-101B Pump running indication
•
Low low level alarm 91-LALL-1523 set at 3 % in Corrosion Inhibitor Storage Tank
9103-T-13 trips the Corrosion Inhibitor Injection Pumps (9103-P-101A/B)
•
High high diaphragm pressure alarm 91-PAHH-1567 set at 8.5 barg in Corrosion
Inhibitor Injection Pump 9103-P-101A initiates the pump changeover
•
High high diaphragm pressure alarm 91-PAHH-1568 set at 8.5 barg in Corrosion
Inhibitor Injection Pump 9103-P-101B initiates the pump changeover
•
ESD-0, ESD-1, ESD-2 shutdown signals activates the tripping of both the Corrosion
Inhibitor Injection Pumps 9103-P-101A/B.
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TITLE: OPERATION AND MAINTENANCE MANUAL
4.14.4
Complex Product Injection Package 6834-A-09
4.14.4.1 Equipment Specification
Complex Product Storage Tank
Equipment Tag No.
6834-T-18
Size, ID/Height, mm
3
Storage Capacity m
Chemical
950/1500
1
Complex Product
Design Pressure bar(a)
1.01
Design Temperature °C
85/0
Operating Pressure bar(g)
ATM.
Operating Temperature, °C
52/0
Material of Construction
AISI 316L
Complex Product Injection Pumps
Equipment Tag No.
6834-P-41A/B
Pump Type
Double Diaphragm
Chemical
Complex Product
Capacity, L/hr
1.87
Design Pressure, bar(g)
31
Discharge Pressure, bar(g)
25
Design Temperature, °C
120/0
Driver Type
Motor
Rated Power, kW
Material of Construction
0.18
SS 316TI/PTFE
Complex Product Unloading Pump
Equipment Tag No.
Pump Type
Chemical
Capacity, L/hr
6834-P-42
Air Operated Pump
Complex Product
2000
Design Pressure, bar(g)
8.7
Discharge Pressure, bar(g)
1.2
Design Temperature, °C
85/0
Material of Construction
AISI 316L
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Complex Product Tank Agitator
Equipment Tag No.
6834-M-04
Speed, RPM
243
Rated Power, kW
0.25
Material of Construction
AISI 316L
4.14.4.2 Complex Product Injection Package Description
Complex Product Injection Package consists of a Complex Product Storage Tank
6834-T-18 and two numbers of Complex Product Injection Pumps 6834-P-41A/B.
The Complex Product Storage Tank 6834-T-18 is having an agitator 6834-M-04.
Complex Product from drums is transferred to the tank through an unloading pump
6834-P-42.
The Complex Product Injection Pumps 6834-P-41A/B are having discharge pulsation
dampner and calibration pots at the suction line.
4.14.4.3 Complex Product Injection Process control Description
The complex product is injected to the boiler feed water going to the steam
generation package and to the boiler feed water going to TGTU.
The control is achieved by maintaining the ratio between the total Boiler Feed Water
flow and Complex Product flow.
The Boiler Feed Water flow rate to Steam Generation Boiler A/B/C is measured by 68FT 1522, 68-FT-1622, 68-FT-1722 respectively and 68-FT-1304 measures the boiler feed
water flow rate to TGTU.
The Complex Product Pumps (6834-P-41A/B) common discharge flow rate is measured
by 68-FT-1311.
Total summation of all the above BFW flow is summated in the calculation block
68-FY-1304 and multiplied with the fixed ratio X (X=complex product/total BFW) in the
multiplication block 68-FFY-1311. The output from 68-FFY-1311 is fed as a set point to
the MASTER complex product flow controller 68-FIC-1311.
The complex product pumps 6834-P-41A/B stroke length (0-15 mm) is measured by the
stroke indicators 68-ZI-1303/1304 and the strokes are controlled by the position
controllers 68-ZIC-1303, 68-ZIC-1304.
Complex product flow controller 68-FIC-1311 is cascaded with the position controllers
68-ZIC-1303 and 68-ZIC-1304 and provides set point to the position controllers.
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Controller
Tag
Control Description
Alarm
Unit
Operating
Set Point
Low
High
L/hr
1.78
0.2
1.78
68-FIC-1311
Complex product flow control
68-ZIC-1303
6834-P-41A position control
%
100
NA
NA
68-ZIC-1304
6834-P-41B position control
%
100
NA
NA
The complex product injection pumps can be operated from the DCS when the Pumps
are selected to “Remote” at its local panel.
Following are the details of the switches & alarm related to motor controls:
Tag No.
Description
68-HSOA-1324
Remote “ START” for the Pump 6834-P-41A
68-HSOA-1332
Remote “ START” for the Pump 6834-P-41B
68-HSCA-1324
Remote “ STOP” for the Pump 6834-P-41A
68-HSCA-1332
Remote “ STOP” for the Pump 6834-P-41B
68-ZL-1324
6834-P-41A Pump Available signal
68-ZL-1332
6834-P-41B Pump Available signal
68-XS-1324
6834-P-41A Pump ESD trip signal
68-XS-1332
6834-P-41B Pump ESD trip signal
68-ZI-1324
6834-P-41A Pump running indication
68-ZI-1332
6834-P-41B Pump running indication
Following parameters are to be monitored
Tag No.
Description
Unit
Alarm
Low
High
68-PI-1318
6834-P-41A Pump discharge pressure
barg
NA
26.5
68-PI-1316
6834-P-41B Pump discharge pressure
barg
NA
26.5
68-LI-1317
Complex product storage tank
6834-T18 level
%
6
NA
•
Low low level alarm 68-LALL-1316 set at 3% in Complex Product Storage Tank trips
the Complex Product Injection Pumps 6834-P-41A/B
•
High high diaphragm pressure alarm 68-PAHH-1326 set at 25.0 barg in Complex
Product Injection Pump 6834-P-41A initiates the pump changeover
•
High high diaphragm pressure alarm 68-PAHH-1327 set at 25.0 barg in Complex
Product Injection Pump 6834-P-41B initiates the pump changeover
•
ESD-0, ESD-1, ESD-2 shutdown signals activates the tripping of both the Complex
Product Injection Pumps 6834-P-41A/B.
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TITLE: OPERATION AND MAINTENANCE MANUAL
4.14.5
Oxygen Scavenger Injection Package 6834-A-09
4.14.5.1 Equipment Specification
Oxygen Scavenger Storage Tank
Equipment Tag No.
6834-T-17
Size, ID/Height, mm
3
Storage Capacity m
Chemical
950/1500
1
Oxygen Scavenger
Design Pressure bar(a)
1.01
Design Temperature °C
85/0
Operating Pressure bar(g)
ATM.
Operating Temperature, °C
52/0
Material of Construction
AISI 316L
Oxygen Scavenging Injection Pumps
Equipment Tag No.
6834-P-39A/B
Pump Type
Double Diaphragm
Chemical
Oxygen Scavenger
Capacity, L/H
0.55
Design Pressure, bar(g)
10.5
Discharge Pressure, bar(g)
6.5
Design Temperature, °C
120/0
Driver Type
Motor
Rated Power, kW
Material of Construction
0.18
SS 316TI
Oxygen Scavenger Unloading Pump
Equipment Tag No.
6834-P-40
Pump Type
Air Operated Pump
Chemical
Oxygen Scavenger
Capacity, L/h
2000
Design Pressure, bar(g)
8.7
Discharge Pressure, bar(g)
1.2
Design Temperature, °C
85/0
Material of Construction
AISI 316L
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Oxygen Scavenger Tank Agitator
Equipment Tag No.
6834-M-03
Speed, RPM
243
Rated Power, kW
0.25
Material of Construction
AISI 316L
4.14.5.2 Oxygen Scavenger Injection Package Description
Oxygen Scavenger Injection Package consists of a Oxygen Scavenger Storage Tank
6834-T-17 and two numbers of Oxygen Scavenger Injection Pumps 6834-P-39A/B.
The Oxygen Scavenger Storage Tank 6834-T-17 is having an agitator 6834-M-03. Oxygen
Scavenger from drums is transferred to the tank through an unloading pump 6834-P-40
The Oxygen Scavenger Injection Pumps 6834-P-39A/B is provided with discharge
pulsation dampener and calibration pots at the suction line.
4.14.5.3 Oxygen Scavenging Injection Process control Description
The oxygen scavenger is injected directly in to the De-aerator package (6834-A-08)
and the flow rate of Oxygen Scavenger is measured by 68-FT-1310.
Oxygen Scavenger Injection Pumps 6834-P-39A, 6834-P-39B stroke length is measured
by 68-ZT-1301 and 68-ZT-1302 respectively. Stroke length of 6834-P-39A, 6834-P-39B is
manually adjusted by the controllers 68-HIC-1301 and 68-HIC-1302, respectively.
The Oxygen Scavenger Injection Pumps can be operated from the DCS when the Pumps
are selected to “Remote” at its local panel
Following are the details of the switches & alarm related to motor controls:
Tag No.
Description
68-HSOA-1323
Remote “ START” for the Pump 6834-P-39A
68-HSOA-1331
Remote “ START” for the Pump 6834-P-39B
68-HSCA-1323
Remote “ STOP” for the Pump 6834-P-39A
68-HSCA-1331
Remote “ STOP” for the Pump 6834-P-39B
68-ZL-1322
6834-P-39A Pump Available signal
68-ZL-1331
6834-P-39B Pump Available signal
68-XS-1322
6834-P-39A Pump ESD trip signal
68-XS-1331
6834-P-39B Pump ESD trip signal
68-ZI-1322
6834-P-39A Pump running indication
68-ZI-1331
6834-P-39B Pump running indication
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Following parameters are to be monitored:
Tag No.
4.14.6
Description
Alarm
Unit
Low
High
68-PI-1317
6834-P-39A Pump discharge pressure
barg
NA
8
68-PI-1315
6834-P-39B Pump discharge pressure
barg
NA
8
68-LI-1315
Oxygen Scavenger Storage Tank
6834-T-17 level
%
6
80
68-FI-1310
Oxygen Scavenger Injection flow rate
LPH
0.2
0.7
•
Low low level alarm 68-LALL-1314 set at 3 % in oxygen scavenger tank 6834-T-17
trips the Oxygen Scavenger Injection Pumps 6834-P-39A/B
•
High high diaphragm pressure alarm 68-PAHH-1324 set at 6.5 barg in Oxygen
Scavenger Injection Pump 6834-P-39A initiates the pump changeover
•
High high diaphragm pressure alarm 68-PAHH-1325 set at 6.5 barg in oxygen
scavenger Injection Pump 6834-P-39B initiates the pump changeover
•
ESD-0, ESD-1, ESD-2 shutdown signals activates the tripping of both the Oxygen
Scavenger Pumps 6834-P-39A/B.
Biocide Injection Package 6932-A-06
4.14.6.1 Equipment Specification
Biocide Storage Tank
Equipment Tag No.
6932-T-04
Size, ID/Height, mm
3
Storage Capacity m
Chemical
1300/2300
3
Biocide
Design Pressure bar(a)
1.01
Design Temperature °C
85/0
Operating Pressure bar(g)
ATM.
Operating Temperature, °C
52/0
Material of Construction
AISI 316L
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TITLE: OPERATION AND MAINTENANCE MANUAL
Biocide Injection Pumps
Equipment Tag No.
Pump Type
Chemical
Capacity, L/H
6932-P-07A/B
Double Diaphragm
Biocide
12/65/110
Design Pressure, bar(g)
10
Discharge Pressure, bar(g)
5.5
Design Temperature, °C
120/0
Driver Type
Motor
Rated Power, kW
Material of Construction
0.75
SS 316TI/PTFE
Biocide Unloading Pump
Equipment Tag No.
Pump Type
Chemical
Capacity, L/h
6932-P-08
Air Operated Pump
Biocide
2000
Design Pressure, bar(g)
8.7
Discharge Pressure, bar(g)
1.2
Design Temperature, °C
85/0
Material of Construction
AISI 316L
4.14.6.2 Biocide Injection Package Description
Biocide Injection Package consists of a Biocide Storage Tank 6932-T-04 and two
numbers of Biocide Injection Pumps 6932-P-07A/B.
Biocide from drums is transferred to the tank through an unloading pump 6932-P-08.
The Biocide Injection Pumps 6932-P-07A/B is provided with discharge pulsation
dampener and calibration pots at the suction line.
4.14.6.3 Biocide Injection Process control Description
The biocide storage tank 6932-T-04 level is measured by 69-LI-1328. Biocide from the
storage tank is injected to Sea Cooling Water through remote stroke adjusting pumps
(6932-P-07A/6932-P-07B).
Stroke lengths of 3 stage 6932-P-07A are measured by 69-ZT-1301, 69-ZT-1326 and
69-ZT-1328. Manual adjustment of stroke is done via the controllers 69-HIC-1301,
69-HIC-1326 and 69-HIC-1328.
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TITLE: OPERATION AND MAINTENANCE MANUAL
Stroke lengths of 3 stage 6932-P-07B are measured by 69-ZT-1302, 69-ZT-1327 and
69-ZT-1329. Manual adjustment of stroke is done via the controllers 69-HIC-1302,
69-HIC-1327 and 69-HIC-1329.
Following parameters are to be monitored:
Tag No.
Description
Unit
Alarm
Low
High
st
69-FI-1319
6932-P-07A/B 1 stage common
discharge flow
LPH
80
130
69-FI-1323
6932-P-07A/B 2nd stage common
discharge flow
LPH
80
130
69-FI-1324
6932-P-07A/B 3rd stage common
discharge flow
LPH
80
130
69-PI-1330
6932-P-07A 1st stage discharge pressure
barg
NA
6.5
69-PI-1340
stage discharge pressure
barg
NA
6.5
rd
6932-P-07A 3 stage discharge pressure
barg
NA
6.5
st
barg
NA
6.5
stage discharge pressure
barg
NA
6.5
69-PI-1343
6932-P-07B 3 stage discharge pressure
barg
NA
6.5
69-LI-1328
Biocide Storage Tank (6932-T-04) level
%
6
NA
69-PI-1342
69-PI-1331
69-PI-1341
6932-P-07A 2
nd
6932-P-07B 1 stage discharge pressure
6932-P-07B 2
nd
rd
The Biocide injection pumps can be operated from the DCS when the Pumps are
selected to “Remote” at its local panel.
Following are the details of the switches & alarm related to motor controls:
Tag No.
Description
69-HSOA-1352
Remote “ START” for the Pump 6932-P-07A
69-HSOA-1353
Remote “ START” for the Pump 6932-P-07B
69-HSCA-1352
Remote “ STOP” for the Pump 6932-P-07A
69-HSCA-1353
Remote “ STOP” for the Pump 6932-P-07B
69-ZL-1352
6932-P-39A Pump Available signal
69-ZL-1353
6932-P-39B Pump Available signal
69-XS-1352
6932-P-07A Pump ESD trip signal
69-XS-1353
6932-P-07B Pump ESD trip signal
69-ZI-1352
6932-P-07A Pump running indication
69-ZI-1353
6932-P-07B Pump running indication
•
Low low level alarm 69-LALL-1329 set at 10 % in biocide storage tank 6932-T-04
trips the Biocide Injection Pumps 6932-P-07A/B
•
High high diaphragm pressure alarm 69-PAHH-1344 set at 5.5 barg in 1st stage
Biocide Injection Pump 6932-P-07A initiates the pump changeover
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4.14.7
•
High high diaphragm pressure alarm 69-PAHH-1346 set at 5.5 barg in 2nd stage
Biocide Injection Pump 6932-P-07A initiates the pump changeover
•
High high diaphragm pressure alarm 69-PAHH-1328 set at 5.5 barg in 3rd stage
Biocide Injection Pump 6932-P-07A initiates the pump changeover
•
High high diaphragm pressure alarm 69-PAHH-1345 set at 5.5 barg in 1st stage
Biocide Injection Pump 6932-P-07B initiates the pump changeover
•
High high diaphragm pressure alarm 69-PAHH-1347 set at 5.5 barg in 2nd stage
Biocide Injection Pump 6932-P-07B initiates the pump changeover
•
High high diaphragm pressure alarm 69-PAHH-1329 set at 5.5 barg in 3rd stage
Biocide Injection Pump 6932-P-07B initiates the pump changeover
•
ESD-0, ESD-1, ESD-2 shutdown signals activates the tripping of both the Biocide
Injection Pumps 6932-P-07A/B.
Scale Inhibitor Injection Package 6932-A-07
4.14.7.1 Equipment Specification
Scale Inhibitor Storage Tank
Equipment Tag No.
6932-T-05
Size, ID/Height, mm
3
Storage Capacity m
Chemical
2480/4900
24
Scale Inhibitor
Design Pressure bar(a)
1.2
Design Temperature °C
85/0
Operating Pressure bar(g)
ATM
Operating Temperature, °C
52/0
Material of Construction
AISI 316L
Scale Inhibitor Injection Pumps
Equipment Tag No.
Pump Type
Chemical
Capacity, L/H
6932-P-09A/B
Double Diaphragm
Scale Inhibitor
26/41/4
Design Pressure, bar(g)
10
Discharge Pressure, bar(g)
5.5
Design Temperature, °C
120/0
Driver Type
Motor
Rated Power, kW
Material of Construction
0.37
SS 316TI/PTFE
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TITLE: OPERATION AND MAINTENANCE MANUAL
Scale Inhibitor Unloading Pump
Equipment Tag No.
6932-P-10
Pump Type
Air Operated Pump
Chemical
Scale Inhibitor
Capacity, L/h
5000
Design Pressure, bar(g)
8.7
Discharge Pressure, bar(g)
1.2
Design Temperature, °C
85/0
Material of Construction
SS 316TI
4.14.7.2 Scale Inhibitor Injection Package Description
Scale Inhibitor Injection Package consists of a Scale Inhibitor Storage Tank 6932-T-05
and two numbers of Scale Inhibitor Injection Pumps 6932-P-09A/B.
Scale Inhibitor from drums is transferred to the tank through an unloading pump
6932-P-10.
The Scale Inhibitor Injection Pumps 6932-P-09A/B are having discharge pulsation
dampner and calibration pots at the suction line.
4.14.7.3 Scale Inhibitor Injection Process control Description
The Scale Inhibitor Storage Tank 6932-T-05 level is measured by 69-LI-1330. Scale
Inhibitor from the storage tank is injected to sea cooling water through Injection
Pumps 6932-P-09A/6932-P-09B.
Following parameters are to be monitored:
Tag No.
69-FI-1322
69-FI-1321
69-FI-1320
69-PI-1332
69-PI-1333
69-PI-1334
69-PI-1335
69-PI-1336
69-PI-1337
69-LI-1330
Description
6932-P-09A/B 1st stage common discharge
flow
6932-P-09A/B 2nd stage common discharge
flow
6932-P-09A/B 3rd stage common discharge
flow
6932-P-09A 1st stage discharge pressure
6932-P-09A 2nd stage discharge pressure
6932-P-09A 3rd stage discharge pressure
6932-P-09B 1st stage discharge pressure
6932-P-09B 2nd stage discharge pressure
6932-P-09B 3rd stage discharge pressure
Scale Inhibitor Storage Tank (6932-T05)
level
Unit
Alarm
Low
High
LPH
2
8
LPH
35
45
LPH
20
30
barg
barg
barg
barg
barg
barg
NA
NA
NA
NA
NA
NA
6.5
6.5
6.5
6.5
6.5
6.5
%
6
80
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The scale inhibitor injection pumps can be operated from the DCS when the Pumps are
selected to “Remote” at its local panel.
Following are the details of the switches & alarm related to motor controls:
Tag No.
Description
69-HSOA-1354
Remote “ START” for the Pump 6932-P-09A
69-HSOA-1355
Remote “ START” for the Pump 6932-P-09B
69-HSCA-1354
Remote “ STOP” for the Pump 6932-P-09A
69-HSCA-1355
Remote “ STOP” for the Pump 6932-P-09B
69-ZL-1354
6932-P-09A Pump Available signal
69-ZL-1355
6932-P-09B Pump Available signal
69-XS-1354
6932-P-09A Pump ESD trip signal
69-XS-1355
6932-P-09B Pump ESD trip signal
69-ZI-1354
6932-P-09A Pump running indication
69-ZI-1355
6932-P-09B Pump running indication
•
Low low level alarm 69-LALL-1331 set at 3% in Scale Inhibitor Storage Tank 6932-T05 trips the Scale Inhibitor Injection Pumps (6932-P-09A/B)
•
High high diaphragm pressure alarm 69-PAHH-1338 set at 5.5 barg in 1st stage
Scale Inhibitor Injection Pump 6932-P-09A initiates the pump changeover
•
High high diaphragm pressure alarm 69-PAHH-1348 set at 5.5 barg in 2nd stage
Scale Inhibitor Injection Pump 6932-P-09A initiates the pump changeover
•
High high diaphragm pressure alarm 69-PAHH-1350 set at 5.5 barg in 3rd stage
Scale Inhibitor Injection Pump 6932-P-09A initiates the pump changeover
•
High high diaphragm pressure alarm 69-PAHH-1339 set at 5.5 barg in 1st stage
Scale Inhibitor Injection Pump 6932-P-09B initiates the pump changeover
•
High high diaphragm pressure alarm 69-PAHH-1349 set at 5.5 barg in 2nd stage
Scale Inhibitor Injection Pump 6932-P-09B initiates the pump changeover
•
High high diaphragm pressure alarm 69-PAHH-1351 in 3rd stage Scale Inhibitor
Injection Pump 6932-P-09B initiates the pump changeover
•
ESD-0, ESD-1, ESD-2 shutdown signals activates the tripping of both the Scale
Inhibitor Injection Pumps 6934-P-09A/B.
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TITLE: OPERATION AND MAINTENANCE MANUAL
4.14.8
Catalyst Injection Package 9101-A-01
4.14.8.1 Equipment Specification
Catalyst Storage Tank
Equipment Tag No.
9101-T-01
Size, ID/Height, mm
3
Storage Capacity m
Chemical
950/1500
1
Catalyst
Design Pressure bar(a)
1.01
Design Temperature °C
85/0
Operating Pressure bar(g)
ATM
Operating Temperature, °C
52/0
Material of Construction
AISI 316L
Catalyst Injection Pumps
Equipment Tag No.
Pump Type
Chemical
Capacity, L/H
9101-P-11A/B
Double Diaphragm
Catalyst
0.55
Design Pressure, bar(g)
8
Discharge Pressure, bar(g)
5
Design Temperature, °C
85/0
Driver Type
Motor
Rated Power, kW
Material of Construction
0.37
SS 316TI/PTFE
Catalyst Unloading Pumps
Equipment Tag No.
Pump Type
Chemical
Capacity, L/h
9101-P-12
Air Operated Pump
Catalyst
2000
Design Pressure, bar(g)
8.7
Discharge Pressure, bar(g)
1.2
Design Temperature, °C
85/0
Material of Construction
SS 316TI
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4.14.8.2 Catalyst Injection Package Description
Catalyst Injection Package consists of a Catalyst Storage Tank 9101-T-01 and two
numbers of Catalyst Injection Pumps 9101-P-11A/B.
Catalyst from drums is transferred to the tank through an unloading pump 9101-P-12.
The Catalyst Injection Pumps 9101-P-11A/B are having calibration pots at the suction
line.
4.14.8.3 Catalyst Injection Process control Description
The Catalyst Storage Tank level 9101-T-01 is monitored by 91-LI-1127 and Catalyst
Injection Pumps 9101-P-11A/B common discharge flow is measured by 91-FI-1128.
Following parameters are to be monitored:
Tag No.
Description
Unit
Alarm
Low
High
91-FI-1128
9101-P-11A/B common
discharge flow
LPH
0.2
0.7
91-PI-1127
9101-P-11A discharge pressure
barg
NA
6
91-PI-1129
9101-P-11B discharge pressure
barg
NA
6
91-LI-1127
catalyst storage tank 9101-T01
level
%
6
NA
Following are the details of the switches & Alarm related to motor controls:
Tag No.
Description
91-HSOA-1129
Remote “ START” for the Pump 9101-P-11A
91-HSOA-1130
Remote “ START” for the Pump 9101-P-11B
91-HSCA-1129
Remote “ STOP” for the Pump 9101-P-11A
91-HSCA-1130
Remote “ STOP” for the Pump 9101-P-11B
91-ZL-1129
9101-P-11A Pump Available signal
91-ZL-1130
9101-P-11B Pump Available signal
91-XS-1129
9101-P-11A Pump ESD trip signal
91-XS-1130
9101-P-11B Pump ESD trip signal
91-ZI-1129
9101-P-11A Pump running indication
91-ZI-1130
9101-P-11B Pump running indication
•
Low low level alarm 91-LALL-1128 set at 3% in Catalyst Storage Tank 9101-T-01
trips the Catalyst Injection Pumps 9101-P-11A/B
•
High high diaphragm pressure alarm 91-PAHH-1128 set at 5 barg in Catalyst
Injection Pump 9101-P-11A initiates the pump changeover
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•
High high diaphragm pressure alarm 91-PAHH-1130 set at 5 barg in Catalyst
Injection Pump 9101-P-11B initiates the pump changeover
•
ESD-0, ESD-1, ESD-2 shutdown signals activates the tripping of both the Catalyst
Injection Pumps 9101-P-11A/B.
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TITLE: OPERATION AND MAINTENANCE MANUAL
SECTION V PRE-REQUISITE FOR START-UP
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5.1
GENERAL
For Start-up of the SRU Upgrade Facilities the pre-requisites are given below:
•
All vent and drain valves position are as per P&ID
•
All spectacle spacers and spectacle blinds are as per P&ID
•
Acid gas from AGRU 1 & 2 to the Acid Gas Enrichment Unit isolation valve 91-BV1881 is in closed condition
•
Electrical power is available
•
Fire & gas system of process unit is tested and in normal operation
•
Ensure that DCS, F&G and ESD systems are available
•
Acid gas flare system is in operation
•
LP Flare is in operation
•
All process line isolating valves are in closed condition
•
Ensure all ‘Lock Open’ and ‘Lock Closed’ valves are in their normal operating
positions as per P&ID
•
Ensure that all safety devices have been set to the appropriate set-point as per
P&ID
•
Ensure all mechanical equipment have been installed properly
•
All instrument root valves are open
•
All instrument vent/drain valves are closed
•
Ensure that no shutdown conditions are present (ESD)
•
Confirm availability of all tools, consumables, and spare parts that are required
for start-up
•
Confirm that the required valid “Permit to Work” has been issued prior to the
commencement of start-up activities
•
Ensure that fire protection system is ready for operation
•
Ensure that the AGRU 1 & 2 are running and ready to provide acid gas to the AGEU
Prior to the starting up of the plant there are several operations that must be
conducted to prepare the plant for the actual start-up. This section covers the work
required in preparing the unit for initial start-up. The jobs can be categorized as
follows:
•
Plant inspection
•
Final inspection of vessels and equipments
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•
Line and Equipment leak test
It is important that these above procedures to be carried out thoroughly and at
earliest possible to achieve a smooth, trouble free and steady normal operation.
5.2
INTERFACE ACTIVITIES
The following tie-ins between the NGL 1, 2, 3 & 4 and the SRU Upgrade Facilities are
to be completed before the start-up of the new facilities.
Process
•
Acid Gas from NGL-3 AGRU 1 & 2
•
Acid Gas from NGL 1 & 2 Blowers
•
Acid Gas from NGL-4 K-8201A/B
•
Acid Gas from AGEU Regenerator Reflux Drum 9103-V-12 to SRU
•
Sour Water from Acid Gas KO Drum Return Pump 9103-P-14A/B to SRU
•
Acid Water from SRU to Amine Sump 9103-V-10
Utilities
•
Sea Cooling Water from new Sea Cooling Water system to the existing Sea Cooling
Water system
•
Sea Cooling Water Return from AGEU/TGTU to existing Sea Water Observation
Sump 6932-X-01
•
20” LP Flare header interconnection from new units to the existing units
•
NGL-4 Sea Cooling Water system new Sea Water Filters S-8840A/B
•
Line from existing Drinking Water Storage Tank 6834-T-01A/B to the new Drinking
Water Pumps 6834-P-23A/B
•
Interconnection between existing Drinking Water Pumps 6834-P-01A/B and new
Drinking Water Pumps 6834-P-23A/B
•
Interconnection between new DM Water network to the existing DM Water network
•
Interconnection between the new plant air header to the old plant air header
•
Interconnection between the existing 6”-GI-82-0357-C01A nitrogen header to the
new nitrogen header
•
Interconnection between the existing Lean Gas from Booster Compressor suction
to the LP Fuel Gas KO Drum 6236-V-05
•
Interconnection between the lean gas from 6103-K-01A/B and the LP Fuel Gas KO
Drum 6236-V-05
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•
Interconnection between the existing fuel gas line upstream of 65-XV-001 and the
LP Fuel Gas KO Drum 6236-V-05
•
Interconnection from existing fuel gas header 6”-6536-FG-101-C12P to Incinerator
9101-F-14 and Reducing Gas Generator 9102-F-11
•
Interconnection of the following new flare lines to the existing LP Flare Header
10”-6922-FL-013-C14P:
•
From LP Fuel Gas KO Drum 6236-V-05 drain line
•
LP Fuel Gas KO Drum 6236-V-05 PSVs 62-PSV-176/176S outlet lines
•
Fuel gas from steam generation package 6848-A-02A/B/C
•
From LP Fuel Gas KO Drum 6236-V-05 vent 62-PV-1303
•
From LP Fuel Gas KO Drum 6236-V-05 inlet pressure control valves 62-PV1301A/62-PV-1301B/62-PV-1302
•
Interconnection from existing fuel gas line 2”-6536-FG-011-C12P to LP Acid Gas
flare header as purge gas
•
Interconnection from the existing Service Water Pump P-3103 discharge to the
Electro Chlorination Package 6932-A-05
•
Interconnection between the existing Instrument Air supply to the new Sea Cooling
Water Filters 6932-S-02A/B
•
Interconnection between the existing Plant Air supply to the Sea Cooling Water
Filters 6932-S-02A/B
•
Interconnection between the existing nitrogen supply system to the new Electro
Chlorination system
•
Interconnection between the existing Spent Caustic system and the new Spent
Caustic form Desuperheater Circulation Pumps 9102-P-11A/B
•
Oily Waste Water from SRU Upgrade new Utilities/Process area to the existing Oily
Waste Water Sump 6922-X-01
•
From new Stripped Water Cooler 6922-E-02/Cooling water return from
AGEU/TGTU to Sea Water Observation Sump 6932-X-01 analyzer 69-AT-1301 outlet
to the existing Observation & Buffer Sump 6922-X-04
•
Interconnection between the existing instrument air header and the new
instrument air header
•
Interconnection between the new Biocide Injection Package 6932-A-06 and the
existing Sea Cooling Water Pumps P-1618 AR/BR/CR suction
•
Interconnection between the new Scale Inhibitor Injection Package 6932-A-07 and
the existing Sea Cooling Water Pumps P-1618 AR/BR/CR discharge.
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5.3
START-UP OF UTILITIES
5.3.1
Start-up Sequence
Utilities are started in the following sequence:
5.4
5.4.1
1.
Instrument Air/Plant Air System
2.
Nitrogen System
3.
Drinking Water System
4.
Oily Water Drain System
5.
Effluent and Waste Water Treatment System
6.
Flare System
7.
Fuel Gas System
8.
Sea Cooling Water System
9.
Chemical Injection System
10.
DM Water System
11.
Boiler Feed Water Deaerator System
12.
Steam Generation System
INSTRUMENT AIR/PLANT AIR SYSTEM
Pre Start-up Checks
Ensure the following pre start-up checks are completed before the start-up:
1. Ensure the Readiness of Instrument Air Compressor, Instrument Air Dryer and all its
auxiliary equipments.
2. Ensure all the instruments are lined up.
3. Ensure that the Air Compressor Discharge Drum 6837-V-10 & Instrument Air
Receiver 6837-V-11 are clean.
Ensure the following PSVs are calibrated, reinstated and lined-up as shown in P&ID:
PSV Tag No.
Description
68-PSV-1401
PSV after intercooler
68-PSV-1402
PSV after intercooler
68-PSV-1106/1106S
Air compressor Discharge drum PSV
68-PSV-1107/1107S
Instrument air receiver PSV
68-PSV-1408
Adsorber 6837-V-14A
68-PSV-1409
Adsorber 6837-V-14A
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PSV Tag No.
5.4.2
Description
68-PSV-1458
Adsorber 6837-V-15A
68-PSV-1459
Adsorber 6837-V-15B
Instrument Air compressor Start-up
There are two Instrument Air Compressors (2 x 100% capacity). The compressors
operate on Duty/Standby configuration.
Each compressor is monitored and controlled by the package controller (UCP) which
contains Siemens S7-400H series PLC and provides information to the DCS through
redundant modbus TCP/IP communication link.
Air Compressors LCP details are tabulated below:
Sl. #
Tag No.
6837-K-02A
Service
6837-K-02B
1.
68-HS-1403
68-HS-1453
Local/Remote Selector Switch
2.
68-HS-1402
68-HS-1452
Load/Unload Selector switch
3.
68-HSOA-1414
68-HSOA-1464
Start Push Button
4.
68-HSCA-1415
68-HSOA-1465
Stop Push Button
5.
68-HS-1404
68-HS-1454
Lamp Test Push Button
6.
68-HS-1401
68-HS-1451
Emergency Stop Push Button
7.
68-HS-1405
68-HS-1455
Reset Push Button
8.
68-XL-1408
68-XL-1458
Voltage ON lamp (white)
9.
68-XL-1409
68-XL-1459
Compressor loaded lamp
10.
68-XL-1410
68-XL-1460
Automatic operation lamp
11.
68-XL-1411
68-XL-1461
General warning lamp
12.
68-XL-1412
68-XL-1462
General shutdown lamp
Details of DCS tags for Air Compressors are tabulated below:
Sl. #
Tag No.
6837-K-02A
6837-K-02B
Service
1.
68-HSOA-1428
68-HSOA-1478
Remote Start Button
2.
68-HSCA-1428
68-HSOC-1478
Remote Stop Button
3.
68-UA-1401
68-UA-1451
Compressor common alarm
Note: Press lamp test push button in local control panel and ensure all the lamps are
in working normal.
The procedure for start-up of one unit (6837-K-02A) of IA Compressor is covered in this
section. The same procedure is applicable for other unit (6837-K-02B).
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Instrument air compressor can be started in two modes.
I.
Local Mode
In local mode, the start/stop of the compressor is done from the local control station
(LCS). For operating the Compressor in local mode, the selectors switch 68-HS-1403 in
Local Control Station to be selected to local position. The loading/unloading is done by
the operator using the loading/unloading switch 68-HS-1402 in the LCS. During Local
mode loading and unloading of the compressor is based on the compressor outlet
pressure transmitter signal 68-PT-1406. Local mode is used for service or maintenance
purposes.
II. Remote Mode
Remote-Auto and Remote-Manual modes are possible under remote mode of operation.
In Remote mode, start and stop of the individual compressors are initiated from
UCP/DCS operating stations. In Remote-Auto mode, the UCP sequence control has
total control over selection, start & stop and pressure control of both the compressors.
All local controls are disabled in this mode except emergency stop from field.
In Remote mode, the loading/unloading of compressors is based on the air receiver
pressure transmitter signal 68-PT-1311.
5.4.3
Start-up permissive conditions:
•
Availability of instruments and in healthy condition
•
Motor available signal (68-XU-1428) from MCC
•
Ensure the below mentioned interlocks in UCP of I/A Compressor are normal:
Tag No.
Description
68-PAHH-1406
Compressor outlet pressure high-high
68-PDALL-1401
Compressor air inlet pressure low-low
68-PALL-1402
Compressor oil pressure low-low
68-PDAHH-1403
Compressor oil filter DP high-high
68-TAHH-1401
LP stage outlet temperature high-high
68-TAHH-1402
Compressor oil temperature high-high
68-TAHH-1403
LP stage inlet temperature high-high
68-TAHH-1405
Compressor outlet temperature high-high
68-TAHH-1406
Main motor (U1) winding temperature high-high
68-TAHH-1407
Main motor (V1) winding temperature high-high
68-TAHH-1408
Main motor (W1) winding temperature high-high
68-TAHH-1412
Main motor(U2) winding temperature high-high
68-TAHH-1413
Main motor (V2) winding temperature high-high
68-TAHH-1414
Main motor (W2) winding temperature high-high
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Tag No.
Description
68-TAHH-1410
Main motor bearing (DE) temperature high-high
68-TAHH-1411
Main motor bearing (NDE) temperature high-high
68-HS-1401
Emergency stop button at LCP
68-XS-1424
ESD signal to UCP
Following interlocks are bypassed automatically during start-up of compressor:
•
68-PT-1402 (Lube oil pressure) low low alarm
•
Compressor trip (68-XZA-1428) and stop (68-XI-1428) feedback
Both the above interlocks are bypassed for 20 seconds.
The local start-up procedure for 6837-K-02A is given below:
1.
Select both the compressors to “Local” from the Local Control panel through
selector switch
2.
Open 6837-K-02A discharge isolation valve
3.
Close the Plant air header pressure control valve 68-PV-1310 and the upstream
block valve
4.
Close the Air Dryer Package pre-filter upstream isolation valves
5.
Confirm ‘Motor available’ signal (68-XU-1428) exists
6.
Before starting the Compressor main motor, Set loading & unloading Pressure set
point at XX barg in UCP HMI
7.
Start Compressor 6837-K-02A through Local Start Push Button and ensure that
compressor is started and running
8.
Ensure that the Cooling Air Fans (6837-EFM-03AA/AB) and External After Cooler
Fan Motor (6837-EFM-04A) is running and its running indication in DCS/HMI
9.
Ensure that oil pump is running and the oil pressure is 2.3 barg
10. Ensure compressor runs in unloaded condition for 20 seconds
11. Load the Air Compressor by Pressing Push button 68-HS-1402 in the local panel
12. Ensure that the compressor is loaded by checking the pressure 68-PT-1406 located
in the HP Stage compressor outlet
13. Confirm ‘Loaded’ indication (68-XL-1409) in local control station
14. Confirm the Compressor loads up to XX barg, based on the value taken from 68PT-1406 located on the compressor outlet
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15. Check the performance of the Compressor by monitoring the following
parameters:
•
Discharge Pressure (68-PI-1406)
•
Discharge Temperature (68-TI-1405)
•
Motor Amperage
•
Oil Temperature (68-TI-1402)
•
Oil Pressure (68-PI-1402)
•
Motor Winding Temperatures
•
Compressor vibration
•
Motor vibration
•
Compressor and motor bearing temperatures
Note: Instrument air compressors can also be started from DCS by selecting the
“Remote” in LCP and Auto/manual button to “Auto” in UCP-HMI.
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Fig. 25 - IA Compressor Start-up
D
Instrument Air Compressor
Start Sequence
Y
20 sec load delay, oil pressure trip
(68-PT-1402) needs to be bypassed
up to this time
Manual Unload
N
Take corrective
action
N
Interlocks &
start-up permissive
healthy
Ready to load/unload
Note-A
Set pressure
<Actual
Pressure
(68-PT-1311)
Y
Check load,
unload selector
switch
68-HS-1402
Local/remote
selection
Loading SOV
68-XY-1401
energizes
Load
Local/remote
Selector switch in
LCP 68-HS-1403
N
Unloading
SOV 68-XY-1403
energizes
Y
Loading SOV 68-XY-1401 energizes
and unloading SOV 68-XY-1403 deenergizes
After 20 minutes
Compressor stops
Local
Loading hour counter starts
Remote Auto/
Manual
selection in HMI
Auto DCS
A
B
Set pressure
<Actual
Pressure
(68-PT-1406)
PLC HMI
(Manual)
c
Loading SOV
68-XY-1401
energizes
N
Unloading
SOV 68-XY-1403
energizes
Y
After 20 minutes
Compressor stops
Loading
hour>Set
value
Y
Service change over-Running
compressor stop, reset the loading
hour counter and start the
standby
C
B
Note A
Motor available signal (68-XU-1428) from MCC
No emergency stop (68-HS-1401) active
No ESD signal (68-XS-1424) active
Compressor O/L pressure high-high (68-PT-1406)
Running hour counter starts
Disable control from UCP
and DCS
Start signal activated
Compressor air I/L pressure low-low (68-PDT-1401)
Compressor oil pressure low-low (68-PT-1402)
Compressor oil filters DP high-high (68-PDT-1403)
LP stage O/L temperature high-high (68-TT-1401)
Start from LCP-68HSOA-1414
Main motor, cooling fan motor and
after cooler fan motor starts
Running hour
>24H
Y
Main motor, cooling fan
motor and after cooler
fan motor starts
20 sec load delay, Oil pressure trip
(68-PT-1402) needs to be bypassed
up to this time
Auto change over-Running
compressor stop & reset the
loading hour counter and start the
standby
Compressor oil temperature high-high (68-TT-1402)
LP stage I/L temperature high-high (68-TT-1403)
Compressor O/L temperature high-high (68-TT1405)
Overload relays of main motor, inter external after
cooler motors
Main motor winding temperatures high-high
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5.4.4
Instrument Air Dryer start-up
The dryer package consists of two trains of dryers (6837-A-03 & 6837-A-04) which are
to be operated (2 X 50%) together and this repetitive operation is controlled from UCP
panel.
ON/OFF valve details in the dryer package are tabulated below:
Sl. #
Tag No.
6837-A-03
Service
6837-A-04
1.
68-XV-1416
68-XV-1466
Purge on/off valve
2.
68-XV-1417
68-XV-1467
Purge on/off valve
3.
68-XV-1418
68-XV-1468
Air inlet on/off valve
4.
68-XV-1419
68-XV-1469
Air inlet on/off valve
Details of tags for Air dryers are tabulated below:
Sl. #
5.4.5
5.4.6
Tag No.
Service
6837-A-03
6837-A-04
1.
68-HSOA-1408
68-HSOA-1458
Remote start Button
2.
68-HSCA-1409
68-HSOC-1459
Remote stop Button
3.
68-UA-1402
68-UA-1452
Dryer common alarm
4.
68-UA-1403
68-UA-1453
Dryer changeover failure alarm
Instrument Air Dryer Start-up Checks
1.
Ensure the UCP for air dryers is powered up and ensure that all controls are in
place.
2.
Close air supply towards the dew point analyzer AI-1401 & AI-1451 and by-pass its
alarm on both units 6837-A-03 & 6837-A-04.
3.
Start the air compressor and wait for pressure to develop in the compressor
discharge drum.
4.
Slowly open the pre-filters inlet manual isolation valve.
5.
Check the connections of the air dryer for air leaks and repair if necessary.
Dryer Start
There are two Nos. Instrument Air Dryer Package (6837-A-03/04) consisting of heaterless desiccant dryers of 2 X 50% capacity. Each Dryer Package consists of two vessels
(one drying, one regenerating), a set of duplex pre-filter and after-filter.
Unit start/stop of the package can be done either from UCP or from DCS. No local
mode of operation available for dryer package.
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At the initial start for the availability of the dryer, the position of valves is as follows:
•
68-XV-1418/68-XV-1468-open (tower - A in drying)
•
68-XV-1419/68-XV-1469-closed
•
68-XV-1416/68-XV-1466-Closed
•
68-XV-1417/68-XV-1467-open (tower - B in regeneration mode)
Also after opening the manual valves following are required to be checked to start the
dryer
•
Tower pressures 68-PT-1408/68-PT-1409
•
Tower pressures 68-PT-1458/68-PT-1459
•
Dryer available status has to be selected by the operator from HMI
•
All the alarm conditions for healthy status to be checked before start-up
Start the dryer by activating the following commands:
•
68-HSOA-1408 for Dryer-6837-A-03
•
68-HSOA-1458 for Dryer-6837-A-04
When drying is started, as a first step (step-0), ensure Adsorber-A (6837-V-14A) is
initialised into drying and Adsorber-B (6837-V-14B) is initialised into depressurizing for
5 seconds. Ensure the following valves’ condition:
•
68-XV-1418 & 68-XV-1417 are in OPEN condition
•
68-XV-1419 & 68-XV-1416 are in CLOSE condition
In step-1, ensure that Adsorber-A (6837-V-14A) is in the drying mode and Adsorber-B
(6837-V-14B) is being pressurised for 55 seconds. Ensure the following valves’
condition:
•
68-XV-1418 & 68-XV-1419 are in OPEN Condition
•
68-XV-1417 & 68-XV-1416 are in CLOSE condition
Tower B will pressurize up to the running pressure (7.8 bar), after pressure is reached
both the towers will be operational for a brief period (5 seconds) together.
In step-2, ensure that Adsorber-A (6837-V-14A) is in the drying mode and Adsorber-B
(6837-V-14B) is in purge saving mode (this mode manually selected, when dew point is
more than -30°C) until the dryer outlet dew point value is greater than the set point
for the dew point or for a maximum duration of 24 hours. Ensure the following valves
condition:
•
68-XV-1418 & 68-XV-1419 are in OPEN Condition
•
68-XV-1417 & 68-XV-1416 are in CLOSE condition
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In step-3, ensure that Adsorber-A (6837-V-14A) is in the regenerating mode and
Adsorber-B (6837-V-14B) is in drying mode for 195 seconds. Ensure the following
valves’ condition:
•
68-XV-1419 & 68-XV-1416 are in OPEN condition
•
68-XV-1418 & 68-XV-1417 are in CLOSE Condition
In step-4, ensure that Adsorber-A (6837-V-14A) is in the pressurizing mode and
Adsorber-B (6837-V-14B) is in drying mode for 55 seconds. Ensure the following Valves’
condition:
•
68-XV-1419 & 68-XV-1418 are in OPEN condition
•
68-XV-1417 & 68-XV-1416 are in CLOSE Condition
In step-5, ensure that Adsorber-A (6837-V-14A) is in the purge saving mode (this mode
Manually Selected, when dew point is more than -30°C) and Adsorber-B (6837-V-14B) is
in drying mode until the dryer outlet dew point value is greater than the set point for
the dew point or for a maximum duration of 24 hours. Ensure the following Valves’
condition:
•
68-XV-1419 is in OPEN condition
•
68-XV-1418,68-XV-1417 & 68-XV-1416 are in CLOSE Condition
In step-6, ensure that Adsorber-A (6837-V-14A) is in the drying mode and Adsorber-B
(6837-V-14B) is in regenerating mode for 195 seconds. Ensure the following valves’
condition:
•
68-XV-1418 & 68-XV-1417 are in OPEN condition
•
68-XV-1419 & 68-XV-1416 are in CLOSE condition
Repeat the above test for TRAIN B (6837-V-15A & 6837-V-15B) dryers.
Steps 2 and 5 will be valid only when the purge saving is requested from UCP.
Following table shows the valve positions of Tower A, B with respect to the above
mentioned phase sequence.
Valve Status
Sl. #
Operational
Phase
Period
1.
A: Drying
B:Depressurising
5 sec
XV-1418
XV-1417
XV-1416
XV-1419
2.
A: Drying
B: pressurising
55 sec
XV-1418
XV-1419
XV-1416
XV-1417
3.
A: Drying
B:Purge saving
DEW>set
Max-24 hrs
XV-1418
XV-1419
XV-1416
XV-1417
Open
Close
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Sl. #
Operational
Phase
Valve Status
Period
Open
Close
4.
A: Regenerating
B: Drying
195 sec
XV-1419
XV-1416
XV-1417
XV-1418
5.
A: Pressurising
B: Drying
55 sec
XV-1419
XV-1418
XV-1416
XV-1417
6.
A: Purge saving
B: Drying
DEW>set
Max-24 hrs
XV-1419
XV-1418
XV-1416
XV-1417
7.
A:Drying
B:Regenerating
195 sec
XV-1418
XV-1417
XV-1416
XV-1419
Note: In the above table only train-A dryer is considered.
5.5
NITROGEN SYSTEM
5.5.1
Lining up of Nitrogen from existing system to the New Distribution Header
Ensure that the following end user isolation valves are closed:
•
Nitrogen line to the Reaction Furnace 9101-F-01
•
Nitrogen line to the Antifoam Storage Tank 9103-T-12
•
Nitrogen line to the Reducing Gas Generator 9102-F-11
•
Nitrogen line to the Incinerator Package 9101-F-14
•
Utility stations in AGEU area
•
Nitrogen line to the Amine Sump 9103-V-10
•
Nitrogen line to the Amine Regenerator 9103-C-12
•
Nitrogen line to the Waste Water Degasser 6922-V-07
•
Nitrogen line to the Amine Surge Tank 9103-T-11
•
Nitrogen line to the Utility Station in Effluent & Waste Water Treatment area
•
Nitrogen line to Utility Station in TGTU area
•
Nitrogen line to the Steam Generation Package 6848-A-02A/B/C
•
Nitrogen line to the Utility station in Heating Medium system area
•
Nitrogen line to the Utility station in Fuel Gas area
Lining up of Nitrogen
•
Ensure that the vent and drain valves are closed in the header.
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5.6
5.6.1
•
Open the 3” isolation valve 68-GV-1953 from the existing 6”-GI-88-0357-C01A
Nitrogen header to the new distribution header slowly and pressurise the header
with Nitrogen.
•
Verify from the pressure gauge 68-PT-1309 that the pressure in the Nitrogen
header is increasing slowly.
•
After pressurising the main header, slowly open the isolation valves for the sub
headers 3”-9138-IG-312-C12M, 3”-6838-IG-126-C12M & 3”-6838-IG-123-C12M to
process/utility area at battery limit and pressurise the lines.
•
Check that the headers are pressurised by checking the pressure gauges 68-PG1329/1331/1351.
•
Open the 2” isolation valves from the header for the utility stations of heating
medium system and the fuel gas system.
•
Open the end user isolation valves and purge the lines to remove oxygen content.
•
Check for any leak in the system.
DRINKING WATER SYSTEM
Lining up of Drinking Water to existing network
1. Ensure that the Drinking Water Storage Tank 6834-T-01A/B level is more than 50%.
3. Ensure that the isolation valve at the tie-in point (T-002) of the new and old
drinking water network is closed.
4. Ensure that the vent and drain valves near the tie-in point is closed.
5. Ensure that the new drinking water line to existing network is cleaned by flushing
and the leak test has been completed.
6. Open the Drinking Water isolation valves from the Tanks 6834-T-01A/B and slowly
fill up the new drinking water lines.
7. Prime the Drinking Water Pumps 6834-P-23A/B.
8. Start the Drinking Water Pump 6834-P-23A on minimum circulation.
9. Ensure that the line connecting the existing network is filled by opening the vent
and bleeding air near the tie-in point.
10. Check for any leaks in the line.
5.6.2
Lining up of Drinking Water to DMW Package
1. Ensure that the isolation valve at the inlet of the DMW Unit is closed.
2. Ensure that the drain valve upstream of the DMW Unit is closed.
3. Ensure that the new drinking water line to DMW Unit is cleaned by flushing and the
leak test has been completed.
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4. Start the Drinking water pump 6834-P-23A and slowly open the discharge isolation
valve and fill the line connecting the DMW Unit by opening the drain line upstream
of the isolation valve.
5. Check for any leaks in the line.
6. After filling the line up to DMW Unit with Drinking water, it can be lined up to DMW
Unit whenever required.
5.7
EFFLUENT & WASTE WATER TREATMENT SYSTEM
5.7.1
Lining up of Waste Water Degasser 6922-V-07
1.
Ensure that the Degasser and pipelines are flushed and cleaned and ready for
lining up.
2.
Confirm that the drain and vent valves are closed.
3.
Ensure that waste water from Tail Gas Treatment Unit is available and Cooling
Water Circulation Pumps 9102-P-12A/B are running.
4.
Ensure that high high level alarm 69-LAHH-1311 and high high pressure 69-PAHH1311 of the Degasser is not active in the ICSS.
5.
Reset ESD. Ensure that the waste water from Cooling Water Circulation Pumps
9102-P-12A/B inlet ON-OFF valve 69-XV-1312 is opened.
6.
Ensure water level starts rising in the Degasser by monitoring 69-LT-1311 & 1301
and cross checked through 69-LG-1302.
7.
Ensure that the low low level trip 69-LALL-1311 is cancelled after the level
reaches 300 mm and also ensure that the Waste Water Degasser Pumps 6922-P08A/B suction ON-OFF valve 69-XV-1316 is open.
8.
Ensure that low level alarm 69-LAL-1301 is cancelled after the level reaches 450 mm.
9.
Open the suction isolation valves of the Waste Water Degasser Pumps 6922-P08A/B.
10. Prime the Waste Water Degasser Pumps 6922-P-08A/B by opening the casing vents.
11. Energize Waste Water Degasser Pumps 6922-P-08A/B from MCC.
12. Put Waste Water Degasser Pumps 6922-P-08A/B LOR switch to ‘Remote’ at Local
Control Station.
13. Select Waste Water Degasser Pump 6922-P-08A as “DUTY” and 6922-P-08B as
“STANDBY” from the ICSS.
14. Ensure the minimum flow recycle line 2″ isolation valve is opened for the pump
6922-P-08A.
15. Start the “DUTY” pump 6922-P-08A from the ICSS.
16. Ensure that the pump is running without any abnormal noise and vibration.
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5.7.2
Lining up of Sour Water Stripper 6922-C-01
1.
Slowly open the 2″ discharge valve of the pump 6922-P-08A and line up sour water
to the Sour Water Filter 6922-S-06.
2.
Ensure that the sour water from 6922-P-08A discharge to the observation sump 2″
isolation valve is closed.
3.
Slowly open the sour water filter 2″ inlet isolation valve and fill the filter with the
sour water.
4.
Open the 2″ vent valve of the sour water filter and release air. Close the vent
isolation valve after filling the filter.
5.
Slowly open the filter outlet 2″ isolation valve and the Sour/Stripped Water
Exchanger 6922-E-01 tube side inlet 2″ isolation valve.
6.
Open the Sour/Stripped Water Exchanger 6922-E-01 tube side outlet 2″ isolation
valve and the 69-FV-1314 upstream and downstream isolation valves.
7.
Put 69-FV-1314 in manual and open the control valve slowly and allow the waste
water to flow through to the Sour Water Stripper.
8.
Now put 69-LIC-1301 in auto mode with a set point of 50% and 69-FV-1314 in
remote mode.
9.
Ensure that the level starts to build at the bottom of the Sour Water Stripper by
checking the level gauge 69-LG-1306.
10. Ensure low low level 69-LALL-1316 is cancelled in the Sour Water Stripper when
the level rises.
11. Ensure that the low level alarm 69-LAL-1306 is also cancelled as the level goes up.
12. Now open the 3″ suction isolation valve of the Stripped Water Pumps 6922-P-10A/B
and prime the pumps.
13. Energize Stripped Water Pumps 6922-P-10A/B from MCC.
14. Put Stripped Water Pumps 6922-P-10A/B LOR switch to ‘Remote’ at field control
panel.
15. Select Stripped Water Pumps 6922-P-10A as “DUTY” and 6922-P-10B as “STANDBY”
from the ICSS.
16. Ensure the minimum flow recycle line 2″ isolation valve is opened for the pump
6922-P-10A.
17. Start the “DUTY” pump 6922-P-10A from the ICSS.
18. Ensure that the pump rated discharge pressure 8.6 bara is reached by checking the
discharge pressure gauge 69-PG-1322.
19. Open the Sour/Stripped Water Exchanger 6922-E-01 shell inlet and outlet 2″
isolation valves.
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20. Open the Stripped Water Cooler 6922-E-02 inlet and outlet 2″ isolation valves.
21. Start the Stripped Water Cooler fan motors 6922-EM-02 AA/6922-EM-02 AB.
22. Line up 69-FV-1317 upstream and downstream isolation valves.
23. Slowly open 69-FV-1317 manually and line up the stripped water to the
Observation & Buffer Sump 6922-X-04.
24. Line up the analyser 69-AT-1302 in the stripped water line.
5.7.3
Lining up of Stripper Overhead Circulation Pump 6922-P-11A/B
1.
Line up start-up water through 69-LV-1325.
2.
Prime the Stripper Overhead Circulation Pump 6922-P-11A/B.
3.
Select the Pump 6922-P-11A as ‘DUTY’ and 6922-P-11B as ‘STANDBY’ from ICSS.
4.
Start the Stripper Overhead Circulation Pump 6922-P-11A.
5.
Take level controller 69-LIC-1325 in ‘AUTO’ with a set point of 50% and ensure the
control valve 69-LV-1325 is controlling the level at 50%.
6.
Take flow control valve 69-FV-1316 in ‘AUTO’ with a set point 13.2 m3/hr.
7.
Open the inlet and outlet isolation valves of the Stripper Overheads Cooler 6922-E-03.
8.
Start Stripper Overheads Cooler 6922-E-03AA/6922-E-03AB fans.
9.
Take 69-TIC-1315 in AUTO with a set point of 55°C.
5.7.4
Lining up of Sour Water Stripper overhead Sour Gas
1.
Ensure that 69-PV-1315A upstream and downstream isolation valves are closed.
2.
Reset ESD and ensure that the ON-OFF valve 69-XV-1313 is open.
3.
Ensure that the upstream and downstream isolation valves of 69-PSV-1303A are
lock open and the bypass valve is closed.
4.
Ensure that the upstream isolation valves of 69-PSV-1303B are lock closed and the
downstream isolation valves are open.
5.
Take 69-PIC-1315 in manual and close 69-PV-1315A fully.
6.
Ensure that 69-PV-1315B upstream and downstream isolation valves are open and
close 69-PV-1615 fully.
7.
Now put 69-PIC-1315 in Auto with a set point of 1.0 barg and take 69-PV-1315A/B
in Remote.
5.7.5
Pressurising Waste Water Degasser 6922-V-07 with Nitrogen
1.
Ensure that the Nitrogen inlet shut down valve 69-XV-1315 is opened after
resetting the ESD.
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2.
Close 69-PV-1307 fully on manual. Open the 69-PV-1307 upstream and downstream
isolation valves.
3.
Slowly open 69-PV-1307 in manual till the pressure in the Degasser and Stripper
reaches 1.0 barg and indicated by 69-PT-1307/1311/1315. Now put the controller
69-PIC-1307 in auto with a set point of 1.0 barg.
4.
Take 69-PIC-1315 in AUTO. Since the isolation valves of 69-PV-1315A are closed,
ensure that 69-PV-1315B opens when the pressure goes above 1.0 barg.
Line up 69-PV-1315A upstream and downstream isolation valves and line up sour
gas to TGTU.
5.7.6
Lining up of Sour Water Stripper Reboiler
1. Ensure that Sour Water Stripper Reboiler 6922-E-04 shell side is filled with sour
water by checking 69-LT-1317/69-LG-1307.
2. Ensure that the 2” isolation valves of the Steam line from the Reboiler Steam inlet
to the Reboiler vapour outlet line 2”-6848-LS-138-C12W-HC are closed.
3. Put steam inlet control valve 69-FV-1315 in manual and close it fully.
4. Ensure that after resetting ESD, steam inlet line ON/OFF valve 69-XV-1314 is open.
5. Open the 2″ vent valve in the steam inlet line to the reboiler and the condensate
outlet line from the reboiler.
6. Open the vents and drains in the Reboiler Condensate Drum 6922-V-09.
7. Open the 69-LV-1327 upstream drain and close the bypass valve.
8. Ensure that the steam inlet line is warmed up upstream of the 8” isolation valve
68-GV-1928 and steam is charged.
9. Open the 2” bypass valves of the flow control valve 69-FV-1315.
10. Open the steam inlet 2″ warm up valve upstream of 68-XV-1314 slowly and admit
steam into the Reboiler.
11. The Reboiler and the Reboiler Condensate Drum are warmed up by the steam and
the condensed steam starts to come out of the drains and vents.
12. When full flow of steam comes out of the drains and vents, close all the vents and
drains.
13. Close the 2″ steam inlet warm up bypass valve and open the steam inlet 8″ main
isolation valve slowly.
14. Open 69-FV-1315 manually by 10%.
15. Close the bypass valves of the 69-FV-1315.
16. Ensure the temperature of the vapour line from the Reboiler increases as the
steam flow is increased.
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17. When the temperature of the vapour line measured by 69-TT-1314 is increased to
120°C, put the steam flow controller 69-FIC-1315 in ratio control with the sour
water flow 69-FIC-1314.
18. Line up Boiler Feed Water to the Desuperheater 6922-X-01. Take the temperature
controller 69-TIC-1327 in AUTO with a set point of 148°C.
19. Ensure that the condensate level starts to increase in the Reboiler Condensate
Drum 6922-V-09 through 69-LG-1308/69-LT-1327.
20. Ensure that the low level alarm 69-LAL-1327 (set at 400 mm) is cancelled when the
level is rising in the Reboiler Condensate Drum 6922-V-09.
21. When the level in the drum reaches 50%, line up the level control valve 69-LV1327, put it on AUTO with a set point of 50%.
5.8
FLARE SYSTEM
Reference: P&ID No. 2970-6-51-0033
5.8.1
Start-up of LP Flare System
1.
Ensure that the isolation valve 62-BV-2211 is closed near the tie-in point T-18.
2.
Ensure that the following new LP Flare lines are purged with Nitrogen and are
under Nitrogen pressure:
•
10”-6236-FL-033-D14M from 62-PSV-176/176S
•
8”-6848-FL-036-C12P from Steam Generation Package 6848-A-02A/B/C
•
2”-6236-FL-053-D14M from 62-PV-1301A/B vents
•
6”-6236-FL-052-D14M from 62-PV-1303
•
2”-6236-BD-005-C14P-HI from LP Fuel Gas KO Drum 6236-V-05
3.
Ensure that the vent and drain valves in the new flare header is closed.
4.
Ensure that the spectacle blind in the new LP Flare header 10”-6236-FL-033-D14M
connecting with the existing header at tie-in point T-18 is in open position.
5.
Slowly open the 10” isolation valve in the new LP Flare header 10”-6236-FL-033D14M connecting with the existing header at tie-in point T-18.
6.
Line up 62-PV-1303 upstream and downstream isolation valves to LP Flare as
shown in P&ID.
7.
Line up 62-PSV-176/176S upstream and downstream isolation valves from LP Fuel
Gas KO Drum 6236-V-05 to LP Flare header as per requirement.
8.
Line up Steam Generation Package 6848-A-02A/B/C relief header 8”-6848-FL-036C12P to LP Flare header as per requirement.
9.
Line up the vent lines 2”-6236-FL-053-D14M from 62-PV-1301A/B to the new LP
flare header as per requirement.
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10. Line up the drain line 2”-6236-BD-005-C14P from new LP Fuel Gas KOD 6236-V-05
to the new LP flare header as per requirement.
11. Line up the drains and vents from the fuel gas system to LP Flare whenever
required by reversing the spectacle blind to open position and opening the drain/
vent valve as per requirement.
5.8.2
LP ACID GAS FLARE SYSTEM
Reference: P&ID No. 2970-6-50-0039
Start-up of LP Acid Gas Flare System
1.
Ensure that the LP Flare header isolation valve is closed near the tie-in point T-69.
2.
Ensure that the following new LP Acid Gas Flare lines are purged with Nitrogen
and are under Nitrogen pressure:
a. 2”-6236-FG-131-C12P purge fuel gas line to the Acid Gas Flare header
b. 20”-9103-AG-104-C14P from AGRU 1 & 2
c. 6”-6922-AL-064-C14P from 69-PSV-1303A/1303B
d. 2”-6922-AL-065-C14P from Sour Water Stripper 6922-C-01
e. 16”-9103-AL-117-C14P from Regenerator Reflux Drum 9103-V-12
f. 2”-9102-AG-116-A1C1 from sulphiding line of Hydrogenation Reactor 9102-V-11
g. 6”-9103-AL-110-C14P from Regenerator Reflux Drum 9103-V-12 PSV-1505/1506
h. 6”-9103-AL-101-C14P from Lean Acid Gas KO Drum 9103-V-14
i. 6”-9103-AL-104-C14P from Acid Gas Amine Absorber 9103-C-11 PSV-1503/1504
j. 14”-9101-AL-565-C14P from Acid Gas Pre-heater 9101-E-06 PSV-1071A/B
k. 2”-9136-FG-056-C12P from Incinerator Fuel Gas Skid 9101-E-06
l. 12”-9103-AL-107-C14P from Regenerator 9103-C-12 PSV-1508/1509
m. 6”-9102-AL-102-C14P
PSV-1303/1304.
from
Desuperheater/Contact
Condenser
9102-C-11
n. 8”-9102-AL-110-C14P from Tail Gas Amine Absorber 9102-C-12 PSV-1334/1346
o. 2”-9136-FG-202-C12P from Fuel Gas distribution
p. 20”-9103-AL-113-C14P Acid Gas flare header
3.
Slowly open the 20” isolation valve in the new LP Flare header 20”-9103-AL-113C14P connecting with the existing header at tie-in point T-069.
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4.
Reverse the 2”-6236-FG-131-C12P purge fuel gas line spectacle blind to open
position. Line up purge fuel gas to the Acid Gas Flare header as per requirement.
5.
Line up AGRU 1 & 2, 20”-9103-AG-104-C14P to Acid Gas flare as per requirement.
6.
Line up 69-PSV-1303A/1303B from the Sour Water Stripper 6922-C-01 to the new
LP Acid Gas flare header as per requirement.
7.
Line up 2”-6922-AL-065-C14P from Sour Water Stripper 6922-C-01 69-PV-1315B to
the new LP Acid Gas flare header as per requirement.
8.
Line up 16”-9103-AL-117-C14P from Regenerator Reflux Drum 9103-V-12 to the
new LP Acid Gas flare header as per requirement.
9.
Line up PSV-1505/1506 from Regenerator Reflux Drum 9103-V-12 to the new LP
Acid Gas flare header as per requirement.
10. Line up 6”-9103-AL-101-C14P from Lean Acid Gas KO Drum 9103-V-14 to the new
LP Acid Gas flare header as per requirement.
11. Line up 91-PSV-1503/1504 from Acid Gas Amine Absorber 9103-C-11 to the new LP
Acid Gas flare header as per requirement.
12. Line up 91-PSV-1071A/B from Acid Gas Pre-heater 9101-E-06 to the new LP Acid
Gas flare header as per requirement.
13. Line up 2”-9136-FG-056-C12P from Incinerator Fuel Gas skid 9101-E-06 to the new
LP Acid Gas flare header as per requirement.
14. Line up 91-PSV-1508/1509 from Regenerator 9103-C-12 to the new LP Acid Gas
flare header as per requirement.
15. Line up 91-PSV-1303/1304 from Desuperheater/Contact Condenser 9102-C-11 to
the new LP Acid Gas flare header as per requirement.
16. Line up 91-PSV-1334/1346 from Tail Gas Amine Absorber 9102-C-12 to the new LP
Acid Gas flare header as per requirement.
17. Line up 2”-9136-FG-202-C12P from fuel gas distribution to the new LP Acid Gas
flare header as per requirement.
18. Line up 20”-9103-AL-113-C14P Acid Gas flare header to the new LP Acid Gas flare
header as per requirement.
5.9
FUEL GAS SYSTEM
Line-up Fuel Gas from the Existing 1st Stage Booster Compressor 6701-K-10/
20/30 in NGL-3
5.9.1
1.
Ensure that the fuel gas inlet isolation valves to the new Steam Boiler Package
6848-A-02A/B/C are in closed position and the lines are under Nitrogen pressure of
0.5 barg.
2.
Ensure LP Fuel Gas KO Drum 6236-V-05 drain line isolation valve is closed.
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3.
Ensure Booster Compressor 6701-K-10/20/30 in NGL-3 is running.
4.
Ensure 62-PV-1301A/B & 62-PV-1302 control valves are closed manually and the
upstream and downstream isolation valves are closed.
5.
Ensure 62-XV-1301 in the fuel gas supply line from Booster Compressor 6701-K-10/
20/30 is open and the upstream isolation valve is closed.
6.
Ensure 62-XV-1302 in the back-up supply fuel gas from 6103-K-01 A/B is open and
the upstream isolation valve is closed.
7.
Ensure 62-XV-1303 in the back-up supply fuel gas from 30” existing line is open
and the upstream isolation valve is closed.
8.
Ensure 62-PV-1303 is closed in auto with a set point of 7.8 barg and its upstream
and downstream isolation valves are open.
9.
Ensure 62-PSV-176 inlet and outlet isolation valves are open and the bypass is
closed.
10. Ensure 62-PSV-176S inlet isolation valve is closed and outlet isolation valve is
open.
11. Ensure that the spectacle blind on fuel gas supply line from Booster Compressor
6701-K-10/20/30 is in open position.
12. Open the 6” isolation valve slowly from the Booster Compressor 6701-K-10/20/30
and pressurise the line up to 62-XV-1301 upstream isolation valve.
13. Open 62-XV-1301 upstream isolation valve slowly and gradually pressurise the line
up to 62-PV-1301A upstream isolation valve.
14. Open 62-PV-1301A bypass 3” isolation valves slowly and pressurise the fuel gas KO
Drum 6236-V-05 gradually up to 7.0 barg.
15. Close the 62-PV-1301A bypass 3” isolation valves.
16. Open the 62-PV-1301A downstream isolation valve.
17. Put 62-PIC-1301 in auto with a set point of 7.0 barg.
18. Open 62-PV-1303 upstream and downstream isolation valves.
19. Open the upstream and downstream isolation valves of 62-PV-1301B/1302.
5.10
SEA COOLING WATER SYSTEM
The start-up procedure for the Sea Cooling Water Pumps 6932-P-04A/B is given below:
5.10.1
Pre-start up checks
Before starting the pump the following checks should be made
1. Rotate the pump shaft by hand to make sure that the pump rotates freely and the
impellers are correctly positioned
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2.
The electric motor is properly lubricated
3.
Direction of Rotation of the motor is checked and marked
4.
Ensure all the piping connections are tight
5.
Check for foundation bolts tightness
6.
Check all bolting connections for tightness (coupling bolts, mechanical seal gland
bolts, driver bolts)
7.
Ensure the coupling guard is in place
5.10.2
5.11
Initial Starting and Lining Up of Sea Cooling Water
1.
Open the Sea Cooling Water Pump 6932-P-04A discharge MOV 69-MOV-1301 by 10%
2.
Start pre-lubrication liquid flow for the pump
3.
Start the pump and open the discharge MOV 69-MOV-1301 immediately within 30
seconds
4.
Observe the operation of the pump for any abnormal noise and vibration.
5.
Measure the pump shaft vibration and lube oil temperature at regular intervals.
6.
Line up sea cooling water to the header.
7.
Start Biocide Injection and Scale Inhibitor Injection as per section 5.12.3 and
5.12.4 and start injection of the chemicals.
8.
Line up sea cooling water to the following heat exchangers one by one by opening
the high point vents and releasing air.
•
Lean Amine Trim Cooler 9103-E-15
•
Regenerator Condenser Trim Cooler 9103-E-16
•
Contact Condenser Trim Cooler 9102-E-13A/B
•
Acid Gas Cooler 9103-E-101A/B
ELECTRO CHLORINATION PACKAGE START-UP
Control of the package is via Allen Bradley compact logix PLC located in the control
panel which also contains an HMI which provides facility for the operator to input
selections of duty and stand-by equipments and adjustments of system parameters in
addition to providing system of status, indications and alarms.
Both automatic and manual operation of the package is possible, but manual operation
is recommended only for maintenance purpose.
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Electro chlorination package switch details are listed below:
Sl. #
Tag No.
Service
1.
69-HSR-1480L
Local selector switch
2.
69-HSR-1480R
Remote selector switch
3.
69-HSOA-1451
Package start command from DCS
4.
69-HSCA-1451
Package stop command from DCS
5.
69-HS-1451
Package trip from UCP
6.
69-HS-1452
Package trip from field
7.
69-HS-1453
Package trip from field
8.
69-HSR-1470
Manual selected at transformer rectifier
9.
69-HSOA-1470
Transformer unit start
10.
69-HSCA-1470
Transformer unit stop
Control valve and ON-OFF valve details are tabulated below:
Sl. #
5.11.1
Tag No.
Description
1.
69-XV-1451
Auto back wash filter 69-S-03A valve
2.
69-XV-1454
Auto back wash filter 69-S-03B valve
3.
69-XV-1452
Auto back wash filter drain valve
4.
69-XV-1455
Auto back wash filter drain valve
5.
69-XV-1456
Auto back wash filter 69-S-03A discharge valve
6.
69-XV-1456
Auto back wash filter 69-S-03B discharge valve
7.
69-XV-1457
Electrolyser – A inlet valve
8.
69-XV-1458
Electrolyser – B inlet valve
Normal start-up of Electro Chlorination Plant:
Before starting the package, ensure the following emergency shutdown causes are
normal/healthy:
Sl. #
Tag No.
Description
1
69-HS-1451
Emergency stop in UCP
2
69-HS-1452
Emergency stop in ECP skid
3
69-HS-1453
Emergency stop in ECP skid
4
69-XS-1336
Sea cooling water pump (6932-P-04A/B) trip
5
66-GF-02-1801
Hydrogen gas high-high alarm
6
66-GF-02-1801
Hydrogen gas high-high alarm
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1.
Open the Electro chlorination I/L PCV 69-PCV-1463 upstream and downstream
isolation valves.
2.
Open Auto Backwash Filters 6932-S-03A/B inlet and outlet isolation valves.
3.
Open Electrolyser 6932-G-01A/B inlet and outlet isolation valves.
4.
Open Hydrogen Dilution Blowers 6932-K-01A/B discharge isolation valves.
5.
Ensure that Sea Cooling Water Pumps 6932-P-04A/B is started and running.
6.
Open Auto Backwash Filter inlet PCV 69-PCV-1463, manually and slowly fill up the
Sea Water Filter 6932-S-03A. Put 69-PCV-1463 in auto with a set point of 3.5 barg.
7.
Select ‘LOCAL’ for the unit start-up from UCP.
8.
Select Auto Backwash Filter 6932-S-03A as duty Filter from UCP.
9.
Select Electrolyser Stream 6932-G-01A as duty form UCP.
10. Select Dilution Blower 6932-K-01A as duty blower from UCP.
11. Select Dosing Pump 6932-P-05A as duty pump from UCP.
12. Press ‘start’ from UCP.
13. Ensure that system status indication changes to ‘starting’. Ensure that Start lamp
is flashing.
14. Ensure Auto Backwash Filter outlet XV, XV-1453 opens and sea water flow is
established through the filters.
15. Ensure that the duty dilution blower 6932-K-01A is started.
16. After a 30 second delay, Ensure that the Electrolyser inlet XV, XV-1457 is opened
and sea water flows through the Electrolyser.
17. Ensure that the Transformer/Rectifier 6932-TA-08A is energised after confirming the
flow through the Electrolyser with the help of Magnetic flow meter 69-FT-1451.
18. Ensure that the ‘system running’ indication is illuminated.
19. Ensure that the Sodium Hypochlorite generated is sent to the Degassing Tank
6932-T-02.
20. Ensure that the level in Degassing Tank 6932-T-02 starts rising.
21. Fill the Dosing Pump 6932-P-05A by opening the suction isolation valve and
releasing air through the casing vent valve.
22. Ensure that the Dosing Pump 6932-P-05A starts after the level reaches the low
alarm level of 924 mm measured by 69-LT-1452.
23. Ensure that Sodium Hypochlorite is continuously dosed at a rate of 7 m3/hr and
1.25 ppm concentration to the Sea Cooling Water by dosing pumps (6932-P05A/05B).
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24. Ensure that Sodium Hypochlorite is shock dosed at a rate of 11 m3/hr and 6 ppm
concentration for 15 minutes in every 6 hours by dosing pumps (6932-P-05A/05B).
25. Ensure that the following indications are healthy
a. Autoback wash Filter Outlet Pressure Status Healthy
b. Autoback wash Filter 6932-S-03A/B Status Healthy
c. Electrolyser 6932-G-01A/B inlet flow healthy
d. Electrolyser Inlet Temperature Healthy
e. Hydrogen Blower Outlet Pressure Status Healthy
f. Transformer/Rectifier 6932-RC-101A/B Healthy.
26. Ensure that the time for START-UP is 5 minutes.
Manual start-up of electro chlorination package:
1. Manual operation is provided for maintenance and commissioning purposes only.
2. Select the Auto/Manual switch to manual mode in UCP HMI for manual start of
ECP.
3. Following manual controls are available:
5.12
5.12.1
•
Manual operation of each actuated on/off valve (69-XV-1457/69-XV-1458), (69XV-1453/69-XV-1456), (69-XV-1452/69-XV-1455) via a manual override facility,
mounted on the valve
•
Flow control valve (69-FV-1453) which regulates the flow of sodium
hypochlorite dosing to sea water can be operated by flow controller in UCP
manually
•
Dilution blowers, dosing pumps and transformer rectifiers can be operated
manually by selecting local mode at RCU in the field
•
Manual operation of each Transformer/Rectifier (6932-RC-101A/6932-RC-101B)
can be done via local start/stop push buttons (69-HSOA-1470/69-HSCA-1470), by
selecting manual button (69-HSR-1470) mounted on the front panel of each T/R.
CHEMICAL INJECTION SYSTEM
Complex Product Injection Package (6834-A-09)
Fill the Complex Product Tank, 68-T-18 with Complex Product Chemical.
WARNING: REVIEW THE COMPLEX PRODUCT MSDS AND ENSURE THAT
APPROPRIATE SAFETY MEASURES ARE TAKEN BEFORE HANDLING THE
CHEMICAL.
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1. Ensure that the Complex Product Inhibitor Tank, 68-T-18 is clean and dry for
charging chemicals.
2. Line up the Complex Product Unloading Pump (6834-P-42) (Pneumatic driven) with
chemical Tote Tank through the pump suction line and open isolation valve on the
suction line.
3. Check plant air pressure and line up air to the unloading pump.
4. Open the isolation valve on the tank fill line and start Complex Product Unloading
Pump (6834-P-42) and start filling the tank. Check all connections and confirm that
there is no leakage.
5. Vent the instruments and line up for operation.
6. Monitor the level from the ICSS as the level increases. Ensure that the low low
level, 68-LALL-1316 and the low-level alarm, 68-LAL-1317 are reset at their
respective set point.
7. Fill the tank up to its maximum operating level, stop the chemical unloading pump
(6834-P-42) by closing the plant air isolation valve and close the isolation valve on
the fill line. Close the isolation valve on the pump suction line.
8. Open the Complex Product Injection Pump, 68-P-41A/B manual suction valve and
fill the pumps.
9. Open pump discharge valve and close valve at injection point and upstream drain
valve.
10. Set the stroke adjuster of the Complex Product Injection Pump, 68-P-41A/B to 10%.
11. Start the pump and check for flow at the injection point drain valve. Then stop the
pump.
12. The system is now ready for start-up. The manual stroke is later adjusted to the
desired injection rate based on the actual chemical requirement at the injection
points.
5.12.2
Oxygen Scavenger Injection Package (6834-A-09)
Fill the Oxygen Scavenger Storage Tank, 6834-T-17 with Oxygen Scavenger Chemical.
WARNING: REVIEW THE OXYGEN SCAVENGER MSDS AND ENSURE
THAT APPROPRIATE SAFETY MEASURES ARE TAKEN BEFORE
HANDLING THE CHEMICAL.
1. Ensure that the Oxygen Scavenger Storage Tank, 6834-T-17 is clean and dry for
charging chemicals.
2. Line up the Oxygen Scavenger Unloading Pump (6834-P-40) (Pneumatic driven) with
chemical Tote Tank through the pump suction line and open isolation valve on the
suction line.
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3. Check plant air pressure and line up air to the unloading pump.
4. Open the isolation valve on the tank fill line and start Oxygen Scavenger Transfer
Pump (6834-P-40) and start filling the tank. Check all connections and confirm that
there is no leakage.
5. Vent the instruments and line up for operation.
6. Monitor the level from the ICSS as the level increases. Ensure that the low low
level trip, 68-LALL-1314 and the low-level alarm, 68-LAL-1315 are reset at their
respective set point.
7. Fill the tank up to its maximum operating level, stop the chemical unloading pump
(6834-P-42) by closing the plant air isolation valve and close the isolation valve on
the fill line. Close the isolation valve on the pump suction line.
8. Open the Oxygen Scavenger Injection Pump, 68-P-39A/B manual suction valve and
fill the pumps.
9. Open pump discharge valve and close valve at injection point and upstream drain
valve.
10. Set the stroke adjuster of the Oxygen Scavenger Injection Pump, 68-P-39A/B to
10%.
11. Start the pump and check for flow at the injection point drain valve. Then stop the
pump.
12. The system is now ready for start-up. The manual stroke is later adjusted to the
desired injection rate based on the actual chemical requirement at the injection
points.
5.12.3
Biocide Injection Package (6932-A-06)
Filling the Biocide Tank, 6932-T-04 with Biocide Chemical
WARNING: REVIEW THE BIOCIDE MSDS AND ENSURE THAT
APPROPRIATE SAFETY MEASURES ARE TAKEN BEFORE HANDLING
ANY CHEMICAL.
1. Ensure that the Biocide Tank, 6932-T-04 is clean and dry for charging chemicals.
2. Line up the Biocide Unloading Pump (6932-P-08) (Pneumatic driven) with chemical
Tote Tank through the pump suction line and open isolation valve on the suction
line.
3. Check plant air pressure and line up air to the unloading pump.
4. Open the isolation valve on the tank fill line and start Biocide Unloading Pump
(6932-P-08) by opening the plant air isolation valve to the pump and start filling
the tank. Check all connections and confirm that there is no leakage.
5. Line up instruments for operation.
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6. Monitor the level from the ICSS as the level increases. Ensure that the low low
level trip, 69-LALL-1329 and the low-level alarm, 69-LAL-1328 are reset at their
respective set point.
7. Fill the tank up to its maximum operating level, stop the Biocide Unloading Pump
(6932-P-08) by closing the plant air isolation valve and close the isolation valve on
the fill line. Close the isolation valve on the pump suction line.
8. Open the Biocide Injection Pump, 6932-P-07A/B manual suction valves and fill the
pumps.
9. Open pump discharge valve and close valve at injection point and upstream drain
valve.
10. Set the stroke adjuster of the Biocide Injection Pump, 6932-P-07A/B to 10%.
11. Start the pump and check for flow at the injection point drain valve. Then stop the
pump.
12. The system is now ready for start-up. The manual stroke is later adjusted to the
desired injection rate based on the actual chemical requirement at the injection
points.
5.12.4
Scale Inhibitor Injection Package (6932-A-07)
Filling the Scale Inhibitor Tank 6932-T-05 with Scale Inhibitor Chemical
WARNING: REVIEW THE SCALE INHIBITOR MSDS AND ENSURE THAT
APPROPRIATE SAFETY MEASURES ARE TAKEN BEFORE HANDLING ANY
CHEMICAL.
1. Ensure that the Scale Inhibitor Tank, 6932-T-05 is clean and dry for charging
chemicals.
2. Line up the Scale Inhibitor Unloading Pump (6932-P-10) (Pneumatic driven) with
chemical Tote Tank through the pump suction line and open isolation valve on the
suction line.
3. Check plant air pressure and line up air to the unloading pump.
4. Open the isolation valve on the tank fill line and start Scale Inhibitor Transfer
Pump (6932-P-10) by opening the plant air isolation valve to the pump and start
filling the tank. Check all connections and confirm that there is no leakage.
5. Vent the instruments and line up for operation.
6. Monitor the level from the ICSS as the level increases. Ensure that the low low
level trip, 69-LALL-1331 and the low-level alarm, 69-LAL-1330 are reset at their
respective set points.
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7. Fill the tank up to its maximum operating level, stop the Scale Inhibitor Unloading
Pump (6932-P-10) by closing the plant air isolation valve and close the isolation
valve on the fill line. Close the isolation valve on the pump suction line.
8. Open the Scale Inhibitor Injection Pump, 6932-P-09A/B manual suction valves and
fill the pumps.
9. Open pump discharge valve and close valve at injection point and upstream drain
valve.
10. Set the stroke adjuster of the Scale Inhibitor Injection Pump, 6932-P-09A/B to 10%.
11. Start the pump and check for flow at the injection point drain valve. Then stop the
pump.
12. The system is now ready for start-up. The manual stroke is later adjusted to the
desired injection rate based on the actual chemical requirement at the injection
points.
5.12.5
Catalyst Injection Package (9101-A-01)
Filling the Catalyst Tank 9101-T-09 with Aquisulf Catalyst Chemical
WARNING: REVIEW THE CATALYST MSDS AND ENSURE THAT
APPROPRIATE SAFETY MEASURES ARE TAKEN BEFORE HANDLING ANY
CHEMICAL.
1. Ensure that the Catalyst Tank, 9101-T-01 is clean and dry for charging chemicals.
2. Line up the Catalyst Unloading Pump (9101-P-12) (Pneumatic driven) with chemical
Tote Tank through the pump suction line and open isolation valve on the suction
line.
3. Check plant air pressure and line up air to the unloading pump.
4. Open the isolation valve on the tank fill line and start Catalyst Unloading Pump
(9101-P-12) by opening the plant air isolation valve to the pump and start filling
the tank. Check all connections and confirm that there is no leakage.
5. Vent the instruments and line up for operation.
6. Monitor the level from the ICSS as the level increases. Ensure that the low low
level trip, 91-LALL-1128 and the low-level alarm, 91-LAL-1127 are reset at their
respective set points.
7. Fill the tank up to its maximum operating level, stop the chemical transfer pump
(9101-P-12) by closing the plant air isolation valve and close the isolation valve on
the fill line. Close the isolation valve on the pump suction line.
8. Open the Catalyst Injection Pump, 9101-P-11A/B suction isolation valves and fill
the pumps.
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9. Open pump discharge valve and close valve at injection point and upstream drain
valve.
10. Set the stroke adjuster of the Catalyst Injection Pump, 9101-P-11A/B to 10%.
11. Start the pump and check for flow at the injection point drain valve. Then stop the
pump.
12. The system is now ready for start-up. The manual stroke is later adjusted to the
desired injection rate based on the actual chemical requirement at the injection
points.
5.12.6
Antifoam Injection Package (9103-A-11)
Fill the Antifoam Tank, 9103-T-12 with Antifoam Chemical
WARNING: REVIEW THE ANTIFOAM MSDS AND ENSURE THAT
APPROPRIATE SAFETY MEASURES ARE TAKEN BEFORE HANDLING ANY
CHEMICAL.
1. Ensure that the Antifoam Tank, 9103-T-12 is clean and dry for charging chemicals.
2. Line up the Antifoam Unloading Pump (9103-P-19) (Pneumatic driven) with
chemical Tote Tank through the pump suction line and open isolation valve on the
suction line.
3. Check plant air pressure and line up air to the unloading pump.
4. Open the isolation valve on the tank fill line and start Antifoam Unloading Pump
(9103-P-19) by opening the plant air isolation valve to the pump and start filling
the tank. Check all connections and confirm that there is no leakage.
5. Vent the instruments and line up for operation.
6. Monitor the level from the ICSS as the level increases. Ensure that the low low
level trip, 91-LALL-1520 and the low-level alarm, 91-LAL-1521 are reset at their
respective set points.
7. Fill the tank up to its maximum operating level, stop the Antifoam Unloading Pump
(9103-P-19) by closing the plant air isolation valve and close the isolation valve on
the fill line. Close the isolation valve on the pump suction line.
8. Open the Antifoam Injection Pump, 9103-P-16A/B suction valves and fill the
pumps.
9. Open pump discharge valve and close valve at injection point and upstream drain
valve.
10. Set the stroke adjuster of the Antifoam Injection Pump, 9103-P-16A/B to 10%.
11. Start the pump and check for flow at the injection point drain valve. Then stop the
pump.
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12. The system is now ready for start-up. The manual stroke is later adjusted to the
desired injection rate based on the actual chemical requirement at the injection
points.
5.12.7
Corrosion Inhibitor Injection Package (9103-A-12)
Filling the Corrosion Inhibitor Tank, 9103-T-13 with Corrosion Inhibitor Chemical.
WARNING: REVIEW THE CORROSION INHIBITOR MSDS AND ENSURE
THAT APPROPRIATE SAFETY MEASURES ARE TAKEN BEFORE
HANDLING ANY CHEMICAL.
1. Ensure that the Corrosion Inhibitor Tank, 9103-T-13 is clean and dry for charging
chemicals.
2. Line up the Corrosion Inhibitor Unloading Pump (9103-P-102) (Pneumatic driven)
with chemical Tote Tank through the pump suction line and open isolation valve on
the suction line.
3. Check plant air pressure and line up air to the unloading pump.
4. Open the isolation valve on the tank fill line and start Corrosion Inhibitor Unloading
Pump (9103-P-102) by opening the plant air isolation valve to the pump and start
filling the tank. Check all connections and confirm that there is no leakage.
5. Vent the instruments and line up for operation.
6. Monitor the level from the ICSS as the level increases. Ensure that the low low
level trip, 91-LALL-1522 and the low-level alarm, 91-LAL-1523 are reset at their
respective set points.
7. Fill the tank up to its maximum operating level, stop the Corrosion Inhibitor
Unloading Pump (9103-P-102) by closing the plant air isolation valve and close the
isolation valve on the fill line. Close the isolation valve on the pump suction line.
8. Open the Corrosion Inhibitor Injection Pump, 9103-P-101A/B suction valves and fill
the pumps.
9. Open pump discharge valve and close valve at injection point and upstream drain
valve.
10. Set the stroke adjuster of the Corrosion Inhibitor Injection Pump, 9103-P-101A/B to
10%.
11. Start the pump and check for flow at the injection point drain valve. Then stop the
pump.
12. The system is now ready for start-up. The manual stroke is later adjusted to the
desired injection rate based on the actual chemical requirement at the injection
points.
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5.12.8
Caustic Injection Package (9103-A-13)
Filling the Caustic Storage Tank, 9103-T-14 with Caustic
WARNING: REVIEW THE CAUSTIC MSDS AND ENSURE THAT
APPROPRIATE SAFETY MEASURES ARE TAKEN BEFORE HANDLING ANY
CHEMICAL.
1. Ensure that the Caustic Storage Tank, 9103-T-14 is clean and dry for charging
chemicals.
2. Line up the Caustic Unloading Pump (9103-P-104) (Pneumatic driven) with chemical
Tote Tank through the pump suction line and open isolation valve on the suction
line.
3. Check plant air pressure and line up air to the unloading pump.
4. Open the isolation valve on the tank fill line and start Caustic Unloading Pump
(9103-P-104) by opening the plant air isolation valve to the pump and start filling
the tank. Check all connections and confirm that there is no leakage.
5. Vent the instruments and line up for operation.
6. Monitor the level from the ICSS as the level increases. Ensure that the low low
level trip, 91-LALL-1524 and the low-level alarm, 91-LAL-1525 are reset at their
respective set points.
7. Fill the tank up to its maximum operating level, stop the Caustic Unloading Pump
(9103-P-104) by closing the plant air isolation valve and close the isolation valve on
the fill line. Close the isolation valve on the pump suction line.
8. Open the Caustic Injection Pump, 9103-P-103A/B manual suction valves and fill the
pumps.
9. Open pump discharge valve and close valve at injection point and upstream drain
valve.
10. Set the stroke adjuster of the Caustic Injection Pump, 9103-P-103A/B to 10%.
11. Start the pump and check for flow at the injection point drain valve. Then stop the
pump.
12. The system is now ready for start-up. The manual stroke is later adjusted to the
desired injection rate based on the actual chemical requirement at the injection
points.
5.13
5.13.1
DEMINERALIZED WATER SYSTEM
Demineralized Water Unit Start-up
Demineralized Water Unit (2 trains) is designed for automatic operation via unit
control panel which contains Siemens S7-400 PLC. All the alarms, indications and
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status signals generated within the package are transmitted from package UCP to DCS
through serial link (modbus through TCP/IP).
The list of switches used in the operation of DM water package is tabulated below:
Sl. #
Tag No.
Train-A
Train-B
Service
1.
68-HS-1840 A
68-HS-1840 B
Auto/Man/Off selector-Auto
2.
68-HS-1841 A
68-HS-1841 B
Auto/Man/Off selector-Manual
3.
68-HS-1843 A
68-HS-1843 B
Auto/Man/Off selector-off
4.
68-HS-1842 A
68-HS-1842 B
Step advance push button
5.
68-HSOA-1845 A
68-HSOA-1845B
Remote start from DCS
6.
68-HSCA-1845 A
68-HSCA-1845B
Remote stop from DCS
The list of ON/OFF valves is tabulated below:
Sl. #
Tag No.
Train-A
Train-B
Service
1.
68-XV-1825
68-XV-1840
Cation Exchanger Inlet
2.
68- XV-1831
68-XV-1846
Cation Exchanger outlet
3.
68-XV-1833
68-XV-1848
Anion Exchanger inlet
4.
68-XV-1838
68-XV-1852
Anion Exchanger outlet
5.
68- XV-1856
68-XV-1855
DM Water common header inlet
6.
68-XV-1832
68-XV-1847
AE-1825 pH Analyzer inlet
7.
68-XV-1839
68-XV-1853
AE-1826 Conductivity Analyzer inlet
8.
68-XV-1830
68-XV-1844
HCL drain to pit
9.
68-XV-1837
68-XV-1851
NaOH drain to pit
10.
68-XV-1828
68-XV-1843
DM+HCL inlet to cationic exchanger
11.
68-XV-1835
68-XV-1854
DM+ NaOH inlet to anionic
exchanger
12.
68-XV-1829
68-XV-1845
Regeneration inlet to cationic
exchanger
13.
68-XV-1836
68-XV-1850
Regeneration inlet to anionic
exchanger
14.
68-XV-1826
68-XV-1841
Recycle water to cation exchanger
15.
68-XV-1827
68-XV-1842
Cation exchanger to neutralization
pit
16.
68-XV-1834
68-XV-1849
Anion exchanger to neutralization
pit
17.
68-XV-1857
Neutralization pump discharge
18.
68-XV-1858
Neutralization pump recycle
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The list of Pumps is tabulated below:
Sl. #
1.
Tag No.
Train-A
6834-P-37A
Service
Train-B
6834-P-37B
Recycling pump
2.
6834-P-34A/B/C
NaOH dosing pump
3.
6834-P-35A/B/C
HCL dosing pump
4.
6834-P-36A/B
Regeneration pump
5.
6834-P-38A/B
Neutralization pump
The operational status of the package is indicated by the following signals:
Sl. #
Tag No.
Train-A
Service
Train-B
1.
68-XL-1840A
68-XL-1840B
Package working in auto mode
2.
68-XL-1841A
68-XL-1841B
Package working in manual mode
3.
68-XL-1843A
68-XL-1843B
Package is in offline
4.
68-XL-1850A
68-XL-1850B
service phase
5.
68-XL-1851A
68-XL-1851B
waiting regeneration phase
6.
68-XL-1852A
68-XL-1852B
Acid regeneration/caustic
regeneration
7.
68-XL-1853A
68-XL-1853B
Acid slow rinse/caustic slow rinse
8.
68-XL-1854A
68-XL-1854B
caustic slow rinse
9.
68-XL-1855A
68-XL-1855B
Final rinse with recirculation
10.
68-XL-1856A
68-XL-1856B
Waiting ready phase
11.
68-XL-1857A
68-XL-1857B
Pre-service phase
12.
68-UA-1844
Irregular valves/pumps position
13.
68-XL-1858
Neutralization
14.
68-XL-1859
Effluent discharge
15.
68-XL-1860
Neutralization recirculation
16.
68-XL-1861
Neutralization standby
Startup of the Demineralized Water System
1.
Put the AUTO/MANUAL/OFF selector in UCP in MANUAL position for Train-A
(68-HS-1841A).
2.
Put the AUTO/MANUAL/OFF selector in UCP in MANUAL position for Train-B
(68-HS-1841B).
3.
Put the LOR selector of all the pumps in ‘Remote’ and select the duty and standby
pumps in UCP and put them in auto.
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4.
Put the Train-A in ‘SERVICE’ mode (Phase No. 1) by pressing the Step Advance
push button 68-HS-1842A in the UCP once.
5.
Ensure that the following valves are open in Train–A:
a.
68-XV-1825
b.
68-XV-1831
c.
68-XV-1833
d.
68-XV-1854
e.
68-XV-1830
f.
68-XV-1837
g.
68-XV-1832
6. Now Train A is on line.
7. Put Train B in ‘WAITING READY’ mode (Phase No. 7) by pressing the Step Advance
push button 68-HS-1842B in the UCP.
8. Ensure that the following valves in Train-B are open:
a.
68-XV-1844
b.
68-XV-1851
9. Ensure that drinking water is available in the existing Drinking Water Storage Tanks
6834-T-01A/B.
10. Open the isolation valve from the existing Drinking water storage tank 6834-T-01A
to the new Drinking Water Pumps 6834-P-23A/B slowly and fill up the suction lines
of the pumps.
11. Prime the Drinking Water Pumps 6834-P-23A/B by opening the casing vents and
releasing air.
12. Put the LOR switch of the Drinking Water Pump 6834-P-23A in ‘LOCAL’ position.
13. Start the Drinking Water Pump 6834-P-23A on recirculation, gradually open the
discharge valve and slowly pressurize the Demineralized Water Unit Train A.
14. Ensure 68-LCV-1827 is lined up and it is fully open on manual.
15. Ensure the Demineralized Water Storage Tank 6834-T-08 water level is raising.
16. When the level is 30% in the storage tank, take 68-LCV-1827 in auto with a set
point of 70%.
17. After stabilising the unit, put the AUTO/MANUAL/OFF selector in UCP in AUTO for
both A & B trains.
18. Prime the Recycling and Regeneration pumps.
19. Prepare HCl (33%) and Caustic solutions (50%).
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5.13.2
Demineralized Water Unit Sequence
A. Phase No. 1: Service
1.
Ensure that when put in service the following XVs of Train-A are open:
a.
68-XV-1825: Cation Exchanger I/L
b.
68-XV-1831: Cation Exchanger O/L
c.
68-XV-1833: Anion Exchanger I/L
d.
68-XV-1838: Anion Exchanger O/L
e.
68-XV-1856: Demin. Water common header I/L
f.
68-XV-1832: AE-1825 pH Analyzer I/L
g.
68-XV-1839: AE-1826 Conductivity Analyzer I/L
h.
68-XV-1830: HCl drain line
i.
68-XV-1837: NaOH drain line
2. Ensure that 68-FIC-1825 is on line and the flow rate through the train is 7 m3/hr.
3. Ensure that Train A is in line for a through put of 168 m3 (=24 hours @ 7 m3/hr)
measured by the flow totaliser 68-FQI-1825 or until the high conductivity 68-AAH1829 measured by the Analyzer 68-AI-1829.
4. Ensure that Train A is transferred to Phase No. 2 ‘Waiting Regeneration’ mode
after step 3.
5. Ensure that the high conductivity alarm is ON if 68-AAH-1829 is ON for 5 minutes.
6. Ensure that this service phase is terminated if 68-AAH-1829 is ON for additional 30
minutes.
B.
1.
Phase No. 2: Waiting Regeneration
Ensure that the following XVs are open in this phase:
a.
68-XV-1830
b.
68-XV-1837
2. Ensure that the following conditions do not exist:
a.
Acid Level Low (68-LAL-1825)
b.
Caustic Level Low (68-LAL-1827)
3. Ensure that the following alarms are not present:
a.
Irregular valve position alarm 68-UA-1844
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b.
Both Regeneration Pumps unavailable
c.
Dosing Pumps unavailable
4. Ensure that this phase duration is 2 minutes.
C.
1.
Phase No. 3: Acid Regeneration/Caustic Regeneration
Ensure that the following XVs are open:
a.
68-XV-1829
b.
68-XV-1828
c.
68-XV-1827
d.
68-XV-1836
e.
68-XV-1835
f.
68-XV-1834
2. Ensure that Acid Dosing Pump 6834-P-35A/B/C is started and dosing 174 litres/
hour of acid for regeneration.
3. Ensure that Caustic Dosing Pump 6834-P-34A/B/C is started and dosing 126 litres/
hour of caustic for regeneration.
4. Ensure that Regeneration Pump 6834-P-36 A/B is started and supplies 1173 litres/
hour of dilution water for acid regeneration and 2300 litres/hour of dilution water
for caustic regeneration.
5. Ensure that the following control valves are in line to control the dilution water to
the acid and caustic dosing systems:
a.
68-FIC-1835 in auto with a set point of 2175 litres/hour
b.
68-FIC-1836 in auto with a set point of 1000 litres/hour
6. Ensure that the Neutralisation Pit Pump 6834-P-38 A/B starts when the level in the
Neutralisation Pit rises to high level 68-LAH-1831.
7. Ensure that the duration of this regeneration phase is 25 minutes.
D.
1.
Phase No. 4: Acid Slow Rinse/Caustic Slow Rinse
Ensure that the following XVs are open:
a.
68-XV-1830
b.
68-XV-1837
c.
68-XV-1827
d.
68-XV-1836
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e.
68-XV-1835
f.
68-XV-1834
g.
68-XV-1828
h.
68-XV-1829
2. Ensure that the Regeneration Pump 6834-P-36 A/B is started and supplies 1000
litres/hour to the Cationic Exchanger 6834-S-21A and 2175 litres/hour to the
Anionic Exchanger 6834-S-22A for rinsing.
3. Ensure that the controllers 68-FIC-1835 and 68-FIC-1836 are inline.
4. Ensure that the rinsing duration is 54 minutes.
E.
1.
Phase No. 5: Caustic Slow Rinse
Ensure that the following XVs are open:
a.
68-XV-1837
b.
68-XV-1836
c.
68-XV-1835
d.
68-XV-1834
2. Ensure that the Regeneration Pump 6834-P-36 A/B is started and supplies 2175
litres/hour to the Anionic Exchanger 6834-S-22A for rinsing.
3. Ensure that the controller 68-FIC-1835 is online.
4. Ensure that the rinsing duration is 29 minutes.
F.
1.
Phase No. 6: Final Rinse with Recirculation
Ensure that the following XVs are open:
a.
68-XV-1831
b.
68-XV-1833
c.
68-XV-1826
d.
68-XV-1839
2. Ensure that the Recirculation Pump 6834-P-37 A is started and recirculates
10 m3/hour water through the cationic and anionic exchangers
3. Ensure that the rinsing duration is 30 minutes.
4. Ensure that after 30 minutes of rinsing, 68-AAH-826 alarm is OFF.
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5. Ensure that if the alarm 68-AAH-826 is ON after 30 minutes of recirculation, the
Regeneration Failure alarm starts and the final rinse with recirculation phase
continues until 68-AAH-826 is OFF.
G.
Phase No. 7: Waiting Ready
Ensure that the following XVs are open:
a.
68-XV-1830
b.
68-XV-1837
H.
1.
Phase No. 8: Pre-service Recirculation
Ensure that the following XVs are open:
a.
68-XV-1831
b.
68-XV-1833
c.
68-XV-1826
d.
68-XV-1839
e.
68-XV-1838
f.
68-XV-1830
g.
68-XV-1837
2. Ensure that the Recirculation Pump 6834-P-37 A is started and circulates 10 m3/hr
water through the system.
3. Ensure that the duration of this phase is 10 minutes.
4. Ensure that the high conductivity 68-AAH-1826 alarm is not present at the end of
the duration of this phase.
5. Ensure that if the alarm 68-AAH-1826 is present, then the Pre-service circulation
continues till the alarm is cancelled.
5.13.3
Neutralization Pit
The waste water generated during regeneration of the Demineralized Plant is
collected in the Neutralization Pit (6834-T-014). Once the level reaches the required
level, ensure the following 4 Phases to pump out the effluent.
A. Phase No. P1: Waiting Ready
1.
Check of conditions for recirculation.
2.
Check the level 68-LT-1831/68-LT-1830 in Neutralization Pit 6834-A-01.
3.
Ensure duration of this phase is 1 minute.
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4.
Activation of level alarm 68-LAH-1831 in pit leads to phase No. P2. Recirculation
B. Phase No. P2: Recirculation
1.
Ensure that the Neutralization Pit Pump 6834-P-38 A/B starts at 68-LAH-1831.
2.
Ensure that 68-XV-1858 is open.
3.
Ensure that 68-XV-1857 is closed.
4.
Ensure the duration of this phase is 15 minutes.
5.
At the end of re-circulation time if pH is within range, then discharge phase 4
starts.
C. Phase No. P3: Neutralization
1.
Ensure that the Neutralization Pit Pump 6834-P-38 A/B starts at LAH-1831.
2.
Ensure that 68-XV-1858 is open.
3.
Ensure that 68-AAH-1831 (pH is more than 9) starts Acid Dosing Pumps 6834-P-35C.
4.
Ensure that 68-AAL-1831 (pH is less than 6) starts Caustic Dosing Pumps 6834-P34C.
5.
Activation of low low alarm 68-LALL-1830 in neutralization pit trips the
neutralization, acid and caustic dosing pumps.
D. Phase No. P4: Effluents Discharge
1.
Ensure that the Neutralization Pit Pump 6834-P-38 A/B starts discharging effluents
when pH analyzer 68-AI-1831 is in the range (pH: 6-9) for more than 5 minutes.
2.
Ensure that 68-XV-1857 is open.
3.
Ensure that the Neutralization Pit Pump 6834-P-38 A/B stops at low level alarm
level of the pit 68-LAL-1831.
4.
By simulating 68-LALL-1830 check the trip signal of Neutralization Pit Pump 6834P-38 A/B in MCC.
Operator can abort Manual Step-by-Step mode and continue operating in Automatic
Mode by simply putting the AUTO/MAN/OFF selectors in AUTO position. The sequence
will continue operating from last selected phase during Step-by-Step mode.
Details of ON/OFF valve positions against the respective phase are tabulated below:
Tag No.
Demineralization - Phase Number
Neutralization Phase Number
1
Train “A”
Train “B”
1
2
3
4
5
6
7
8
68-XV-1825
68-XV-1840
O
C
C
C
C
C
C
C
68- XV-1831 68-XV-1846
O
C
C
C
C
O
C
O
68-XV-1833
O
C
C
C
C
O
C
O
68-XV-1848
2
3
4
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Tag No.
Demineralization - Phase Number
Neutralization Phase Number
1
2
3
4
Train “A”
Train “B”
1
2
3
4
5
6
7
8
68-XV-1838
68-XV-1852
O
C
C
C
C
O
C
O
68- XV-1856 68-XV-1855
O
C
C
C
C
C
C
C
68-XV-1832
68-XV-1847
O
C
C
C
C
C
C
C
68-XV-1839
68-XV-1853
O
C
C
C
C
O
C
O
68-XV-1830
68-XV-1844
O
O
C
O
O
O
O
O
68-XV-1837
68-XV-1851
O
O
C
O
O
O
O
O
68-XV-1828
68-XV-1843
C
C
O
O
C
C
C
C
68-XV-1835
68-XV-1854
C
C
O
O
O
C
C
C
68-XV-1829
68-XV-1845
C
C
O
O
C
C
C
C
68-XV-1836
68-XV-1850
C
C
O
O
O
C
C
C
68-XV-1826
68-XV-1841
C
C
C
C
C
O
C
O
68-XV-1827
68-XV-1842
C
C
O
O
O
C
C
C
68-XV-1834
68-XV-1849
C
C
O
O
O
C
C
C
68-XV-1857
C
C
C
C
C
C
C
C
C
C
C
O
68-XV-1858
C
C
C
C
C
C
C
C
C
O
O
C
Details of pump status against the respective phase are tabulated below:
Pump Tag No.
Train “A”
6834-P-37A
Train “B”
Demineralization - Phase Number
1
2
3
4
5
6834-P-37B ON
6834-P-34A
6834-P-34B
ON
6834-P-35B
6834-P-36B
6834-P-38A
6834-P-38B
8
1
2
3
4
ON
ON
ON
ON
6834-P-35C
6834-P-36A
7
ON
6834-P-34C
6834-P-35A
6
Neutralization Phase Number
ON ON ON
ON ON ON
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5.14
BOILER FEED WATER DEAERATOR SYSTEM
5.14.1
Lining up of Steam Condensate Flash Drum 6834-V-05
1.
Open the 2” drum vent isolation valve to atmosphere.
2.
Open the 2” drain valve from the Steam Condensate Flash Drum 6834-V-05.
3.
Open the 12” Condensate Distribution Header isolation valves at battery limit and
near the Steam Condensate Flash Drum 6834-V-05 slowly and introduce
condensate from condensate distribution header and warm up the Steam
Condensate Flash Drum 6834-V-05.
4.
Ensure enough time is given for the warming up of the drum and then open the
condensate header isolation valves fully.
5.
Close the 2” drain valve from the Steam Condensate Flash Drum 6834-V-05.
6.
Ensure that low low level trip 68-LALL-1309 is cancelled when the water level is
rising.
7.
Ensure that low level alarm 68-LAL-1301 is cancelled when the level is rising in the
drum.
8.
Ensure that the level in the drum is rising by checking the level transmitter 68-LT1301/1308/68-LG-1303.
9.
When the level is around 50%, close the condensate inlet isolation valve near the
drum.
10. Open the Deaerator Feed Pumps 6834-P-20A/B suction isolation valves and the
common suction line isolation valve and warm up the pumps by opening the casing
vent isolation valves.
11. Prime the pumps by opening the casing vent isolation valves and releasing air.
12. Ensure that the Deaerator Package 6834-A-08 inlet isolation valves from the
Deaerator Feed Pumps 6834-P-20A/B discharge is closed.
13. Open the Steam Condensate Coolers fans 6834-E-02A/B/C inlet and outlet
isolation valves.
14. Line up condensate from Steam Condensate Cooler 6834-E-02 to Steam
Condensate Flash Drum 6834-V-05 isolation valve.
15. Open the discharge valve of Deaerator Feed Pump 6834-P-20A.
16. Open the minimum flow control valve 68-FV-1301 in manual by 50% and the
upstream and downstream isolation valves.
17. Ensure that the temperature control valve 68-TV-1301 is manually closed.
18. Start Deaerator Feed Pump 6834-P-20A from the local panel.
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19. Now the Deaerator Feed Pump 6834-P-20A is circulating water back to the Steam
Condensate Flash Drum 6834-V-05 through the Steam Condensate Cooler 6834-E-02.
20. Line up temperature control valve 68-TV-1301 upstream and downstream isolation
valves and take 68-TV-1301 in AUTO with a set point of 102°C.
21. Line up Demineralised Water from Demineralised Water Feed Pumps 6834-P-24A/B
by opening the upstream and downstream isolation valves of 68-LV-1301.
22. Take 68-LV-1301 in AUTO with a set point of 50%.
5.14.2
Lining up of BFW Deaerator Package 6834-A-08
1.
Open the 2” Deaerator Column vent isolation valve to atmosphere.
2.
Open the 3” drain valve from the Deaerator Storage Vessel 6834-A-08.
3.
Reset ESD and ensure the Deaerator inlet ON-OFF valve 68-XV-1301 opens.
4.
Line up 68-LV-1302 upstream and downstream isolation valve.
5.
Open 68-LV-1302 manually by 10%.
6.
Warm up the Deaerator Storage Vessel and the Deaerator Column with the
condensate from Deaerator Feed Pumps.
7.
After allowing sufficient time for the warming up of Deaerator, close the 3” drain
valve from the drum.
8.
Now the level in the drum starts to rise.
9.
Ensure that the low low level trip 68-LALL-1310 in the drum is cancelled when the
level rises.
10. Ensure that the low level alarm 68-LAL-1310 is cancelled when the level rises.
11. When the level reaches 50%, put 68-LIC-1302 in AUTO with a set point of 50%.
12. Line up LP saturated steam by opening the upstream and downstream isolation
valves of 68-PV-1304.
13. Put 68-PV-1304 in AUTO with a set point of 1.21 bara.
14. Drain condensate from the Deaerator if required to maintain the level at 50%.
15. Start Boiler Feed Water Pump 6834-P-22A and recirculate the condensate to the
Deaerator through the minimum flow line.
16. Start O2 Scavenging Injection from the Chemical Injection Package 6834-A-09 as
per section 5.12.2 and line up to the Deaerator at a rate of 0.55 l/hr.
17. Take a sample from the Sample cooler 68-SC-1004 at the suction of the Boiler
Feed Water Pump 6834-P-22A and analyse for dissolved Oxygen.
18. If O2 and CO2 in the sample are less than 5 parts per billion then the Boiler Feed
Water is ready for lining up to the steam generation units.
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5.15
STEAM GENERATION PACKAGE START-UP
5.15.1
Checks for Start-up
•
First of all it is necessary to be sure that all lines up to boiler package battery
limit (including water, steam, compressed air, fuel gas etc.) have been completely
and properly cleaned to eliminate from internal side of lines, any possible
presence of impurities/oxides, debris, rust and scales. This is very important for
the first time start-up of the Boiler subsequent to a long shutdown and there is a
reasonable doubt about possible accumulation of deposits on line internal parts
•
In the case boiler start-up is subsequent to a long boiler shutdown (for instance:
for maintenance, inspection or repair purposes), the Operator visual inspection
should be extended to internal and external parts and it should cover at least the
following essential points:
•
Check of cleaning of all involved piping by means of appropriate fluids so that
piping is internally free from scale and impurities. Operator must always take
care to achieve an ideal clean tube condition, in order to avoid any obstruction
to the instruments, valves and fittings that could seriously jeopardize the
boiler/plant functionality and operation. This visual inspection should be
extended till to check the drains and to see if the fluid is discharged without
any obstruction and free from scales or other impurities;
•
Water gauge passages and other boiler mounting openings are clear
•
Manhole doors are in position with good gaskets and satisfactorily tightened
•
All Boiler and Economizer valves and fittings are operated and checked
•
Combustion chamber and flue gas circuits are checked for cleanliness with
refractory brickwork in good condition and expansion allowances are clear
•
All valves and fittings installed on remaining lines (such as instrument air,
cooling water, fuel lines and so on) are proven clear and in working order
•
All installed instrumentation are in good and working conditions
•
Before start-up of the steam generator, it should be verified that all the
auxiliary equipments are in proper working condition and all the control
devices have been positively tested
Critical checks for start-up of Boiler:
•
Verify the proper functioning of the level gauge (Boiler). If necessary level
gauge drains are to be operated and the level gauge is checked. Ensure that
water comes out of the level gauge drains and that upstream piping is not
blocked by impurities. In case of doubt and if necessary remove the drain
valves and clear the upstream piping of blockages
•
Verify that all the Boiler and Economizer drains are closed
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5.15.2
•
Verify that main steam stop valve and relevant by-pass valves are completely
closed
•
Verify the proper operation of all the control and block valves
•
Verify that all equipment inspection doors are properly closed
•
Verify that feed water is available with proper quality
Water Filling
•
Before the Boiler start-up operation, boiler has to be filled with water up to
the operating level
•
Feed water must always be introduced slowly into the boiler. The filling water
flow rate depends on the water temperature.
•
In general 20°C is the minimum recommended value of the feed water
temperature. If this value is higher than 40°C, the steam generator should be
filled very slowly in order to prevent stress on the boiler components
(particularly on drums)
•
Before starting boiler filling, all vent valves (both manual and actuated) shall
be fully opened
•
Ensure that the manual start-up vent valves GV-5045 & GV-5046 are fully open
•
Boiler and Economizer drains shall be opened (in order to check their proper
operation). Boiler and Economizer drain valves shall be closed after few
minutes
•
All the vent valves are to be kept open. This is to vent out air pockets inside
steam generator tubes to atmosphere
•
When water exits from the Economizer vent, the relevant Economizer vent
manual valve has to be closed.
•
Keep 68-PIC-1819 in Manual Mode and Open 68-PV-1524 fully (MV=100%).
•
Open the start-up vent 68-PV-1523 fully in Manual Mode.
•
Confirm that the LP Steam Outlet 68-MOV-1522 is in closed position.
•
Ensure that the BFW Pumps 6834-P-22 A/B/C are running.
•
Ensure that the BFW inlet 68-XV-1522 & 68-XV-1524 are open.
•
Ensure that complex product Injection package is started as per section 5.12.1
and complex product is dosed at a rate of 1.87 l/hr to the BFW.
•
Gradually open the 68-LV-1522 in Manual Mode and fill the downstream line.
•
Gradually open the valve GV-5013 and fill the Boiler Steam Drum 6848-V-02A
with DM water.
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•
Fill the Boiler gradually and open the drain lines one by one for flushing.
•
Close all the drain valves after ensuring sediment free water from Boiler.
•
Monitor the level in the Steam Drum.
•
Check for water leakages if any.
•
Raise the Steam Drum Water level up to normal level.
•
Confirm that the all drain valves are closed properly.
•
Water filling is completed when drum level is at about 50 mm below the
normal water level (NWL) so that there is enough volume for expansion during
subsequent water heating when burner is lighted.
Note: Achieving of drum level is a necessary and mandatory pre-condition for boiler
start-up operation. Normal Water Level is located +50 mm above Steam Drum centre line.
5.15.3
Fuel Gas Line-up
1.
Ensure that the main fuel gas line and the pilot fuel gas line are purged with
nitrogen and are under nitrogen pressure.
2.
Ensure that the fuel gas lines are leak tested.
3.
Ensure that the vent and drain valves in the fuel gas lines are closed.
4.
Ensure that fuel gas inlet filter 6848-S-01A elements are available and boxed up.
5.
Ensure that the fuel gas inlet 68-XV-1302 is open.
6.
Slowly open the isolation valve upstream of 68-XV-1302 and pressurise the line.
Check the pressure increase through 68-PG-1314.
7.
Open the isolation valve BV-5167 and slowly pressurise the downstream lines.
8.
Open 68-PCV-1522 in Manual Mode slowly and pressurise the Main Fuel Gas Line.
9.
Open the Block valve BV-5190 and slowly pressurise the Pilot Fuel Gas line.
10. Check for any gas leakages.
5.15.4
FD Fan Start-up
1.
Confirm that necessary lubricants/grease is filled as per specifications.
2.
Confirm that the Cooling water is lined-up and the water flows through the Sight
Flow Glass (SFG).
3.
Ensure that the Inlet damper is fully open.
4.
Keep the “LOR” selector Switch in ‘Local’ mode.
5.
Rotate the shaft, half turn, by hand to ensure free rotation of the Fan.
6.
Confirm that the FD Fan 6848-K-02A is ready to start.
7.
Inform to the substation.
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8.
Start the FD Fan by pressing START push button.
9.
Ensure that there is no abnormal noise and vibration
5.15.5
Burner Start-up
Burner management system (BMS):
The burner operation is performed in fully automatic through Burner management
system (BMS).
The BMS performs the following basic functions:
1.
Continuous check of all valves and dampers of combustion systems
2.
Pre-firing cycle.
3.
Light-off cycle of burner.
4.
Boiler Stop cycle.
5.
ESD-Master fuel trip.
6.
Post firing purge.
Steam generation unit-Burner start-up:
Note: Tags considered in this document are all related to BOILER A.
Steam generation unit Local panel details (6848A02A-LP-003) are tabulated below:
Sl. #
Tag No.
Description
1.
68-HSO-1526
Burner start
2.
68-HSC-1527
Burner stop
3.
68-HS-1528
Reset button
4.
68-HS-1524
Emergency shutdown
5.
68-HSR-1529
Local/Remote selector
6.
68-HS-1530
Lamp test button
7.
68-XL-1541
Burner firing lamp
8.
68-XL-1542
Burner shutdown lamp
Control valve/ON-OFF valve details are tabulated below:
Sl. #
Tag No.
Description
1.
68-XV-1528
Main gas shut off valve-1
2.
68-XV-1529
Main gas shut off valve-2
3.
68-XV-1530
Main gas vent valve
4.
68-XV-1531
Pilot gas shut off valve-1
5.
68-XV-1532
Pilot gas shut off valve-2
6.
68-XV-1533
Pilot gas vent valve
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Sl. #
Tag No.
Description
7.
68-FV-1525
Fuel gas control valve
8.
68-FV-1524
Flue gas recirculation damper
9.
68-FV-1526
Combustion air damper
Burner start can be done from HMI, Local panel and DCS.
DCS start is active only in remote mode and start on HMI or local panel is active in
local mode.
Burner Consent to Start:
The start of the burner is allowed only if all the following consents are set:
•
Burner is OFF
•
Combustion Air fan (6848-K-02A) is running
•
Flue gas recirculation fan (6848-K-03A) is running (If enabled)
•
Below mentioned burner Shutdowns are not present
Sl. #
1.
Tag No./Alarm
Description
1.
68-PAHH-1528A/B/C
Combustion chamber pressure high-high
2.
68-LALL-1523A/B/C
Boiler level low-low
3.
68-LAHH-1523A/B/C
Boiler level high-high
4.
68-PAHH-1522A/B/C
Saturated steam pressure high-high
5.
68-PALL-1525A/B/C
Upstream burner gas pressure low-low
6.
68-PAHH-1526A/B/C
Downstream burner gas pressure high-high
7.
68-FALL-1526B/C/D
Combustion air flow low-low
8.
68-FAHH-1525B/C/D
Natural gas flow High-High
9.
68-PALL-1527A/B/C
Instrument air pressure low-low
10.
68-HS-1523
ESD from boiler control panel
11.
68-HS-1524
ESD from boiler local control panel
12.
68-HS-1525
Emergency shutdown
13.
68-ZI-1548
Forced draft fan not running
14.
68-XS-1327
Emergency shutdown from ESD
15.
NA
Burner main, pilot shutoff and vent valves
discrepancies
The burner can be started only manually by the operator from LCP or DCS. The
following permissives for burner start-up are to be satisfied.
a.
The burner is off. The burner is not already “STARTING” or “ON”.
b.
Burner shutdown alarms are not present.
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c.
Combustion Air Fan 6848-K-02A is running.
d.
Flue Gas Recirculation Fan 6848-K-03A is running. (If flue gas recirculation
control is enabled).
2. Select “LOCAL” in the Local Burner Panel.
3. Press the “START” push button HSO-1526 from the Local Burner Panel.
4. Set the minimum opening for the air flow control damper 68-FV-1526 from the LBP
for purge.
5. Ensure that the air purge is done for 5 minutes.
6. After air purge is done ensure that the damper FV-1526 opening is decreased to the
burner light off threshold.
7. If flue gas recirculation controller is enabled, set the opening for the flue gas
recirculation damper FV-1524.
8. Ensure that the flue gas recirculation damper 68-FV-1524 is open.
9. Ensure that the flue gas recirculation purge is done for 1 minute.
10. After flue gas purge is done ensure that the damper 68-FV-1524 is decreased to the
burner light off threshold.
11. After 2 seconds of the PURGE VALID signal given by BMS, ensure that the burner
ignition transformer is powered.
12. After 2 seconds of powering of the transformer, ensure the burner igniter vent
valve 68-XV-1533 is closed and opens the burner igniter shut-off valves 68-XV-1531
and 68-XV-1532.
13. Ensure that after 5 seconds, the burner ignition transformer is powered off.
14. Ensure that the flame is detected by the flame scanner 68-BE-1523.
15. If flame is detected, ensure ‘Pilot On’ indication is available in LBP.
16. If the flame scanner 68-BE-1523 does not detect the flame, ensure that the burner
restart is attempted automatically after 1 minute without purging the combustion
chamber again.
Note: The system can try the restart for 3 times. If flame is not detected again,
the shutdown of the burner is started and purge valid signal is reset.
17. When the pilot ignition is successful, ensure that the main burner vent valve 68-XV1530 is closed and the main shut-off valves 68-XV-1528 and 68-XV-1529 are opened.
18. After 5 seconds for flame stabilization, the pilot vent valve 68-XV-1533 is opened
and the pilot shut off valves 68-XV-1531 and 68-XV-1532 are closed.
19. Ensure that the flame scanners 68-BE-1522A & 68-BE-1522B detect flame.
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Fig. 26 - Burner Management Sequence for Steam Generation Package
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MANUAL
/212
5.15.6
Boiler Normal Start-up
1.
Raise the furnace Temperature gradually as per the Vendor IOM.
2.
Operate the Boiler as per the Vendor IOM.
3.
When the Drum Pressure reaches 1.5 barg (Hot) tighten the Drums bolts/nuts.
4.
Steam Trap line-up:
•
Ensure that the steam flow through the trap bypass line.
•
Open the steam trap down steam valve.
•
Open the steam trap upstream valve.
•
Close the bypass valve.
5. Observe and monitor the parameters:
•
Fuel Gas Flow/Pressure
•
Combustion Air flow
•
Furnace Pressure
•
FD Fan Discharge Pressure
•
Drum Level/Pressure
•
Main Steam line Pressure
6. Check for Boilers expansions, if any.
7. Ensure that the Main Steam line distribution headers, all vents and drains are
opened.
8. Check the furnace for flue gas leakages, if any.
9. Gradually increase the Drum pressure by throttling the start-up vent valve 68-PV-1523.
10. Ensure that the Drum level is maintained.
11. Gradually raise the air flow and fuel gas flow to increase the Drum pressure.
12. Check and confirm that the expansion of the Boiler at various locations is as per
the design values.
13. Collect the Boiler water sample periodically and analyse the sample in lab for oil
traces.
14. When the Drum Pressure reaches 5 barg, gradually open the Main Steam line
MOV-1522 and crack open the downstream isolation valve to warm up the main
steam line Header.
15. Line up all the steam traps along the main header and open the drain valves fully
in the steam traps and drain all the condensate from the header.
/
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16. Keep open the traps drain valves till superheated steam comes out of the drain
lines.
17. When the superheated steam is noticed close the steam trap drain valves one by
one and line up the steam traps to the condensate header.
18. Ensure that the condensate header is already warmed up.
19. When the steam header is warmed up, close all the drains and vents and open the
MOV-1522 downstream isolation valve fully and charge the header.
20. Gradually increase the header pressure to the normal operating pressure.
21. Take all the controls in auto.
22. Open the continuous blow down valve and give blow down as necessary.
23. Line up Complex Product Injection pump 6834-P-41A/B and start dosing the
chemical as per requirement.
5.15.7
Start-up from Cold Condition (Manual Mode)
“Start-up from cold condition” refers to the boiler that is being started at atmospheric
pressure and ambient temperature.
While starting the Boiler on Cold conditions, the following also has to be verified:
•
Economizer manual vent valves are closed
•
Boiler and Economizer manual drain valves are closed
•
Desuperheater 6848-X-03A Boiler Feed water control valve 68-TV-1522 is closed as
it is not necessary to use the Desuperheater 6848-X-03A during initial start-up as
the first steam produced is still “cold”
•
Motorized main steam stop valve and relevant motorized by-pass valve are
completely closed.
Before lighting any burner the Forced Draft Fan 6848-K-02A and the Flue Gas
Recirculation Fan 6848-K-03A are to be started in order to allow the system to be
ready to initiate the boiler purging and also the fuel gas lines leakage test.
Provided that all detailed sequences and controls as described in BMS Controls are
satisfied, it is necessary to wait for a sufficient time to completely purge all boiler
flue gas passages.
Light up the first burner according to the operating sequence described on BMS
controls.
The boiler thermal heat input introduced through the burner must be maintained at
boiler minimum load.
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When saturated steam starts to exit from vents installed on the saturated steam line
(this means that boiler pressure is slightly higher than atmospheric pressure) the vent
valve installed on the saturated steam line to be closed to increase the Boiler
pressure.
During start-up, the boiler pressurisation curve (that is, saturated pressure and
saturated temperature vs. time) shown in the following figure “Boiler start-up curve”
to be followed for pressurisation.
To follow the burner should be operated at minimum allowable firing rate and if
necessary the burner should be shut down and subsequently (after purging time)
started up.
Note: Faster start-up can cause serious damages to boiler. In order to comply with
boiler pressurisation limit curve shown on following figure the burner can be lighted
off/lighted on, as long as necessary.
During boiler pressurisation, do not exceed the following limitations:
•
30°C/h: from ambient temperature up to about 130°C (2 barg steam pressure)
•
55°C/h: from 2 barg steam pressure till to MCR operating pressure
During the boiler heating ramp, when adequate steam pressure is reached the burner
load/fuel heat input can be increased from its minimum, but in any case the boiler
pressurisation curve shall be correctly followed.
When adequate steam flow rate is reached, the Boiler Feed Water to Desuperheater
6848-X-03A is lined up.
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Fig. 27 - Burner Management Sequence for Steam Generation Package
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5.15.8
Start-up from Hot Condition
If the steam generator is in “hot" condition (that is, the boiler is close to the value of
operating pressure/temperature, condition that practically occurs immediately after
or a few hours after a boiler trip) the following conditions often exist:
•
Main steam stop valve 68-MOV-1522 and its by-pass valve are closed
•
Actuated start-up vent valve 68-PV-1523 is closed
Before starting the boiler again, Operator shall check the existing differential pressure
between Steam Drum 6848-V-02A pressure and steam header downstream of main
steam stop valve pressure. When the two pressures are equalised then steam from
Steam Drum can be lined up to the header.
After opening the actuated start-up steam vent valve the burner is started at minimum
firing conditions. The Boiler pressure slowly increases. When the pressure increases
above the header pressure, the produced steam from Steam Drum can be lined up to
the steam network through the motorised main steam shut off valve 68-MOV-1522.
If the steam network grid pressure is higher than the boiler pressure, the motorised
steam shut off valve 68-MOV-1522 should remain closed.
In case steam network grid pressure is lower than the Boiler pressure and main stop
valve is closed, then the bypass valve is crack opened to pressurise the network grid.
At the end of this pressurisation activity, when the network grid pressure is equal or a
little bit lower than boiler pressure (approx 0,5 bar), the motorised main steam stop
valve shall be fully opened by Operator. After that, the actuated start-up vent valve
shall be gradually closed.
During this transfer, the firing rate shall be maintained constant. Then the firing ramp
can be started.
It is strongly recommended during boiler ramping, do not exceed the following
limitations:
•
5.15.9
/
55°C/h: from 2 barg steam pressure to MCR operating pressure
Going On Line
•
Once the Boiler has reached the operating pressure, the main shut off steam valve
can be opened completely (provided that downstream steam network grid is
warmed up and ready to take the boiler steam). The start-up vent valve can now
be closed.
•
When this transfer is completed and the alignment between Steam Generator and
steam network grid line has been stabilised, the Boiler load can be increased from
minimum load.
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5.16
•
When the Boiler is stabilized, the Steam Pressure Controller 68-PIC-1819 can be
put in AUTO.
•
The Steam Pressure Controller 68-PIC-1819 varies the firing rate of the fuel gas
according to the pressure set point.
•
The entire system should be kept under close surveillance until full load operating
conditions are achieved. There is always the possibility of a defect in the safety
cut outs.
•
The operation of burner and the flame pattern shall be closely monitored during
start-up phase.
•
Two scanners are installed on each burner so to reveal the flame presence. The
flame pattern must be checked directly on field by Operator through the
peepholes installed on each burner and in the rear furnace wall.
•
The flame pattern shall be set in order to have a good flame, without furnace
tube impingement and achieving minimum unburned emissions (basically CO
content on flue gases).
•
Operator shall verify that the combustion takes place correctly, monitoring the
flame pattern.
LEAK CHECKING OF SYSTEMS
Leak checking of process systems to be done after maintenance of equipment or break
open of piping flanges for repair/maintenance works.
Preparation:
Ensure that the following activities are completed:
•
Relevant Work Permit have been filled up and signed
•
The system is reinstated as per P&IDs
•
Pressurising manifold with suitable PSV and pressure gauge will be used.
Leak Check:
Leak check shall be done as below:
/
•
Isolate the process system, using the available block valves
•
Close all vent and drains
•
Prepare a list of flanges and other critical locations to be checked.
•
Connect an air hose preferably from the plant air header or otherwise from a
temporary compressor discharge manifold through temporary hoses.
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5.17
•
Pressurise the system step by step and hold the pressure at 25%, 50%, 75% and
operating pressure and carry out a thorough leak check of all the listed flanges
and other systems using tape and soap solution. Attend to leaks, if any after
depressurisation.
•
Repeat the above procedure till there is no leak identified
•
Hold the pressure for 30 minutes and record the pressure loss. If the pressure loss
is less than 0.05 bar/hr, the system will be considered to be leak free.
PURGING
Purging of process lines and equipments with Nitrogen is to be carried out prior to
introduction of acid gases into the process system. Process System and piping which
contains acid gases are Nitrogen purged using an approved inerting procedure.
A.
Pre-requisite for Nitrogen Purging
1.
Verify portable radios are available for communication.
2.
Verify that all-loose materials and tools have been cleaned up prior to nitrogen
purging.
3.
Obtain Oxygen monitors for testing Oxygen concentration during purging.
4.
Verify that all personnel are appropriately equipped with required PPEs including
hard hats, goggles, earplugs and gas monitoring equipment.
5.
Prior to initiating purge, a toolbox talk shall be held for the personnel regarding
the purging and the hazards of Nitrogen gas.
B.
Preparation
1.
Risk assessment shall be done prior to purging of each system.
2.
System shall be marked and identified in the P&ID. Also the point used for purging
will be marked in P&ID.
3.
The PI and PGs in the system will be used for monitoring the system pressure.
4.
Pressure test with nitrogen is carried along with the nitrogen purging.
5.
Depressurisation points shall be chosen such that the whole system is
depressurised and no pressure is trapped downstream of check valves.
C.
Purging Procedure for Vessels & Equipment
1. Purging of Process Systems is critical for a safe start-up of the facility.
/
2.
Purging is accomplished by using Nitrogen.
3.
While carrying out the vessels and equipment purging ensure vents and pressure
taps such as gauge glass, level control bridles, spare pumps, etc., are properly
purged. Purging and testing should be continued until Oxygen content is less than
2%. A sample is taken in each case from the system being purged at the purge
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pressure and passed through an Oxygen monitor, which reads directly in percent
Oxygen.
/
4.
Consider each line and piece of equipment to assure complete purging of air.
Purge interconnecting piping systematically to avoid leaving air pockets in these
systems. Ensure that all appropriate valves are open or closed as required.
Particular attention should be given to block the valves located at the upstream of
relief valves.
5.
If proper tapings are not available, arrange necessary flanged nipples to fix
Nitrogen hose or to make purge outlet.
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SECTION VI
START-UP OF PLANT
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6.1
GENERAL
The start-up procedure of the SRU depends on the exact situation of the unit at any
particular point of time. The various cases are:
•
Start-up after a major turnaround shutdown
•
Start-up after an emergency shutdown, where the unit is ready to be taken on
stream immediately
When starting the unit after a shutdown, only the relevant procedures are followed
depending on the status of the various sections of the unit and nature of jobs carried
out. All safety precautions as per the safety rules and regulations are followed while
taking over and starting up of any equipment or section of the unit. There are
standard procedures to be followed as per the QP safety manuals for inspection,
followed by accepting/deblinding any equipment before taking in line.
Smooth start-up will depend to a larger degree on how well the unit is checked prior
to start-up. In a major turnaround shutdown, all vessel internals are inspected, and if
there are any modifications to be carried out, it is completed and the vessels boxed
up. All safety items should be checked before, during and after start-up to ensure safe
and stable operation.
During start-up, the operating conditions of each unit must be adjusted to bring the
product specifications in line with the design values. During the period of off-spec
product it should be vented to flare system as far as possible to meet the required
specification. Prior planning of various start-up activities can eliminate delay and
improve the safety of personnel and equipment.
6.2
START-UP SEQUENCE
It will be necessary to start-up all or section of the plant after shutting down plant for
various reasons viz.; mechanical repair, repair of critical equipments/pipeline leaks,
utilities failure or any operating problem.
The process plants are to be started in the following sequence:
1. Incinerator
2. Acid Gas Enrichment Unit
3. Sulphur Recovery Unit
4. Tail Gas Treatment Unit
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6.3
START-UP OF PROCESS
6.3.1
Start-up of Incinerator 9101-F-14
Start-up of the Incinerator involves the following activities:
1.
Purging of the system and pilot ignition
2.
Main burner ignition, heat-up and introduction of Tail gases.
6.3.1.1
Purging Of the System and Pilot Ignition
a.
Pre-requisites
1.
Air inlets, burner and incinerator/stack passages are in good condition and free of
foreign material.
2.
All personnel have been evacuated from the Incinerator, duct work, associated
equipment and all access and inspection doors closed and sealed.
3.
Blower VFD’s are operated through full range to check the blower response.
4.
All safety shut off valves in fuel gas lines are closed.
5.
Fuel system vents are open and venting properly to atmosphere. Lines are
properly drained and cleared of condensate.
6.
A complete functional check of the safety interlocks has been made after any
overhaul or other significant maintenance.
7.
The area is clear of obvious safety hazards and flammable gases are not present in
the area.
8.
All lines have been blown down with plant air to ensure they are free of debris
that might plug metering orifices and burner tips.
9.
Utilities (fuel gas, instrument air and plant air) are established and initial
operational checks performed on the elements in each line.
10. Burner elements and pilot are in their proper position in accordance with
specifications shown in the burner assembly and pilot drawings.
11. Power has been supplied to control systems and to safety interlocks.
12. Meters or gauges indicating fuel header pressure to the unit are functional.
13. Ensure that the following Pressure self regulating valves are set according to the
instrument data sheets.
•
Pilot gas supply PCV-1155 set at 0.7 barg
•
Pilot air supply PCV-1164 set at 0.7 barg
14. Isolation valves for all pressure gauges and pressure transmitters are open and
their respective bleed valves are closed.
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15. Purge air has been established for the sight ports and flame scanners. Flame
scanners have clear lenses and the scanner isolation ball valves are open.
b. Local Control Panel
Incinerator is equipped with a Local Control Panel 9101-F-14-LP-001. This panel is used
for the start-up of the Incinerator System. The LCP is supplied with the following
indications:
Tag No.
Description
Colour
91-XL-1173
System Ready for Purge
Green
91-XL-1174
Purge in Progress
Green
91-XL-1175
Purge Complete
Green
91-XL-1176
Pilot Flame On
Green
91-XL-1177
Main Burner On
Green
91-XA-1178
Common Alarm
Red
91-XL-1180
BE-1155A Flame Detected
Green
91-XL-1181
BE-1155B Flame Detected
Green
91-XL-1182
BE-1155C Flame Detected
Green
91-HS-1162
Reset
Black
91-HS-1163
Start Purge
Black
91-HS-1164
Start Pilot
Black
91-HS-1165
Start Burner
Black
91-HS-1166
Normal Stop
Black
91-HS-1167
Emergency Shutdown
Red – Mushroom Head
91-HS-1168
Lamp Test
Black
Control valve and ON-OFF valve details are tabulated below:
Sl. #
Tag No.
Description
1.
91-XV-1155
Fuel gas upstream block valve
2.
91-XV-1156
Fuel gas vent valve
3.
91-XV-1157
Fuel gas downstream block valve
4.
91-XV-1158
Pilot gas upstream block valve
5.
91-XV-1159
Pilot gas vent valve
6.
91-XV-1160
Pilot gas downstream block valve
7.
91-XV-1161
Instrument air block valve
8.
91-XV-1162
Pilot air block valve
9.
91-FV-1155
Fuel gas control valve
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Prior to the start-up of the Incinerator ensure the following:
•
BMS (PLC-UCP) is powered up
•
Signal 91-XS-1170 to force fuel gas flow rate controller 91-FIC-1155 to 0% output is
present.
•
Signal 91-XS-1171 to force combustion air flow rate controller 91-FIC-1156 to 100%
output is absent.
•
Fuel gas control valve 91-FV-1155 at minimum stop position.
•
Fuel gas upstream (91-XV-1155) and downstream (91-XV-1157) is closed.
•
Fuel gas vent valve (91-XV-1156) is opened.
•
Pilot gas upstream (91-XV-1158) and downstream (91-XV-1160) is closed.
•
Pilot gas vent valve (91-XV-1159) is opened.
•
Instrument air block valve (91-XV-1161) is closed.
•
Pilot air block valve (91-XV-1162) is closed.
Note: Press lamp test switch 91-HS-1168 on the local panel and ensure all the lamps
are working.
c.
Purge Cycle
Prior to the ignition of any burner it is important to purge the Incinerator with fresh
air which will sweep away any combustible that may have accumulated in the system.
Start-up of Blowers:
•
Select Local on the local/remote selector switch 9101-RCU-KM-12A/B
•
Force VFD (9101-K-12A/B) to minimum speed from the DCS
•
Press motor start switch in 9101-RCU-KM-12A/B
•
Open the O/L damper
1.
Ensure the following BMS Shutdown alarm conditions in Incinerator are normal:
Tag No.
Description
91-XS-1185
Remote ESD signal
91-HS-1167
Local ESD (PB on LCP)
91-FALL-1156B
Combustion Air flow low low alarm
91-PALL-1155
Fuel gas pressure low low alarm
91-PALL-1156
Fuel gas pressure low low alarm
91-PAHH-1156
Fuel gas pressure high high alarm
91-BSLL-1155
Flame fail (2oo3) alarm
91-TAHH-1160
Incinerator Temperature high high alarm
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Note: During start-up, the discrepancy alarms of BMS ON/OFF valves trips the
Incinerator.
2.
Ensure that the following permissives to start the purge are available:
Tag No.
Description
Position/Status
91-BSL-1155A
Flame Scanner Switch
Not energized (No flame)
91-BSL-1155B
Flame Scanner Switch
Not energized (No flame)
91-BSL-1155C
Flame Scanner Switch
Not energized (No flame)
91-BSL-1156
Flame Rod Switch
Not energized (No flame)
91-ZSL-1155
Fuel Gas Control valve
Valve at low-fire position
91-ZSC-1155
Fuel Gas upstream block valve
Valve closed
91-ZSO-1156
Fuel Gas vent valve
Valve open
91-ZSC-1157
Fuel Gas downstream block valve
Valve closed
91-ZSC-1158
Pilot Fuel Gas upstream block
valve
Valve closed
91-ZSO-1159
Pilot Fuel Gas vent valve
Valve open
91-ZSC-1160
Pilot Fuel Gas downstream block
valve
Valve closed
3. If purge permissives are met, ensure that the System Ready for Purge lamp 91-XL1173 on LCP is lit.
4. Press ‘START PURGE’ pushbutton 91-HS-1163 from LCP 9101-F14-LP-001.
5. Ensure that the force signal (91-XS-1171) to FIC-1156 is energized and forces the
flow controller FIC-1156 to manual mode with 100% output.
6. Ensure that the shut off valves 91-XV-1161 & 91-XV-1162 are opened and air is
supplied to the pilot and purge air to the flame scanners.
7. Ensure that the combustion air flow measured by 91-FT-1156C indicates a flow of
>45500 Sm3/hr.
8. Ensure that the ‘PURGE IN PROGRESS’ lamp 91-XL-1174 on LCP is lit.
9. Ensure purging is completed in 5 minutes.
10. Ensure that ‘PURGE COMPLETE’ lamp 91-XL-1175 on the LCP is lit.
11. At the end of 5 minutes, the forcing signal 91-XS-1171 is de-energised allowing
FIC-1156 to return to automatic mode, since no fuel gas is flowing to the burner at
this point the output to the VFD is at its minimum, 11106 Sm3/hr.
12. Ensure that this condition exists for another 5 minutes.
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d.
Pilot Ignition
1.
Ensure that there are no alarms present in the UCP (BMS).
2.
Ensure that the above listed permissives are met.
3.
Press ‘START PILOT’ push button 91-HS-1164 from LCP.
4.
Ensure that ‘PURGE COMPLETE’ indication is no more present.
5.
Ensure that the pilot vent valve 91-XV-1159 is closed.
6.
Ensure that the pilot block valves 91-XV-1158 & 91-XV-1160 are opened after
receiving the CLOSE feedback 91-ZSC-1159 of the vent valve 91-XV-1159.
7.
Ensure that the ignition transformer 91-XS-1183 is energised.
8.
Ensure that after 10 seconds, ignition transformer 91-XS-1183 is de-energised.
9.
Ensure that after 10 seconds, if pilot is ON, the flame is detected by the Pilot
Flame Rod 91-BE-1156.
10. Ensure that the ‘PILOT FLAME ON’ lamp 91-XL-1176 on the LCP is lit.
11. Ensure that pilot stabilisation timer of 60 seconds is completed from UCP HMI.
12. If no pilot flame is detected by the flame rod, ensure that after 10 seconds, SRU
tail gas Incinerator is tripped.
13. Ensure that the COMMON ALARM lamp 91-XA-1178 is lit.
14. Check the DCS/UCP for the first out alarm condition.
15. Clear the alarm condition.
16. RESET the system by pressing the RESET push button 91-HS-1162 from LCP.
17. Restart the system from the beginning.
18. If a flame is detected by 91-BE-1156 at the end of the 10 second trial period, then
the second pilot flame stabilization timer will be started.
6.3.1.2
Main Burner Ignition, Heat-up and Introduction of Tail Gases
1.
After pilot stabilisation timer of 60 seconds is completed, press ‘START BURNER’
pushbutton 91-HS-1165 on LCP 9101-F14-LP-001.
2.
Ensure that fuel gas vent valve 91-XV-1156 is closed.
3.
Ensure that the vent valve closing feedback is received from the limit switch
91-ZSC-1156.
4.
Ensure that the fuel gas block valves 91-XV-1155 & 91-XV-1157 are opened.
5.
Ensure that the burner fuel gas control valve 91-FV-1155 is at its minimum stop
position.
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6.
Ensure that in a 10 second trial for ignition period, the burner main flame is
detected by 2oo3 voting of flame scanners 91-BE-1155A, 91-BE-1155B & 91-BE1155C.
7.
Ensure that the ‘MAIN BURNER ON’ lamp 91-XA-1178 is lit in LCP.
8.
If no pilot flame is detected by the flame scanners, ensure that after 10 seconds,
SRU tail gas Incinerator is tripped.
9.
Ensure that the COMMON ALARM lamp 91-XA-1178 is lit.
10. Check the DCS/UCP for the first out alarm condition.
11. Clear the alarm condition.
12. RESET the system by pressing the RESET push button 91-HS-1162 from LCP.
13. Restart the system from the beginning.
14. Ensure that if the main flame is confirmed at the end of the main burner trial-forignition period, then a 60 second low fire timer in the BMS is automatically
started.
15. Ensure at the end of the 60 second low fire period, the BMS stops sending the
forcing signal 91-XS-1170 to the DCS.
16. Increase slowly the set point of 91-TIC-1155 so that the temperature of the
incinerator does not rise faster than 50°C per hour, until the normal operating
temperature of 817°C is reached.
17. Ensure that at 817°C the pilot is turned off.
18. Ensure that 91-XV-1158 & 91-XV-1160 are closed.
19. Ensure that 91-XV-1159 is opened.
20. Ensure that 91-XV-1162 is closed.
21. Ensure that there is a flow of 4.6 Sm3/hr. of purge cooling air through a restriction
orifice RO-1155 to the pilot around 91-XV-1162.
22. To introduce tail gases ensure that the system is in operation with no alarm
condition.
23. Ensure that the Incinerator temperature at 91-TE-1156 is greater than or equal to
817°C.
24. Now the system is ready for introduction of tail gases.
25. The flow of waste gases can be started and stopped in any order. However the
waste gases should be introduced one at a time to the Incinerator.
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Fig. 28 - Incinerator Burner Start-up Flow Chart
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6.3.2
Start-Up of Acid Gas Enrichment Unit
Pre-requisites
•
Preparation of Antifoam
•
Preparation of Corrosion Inhibitor
•
Preparation of Amine Solution
6.3.2.1
Preparation of Antifoam
1.
Ensure that the Antifoam Injection Pumps 9103-P-16A/B and the Agitator 9103-M12 are energised in MCC.
2.
Ensure that the Antifoam Storage Tank 9103-T-12 is cleaned internally.
3.
Ensure that all the drain and vent valves in the package are closed.
4.
Introduce minimum flow of Nitrogen to the Antifoam Storage Tank and read the
flow through the flow indicator 91-FI-1537.
5.
Procure the Antifoam drums to the site and place it near the unloading pumps
9103-P-19A/B.
6.
Connect the drums to the unloading pumps through flexible hose.
7.
Start the unloading pumps and transfer antifoam to the tank.
8.
Ensure that the low low level trip 91-LALL-1520 & low level alarm 91-LAL-1521 are
cancelled while making up the solution.
9.
Ensure the level in the tank from 91-LG-1510 and 91-LT-1521 and ensure the tank
does not overflow.
10. Start agitator 9103-M-12 from the local panel to mix the solution thoroughly.
6.3.2.2
Lining up of Antifoam Injection Pumps 9103-P-16A/B
1.
Ensure that the Antifoam Injection pumps 9103-P-16A/B suction strainer elements
are fixed and boxed up.
2.
Ensure that the Antifoam Injection Pumps 9103-P-16A/B discharge PSVs 91-PSV1602/1603 are lined up.
3.
Open the Antifoam Storage Tank outlet isolation valve to the injection pumps and
fill the lines with the antifoam solution.
4.
Open the discharge isolation valve of the Antifoam Injection Pump 9103-P-16A.
5.
Open the common discharge isolation valve of the Antifoam Injection Pumps 9103P-16A/B.
6.
Select the LOR switch of the Antifoam Injection Pump 9103-P-16A in Local.
7.
Start the Antifoam Injection Pump 9103-P-16A from local control station.
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8.
Ensure that the Antifoam Injection Pump 9103-P-16A is developing pressure by
checking the discharge pressure transmitter 91-PT-1559.
9.
Stop the pump and keep the Antifoam Injection Pump 9103-P-16A ready for
dosing.
10. Repeat the above procedure for Antifoam Injection Pump 9103-P-16B and keep it
ready.
11. Line up Antifoam to the Acid Gas Amine Absorber 9103-C-11 or Amine Regenerator
9103-C-12 as required.
6.3.2.3
Preparation of Corrosion Inhibitor
1.
Ensure that the Corrosion Inhibitor Injection Pumps 9103-P-101A/B and the
Agitator 9103-M-13 are energised in MCC.
2.
Ensure that the Corrosion Inhibitor Storage Tank 9103-T-13 is cleaned internally.
3.
Ensure that all the drain and vent valves in the package are closed.
4.
Transport the Corrosion Inhibitor drums to the site and place it near the unloading
pumps 9103-P-102.
5.
Connect the drums to the unloading pumps through unloading hose.
6.
Start the unloading pumps and transfer Corrosion Inhibitor to the tank.
7.
Ensure that the low low level trip 91-LALL-1522 is cancelled while making up the
solution.
8.
Ensure the level in the tank from 91-LG-1511 and 91-LT-1523 and ensure the tank
does not overflow.
9.
Start agitator 9103-M-13 from the local panel to mix the solution thoroughly.
10. Keep the Corrosion Inhibitor Injection Pumps 9103-P-101A/B ready for dosing.
6.3.2.4
Lining up of Corrosion Inhibitor Injection Pumps 9103-P-101A/B
1.
Ensure that the Corrosion Inhibitor Injection pumps 9103-P-101A/B suction strainer
elements are fixed and boxed up.
2.
Ensure that the Corrosion Inhibitor Injection Pumps 9103-P-101A/B discharge PSVs
PSV-1504/1505 are lined up.
3.
Open the Corrosion Inhibitor Storage Tank outlet isolation valve to the injection
pumps and fill the lines with the Corrosion Inhibitor solution.
4.
Open the discharge isolation valve of the Corrosion Inhibitor Injection Pump 9103P-101A.
5.
Open the common discharge isolation valve of the Corrosion Inhibitor Injection
Pumps 9103-P-101A/B.
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6.
Put the stroke length of the Corrosion Inhibitor Injection Pump 9103-P-101A at
minimum position.
7.
Keep the LOR switch of the Corrosion Inhibitor Injection Pump 9103-P-101A in
‘Local’.
8.
Start the Corrosion Inhibitor Injection Pump 9103-P-101A from local control
station.
9.
Ensure that the Corrosion Inhibitor Injection Pump 9103-P-101A is developing
pressure by checking the discharge pressure transmitter 91-PT-1561.
10. Stop the pump and keep the Corrosion Inhibitor Injection Pump 9103-P-101A ready
for dosing.
11. Repeat the above procedure for Corrosion Inhibitor Injection Pump 9103-P-101B
and keep it ready.
12. Line up Corrosion Inhibitor to the Acid Gas Amine Absorber 9103-C-11 or Amine
Regenerator 9103-C-12 as required.
6.3.2.5
Filling Amine Surge Tank 9103-T-11 with Dow Ucarsol HS-103 (Amine Solution)
1.
Ensure that the Amine Surge Tank 9103-T-11 internals are clean and the man ways
are boxed up.
2.
Ensure that the following valves are closed.
a.
Lean Amine from Lean Amine Trim Cooler 9103-E-15 to the Tank 9103-T-11.
b.
Amine from Amine Filters 9103-S-11/12/13 to the Tank 9103-T-11.
c.
DM Water line to the Tank 9103-T-11.
d.
Lean Amine Pump 9103-P-13A/B minimum flow line isolation valves to the
Tank 9103-T-11.
e.
Lean Amine from Tank 9103-T-11 to Lean Amine Pump 9103-P-13A/B isolation
valve.
f.
Hydrocarbon skimming facility isolation valves.
g.
PSV-1513/1517/1518 outlet header isolation valve to the Tank 9103-T-11.
3. Ensure that the drain and vent valves of the Tank 9103-T-11 are isolated.
4. Ensure that the Tank PVRV-1521/PVRV-1522 upstream isolation valves are lined up.
5. Ensure that the Amine Surge Tank 9103-T-11 is purged with Nitrogen.
6. Line up tank vent valve 91-PV-1526B upstream isolation valve and take the control
valve in Remote.
7. Take the pressure controller 91-PIC-1526 in Auto with a set point of 0.02 barg.
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8. Line up the Nitrogen supply line to the tank isolation valves and take the control
valve 91-PV-1526A in Remote.
9. Ensure that all the instruments in the Amine Surge Tank 9103-T-11 are lined up.
10. Receive the road tanker containing amine solution and place it near the Amine
Surge Tank 9103-T-11 filling station.
11. Connect a 2” flexible metallic hose to the road tanker unloading line.
12. Connect the other end of the flexible metallic hose to the suction of the Amine
Unloading Pump 9103-P-18.
13. Ensure that the amine unloading pump suction strainer element is in place.
14. Connect the discharge of the amine unloading pump 9103-P-18 to the loading line
2”-9103-M-141-A189 of the Amine Surge Tank 9103-T-11 with a flexible metallic
hose.
15. Connect plant air to the pneumatic amine unloading pump 9103-P-18.
16. Ensure that the air vent valve (if any) of the pneumatic pump is open.
17. Open the amine loading line isolation valves of the Amine Surge Tank 9103-T-11.
18. Open the road tanker unloading line isolation valve slowly and fill the metallic
hose.
19. Start the Amine Unloading Pump 9103-P-18 by supplying plant air, and start to load
the amine into the Amine Surge Tank 9103-T-11.
20. Ensure that low low level trip 91-LT-1511 (1000 mm) is cancelled in ICSS.
21. Ensure that the low level alarm 91-LAL-1512 (1150 mm) is cancelled as the level
rises.
22. Monitor 91-LT-1512 and build the level up to 40% in the Amine Surge Tank 9103-T-11.
23. Stop pumping amine into the Amine Surge Tank 9103-T-11.
24. Close the tanker outlet valve and the Amine Surge Tank 9103-T-11 amine make up
line isolation valves.
25. Drain amine from all the transfer lines and the metallic hoses and remove the
metallic hoses.
26. Find the quantity of amine pumped into the Amine Surge Tank 9103-T-11.
27. If the added amine is 100% in concentration then DM water is to be added to dilute
the solution to 50%.
28. Open DM water make up to the Tank and fill DM water by observing the flow
through the flow gauge 91-FI-1529 in the DM water line equivalent to the Amine
quantity.
29. The concentration of the solution in the Tank now is 50%.
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30. Collect a sample of the Amine solution and send it to laboratory for analysing the
concentration.
31. When the sample concentration is given by the lab, necessary correction may be
carried out to make the concentration of 50% amine.
32. Now the amine solution at 50% concentration is ready to be transferred to the
AGEU and TGTU.
33. Ensure that the tank is blanketed by Nitrogen by checking through the pressure
transmitter 91-PT-1526.
6.3.2.6
Transfer of Amine from Amine Surge Tank 9103-T-11 to Acid Gas Amine
Absorber 9103-C-11
1.
Ensure that the Amine absorption section is under nitrogen pressure.
2.
Ensure that the drain and vent isolation valves are closed in the Lean Amine
Pumps 9103-P-13A/B suction and discharge lines.
3.
Ensure that the H2S Analyzer 91-AI-1506 from Lean Amine Cooler 9103-E-14 outlet
line joining the suction of the Lean Amine Pump 9103-P-13A/B isolation valve is
closed.
4.
Open the Amine Surge Tank 9103-T-11 outlet line to Lean Amine Pump 9103-P13A/B isolation valve and fill up the line with amine.
5.
Open the suction isolation valves of the Lean Amine Pumps 9103-P-13A/B and fill
the pumps by opening the casing vent valves.
6.
Ensure that the Lean Amine from the Lean Amine Pumps 9103-P-13A/B discharge
to the Tail Gas Amine Absorber 9103-C-12 is closed.
7.
Ensure that the Lean Amine from the Lean Amine Pumps 9103-P-13A/B discharge
to the Lean Amine Filter 9103-S-11/12/13 isolation valve is closed.
8.
Put the LOR switch position to “Local” position.
9.
Ensure that the Lean Amine Pumps 9103-P-13A/B are energized.
10. Reset PSD (Process Shut Down) from ICSS.
11. Ensure that Lean amine to Acid Gas Amine Absorber 9103-C-11 inlet ON-OFF valve
91-XV-1504 is opened.
12. Line up Lean Amine to Acid Gas Amine Absorber 9103-C-11 flow controller
91-FV-1501 isolation valves and close the bypass valve. Close the control valve
91-FV-1501 fully in manual.
13. Ensure that all the drain valves in the lean amine line to the Acid Gas Amine
Absorber 9103-C-11 are closed.
14. Start the Lean Amine Pump 9103-P-13A on minimum flow from local control
station.
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15. Ensure that the minimum flow line isolation valves are opened and the control
valve 91-FV-1511 is lined up and the controller 91-FIC-1511 is in AUTO with a set
point of 300 m3/hr.
16. Check the discharge pressure is normal at 6.50 barg from the pressure gauge
91-PG-1522.
17. Slowly open the discharge valve of the pump and fill the discharge line.
18. Open the Lean amine to Acid Gas Amine Absorber 9103-C-11 isolation valve and fill
the downstream lines.
19. Open the flow control valve 91-FV-1501 slowly and start filling up the Acid Gas
Amine Absorber 9103-C-11 with the amine.
20. Ensure that the Acid Gas Rich Amine Pumps 9103-P-12 A/B suction isolation valves
are closed.
21. Ensure that the level is increasing in the Acid Gas Amine Absorber 9103-C-11 by
checking the level transmitter 91-LT-1505 & level gauge 91-LG-1505A/B/C/D.
22. Ensure that the low low level alarm 91-LALL-1516 is cancelled as the level rises.
23. Ensure that the low level alarm 91-LAL-1506 is cancelled is cancelled as the level
rises.
24. When the level reaches 100%, close the flow control valve 91-FV-1501 fully and
close the isolation valve at pump discharge which is going to the Acid Gas Amine
Absorber 9103-C-11.
6.3.2.7
Filling Lean Amine Filters 9103-S-11/12/13 with Lean Amine Solution
1.
Ensure that the Lean Amine Pump 9103-P-13A is running on minimum flow.
2.
Ensure that the drain and vent valves in the Lean Amine Filters 9103-S-11/12/13
are closed.
3.
Ensure that Lean Amine Filter 9103-S-11 and Fines Filter 9103-S-13 elements are
fixed in the respective filter elements.
4.
Ensure that the Activated carbon Filter 9103-S-12 is loaded with the media and
boxed up.
5.
Ensure that the amine from Amine Sump Pump isolation valve is isolated near the
filters.
6.
Ensure that the upstream and downstream isolation valves of the 91-PSV-1512 are
opened, the upstream isolation valve is closed for 91-PSV-1513 and the bypass
valve is closed for Lean Amine Filter 9103-S-11.
7.
Ensure that the upstream and downstream isolation valves of the 91-PSV-1515 are
opened, the upstream isolation valve is closed for 91-PSV-1514 and the bypass
valve is closed for Activated Carbon Filter 9103-S-12.
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8.
Ensure that the upstream and downstream isolation valves of the 91-PSV-1517 are
opened, the upstream isolation valve is closed for 91-PSV-1516 and the bypass
valve is closed for Fines Filter 9103-S-13.
9.
Ensure all the instruments in the Lean Amine Filters are lined up.
10. Ensure that the bypass for the Activated Carbon Filter and Fines Filter is closed.
11. Open slowly the Lean Amine Pump 9103-P-13A/B discharge isolation valve to the
filters and fill up the lines.
12. Crack open the Lean Amine Filter 9103-S-11 vent valve at the top.
13. Line up the flow control valve 91-FV-1507 and slowly open 91-FV-1507 on manual.
14. Slowly fill up the Lean Amine Filter 9103-S-11 until all the nitrogen is displaced
through the vent and the amine just starts to overflow through the vent.
15. Close the vent valve at the top of the Lean Amine Filter 9103-S-11.
16. Crack open the vent valve at the top of the Activated Carbon Filter 9103-S-12.
17. Crack open the inlet isolation valve for the Activated Carbon Filter 9103-S-12 from
the Lean Amine Filter 9103-S-11.
18. Fill the vessel with amine by displacing nitrogen through the vent valve at the top.
19. When the amine just starts to overflow through the vent valve, close the valve
immediately.
20. Crack open the vent valve of the Fines Filter 9103-S-13 at the top.
21. Crack open the inlet isolation valve for the Fines Filter 9103-S-13 and start filling
the vessel with amine.
22. The nitrogen inside the vessel is displaced through the vent and when the amine
just starts to overflow through the vent immediately close the vent valve.
23. Open the outlet valve of the Fines Filter 9103-S-13 and fill the line up to the
Amine Surge Tank 9103-T-11.
6.3.2.8
Lining up of Lean Amine Filters 9103-S-11/12/13
1.
Ensure that the Lean Amine Filter 9103-S-11, Activated Carbon Filter 9103-S-12
and Fines Filter 9103-S-13 are filled with the amine.
2.
Open the Lean amine Filters outlet isolation valves and line up the amine to the
Amine Surge Tank 9103-T-11.
3.
Take Lean Amine Filters inlet control valve 91-FV-1507 in manual and slowly open
the control valve so that the amine starts to flow through the amine filters.
4.
Slowly open the control valve till the flow measured by 91-FT-1507 reaches
155.6 m3/hr.
5.
Put the flow control valve 91-FV-1507 in auto with a set point of 155.6 m3/hr.
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6.
Check the pressure drop across the Lean Amine Filter 9103-S-11 and ensure that it
is less than 0.7 barg from 91-PDT-1517.
7.
Check the pressure drop across the Activated Carbon Filter 9103-S-12 and ensure
that it is less than 0.7 barg from 91-PDT-1518.
8.
Check the pressure drop across the Fines Filter 9103-S-13 and ensure that it is less
than 0.7 barg from 91-PDT-1519.
6.3.2.9
Transfer of Amine from Acid Gas Amine Absorber 9103-C-11 to the Amine
Regenerator 9103-C-12
1.
Ensure that all the drain valves in the Rich amine line to the Lean/Rich Amine
Exchanger 9103-E-11A/B and to the Regenerator 9103-C-12 are closed.
2.
Open the suction isolation valves of Acid Gas Rich Amine Pumps 9103-P-12A/B and
fill the suction lines.
3.
Prime the pumps by opening the casing vent valves of the pumps and releasing
Nitrogen.
4.
Put the switch position of the Acid Gas Rich Amine Pumps 9103-P-12A/B to
‘LOCAL’ position.
5.
Ensure that the Acid Gas Rich Amine Pumps 9103-P-12A/B are energized.
6.
Line up the Rich Amine Pump 9103-P-12A minimum flow control valve 91-FV-1508
and open it manually by 50%.
7.
Start the Acid Gas Rich Amine Pump 9103-P-12A from local control station on
minimum flow.
8.
Check the discharge pressure is normal at 7.50 barg from the pressure gauge
91-PG-1536.
9.
Ensure that the pump is running without any abnormal noise and vibration.
10. Open the discharge valves of the pump slowly and fill the discharge line and
circulate the Rich Amine back to the Acid Gas Amine Absorber 9103-C-11 through
the minimum flow line control valve 91-FV-1508.
11. Open the Rich amine to Lean/Rich Exchanger inlet isolation valves 9103-E-11A/B
and fill the downstream lines and the exchanger.
12. Open the Lean Rich Exchanger outlet isolation valve and fill the downstream lines
up to 91-FV-1520.
13. Take the flow control valve 91-FV-1520 in manual and open the control valve
slowly and start taking level in Amine Regenerator 9103-C-12.
14. Ensure that the level is increasing in the Amine Regenerator 9103-C-12 by
checking the level transmitter 91-LT-1510 and level gauge 91-1506A/B.
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15. Ensure that the Amine Regenerator 9103-C-12 low low level alarm 91-LALL-1517 is
cancelled as the level rises.
16. Ensure that the Amine Regenerator 9103-C-12 low level alarm 91-LAL-1510 is
cancelled as level increases.
17. When the level reaches 50%, close the flow control valve 91-FV-1520 fully and stop
the Rich Amine Pump 9103-P-12A from the local control station.
18. Check the level in the Acid Gas Amine Absorber 9103-C-11 and ensure that it does
not drop below 50%.
19. If the level drops below 50% in the Acid Gas Amine Absorber 9103-C-11, stop the
Acid Gas Rich Amine Pump 9103-P-12A immediately.
20. Start the Lean Amine Pump 9103-P-13A and fill the Acid Gas Amine Absorber
9103-C-11 as mentioned previously.
6.3.2.10 Filling up of Lean Amine Section with Amine
1.
Ensure that the drain and vent valves of the Hot Lean Amine Pumps 9103-P-17A/B,
lean amine side of the Lean/Rich Exchanger 9103-E-11A/B, Lean Amine Cooler
9103-E-14 and Lean Amine Trim Cooler 9103-E-15 are closed.
2.
Ensure that the Amine Regenerator 9103-C-12 is filled with amine upto 50% level.
Check the level in 91-LT-1510 and also cross check with 91-LG-1506A/B.
3.
Open the Hot Lean Amine Pumps 9103-P-17A/B suction isolation valves slowly and
fill the lines and the pumps with amine by opening the casing vent valves of the
pumps and by releasing Nitrogen.
4.
Ensure that the Hot Lean Amine Pumps 9103-P-17A/B are energized in MCC.
5.
Put the LOR switch of the Hot Lean Amine Pumps 9103-P-17A/B to “LOCAL” at
local control station.
6.
Ensure that the minimum flow line of the Hot Lean Amine Pumps 9103-P-17A/B is
lined up and the flow control valve 91-FV-1512 is opened by 20% on manual.
7.
Start the Hot Lean Amine Pump 9103-P-17A from local control station.
8.
Ensure that the Hot Lean Amine Pump 9103-P-17A discharge pressure is normal at
6.80 barg.
9.
Ensure that the Hot Lean Amine Pump 9103-P-17A is pumping amine back to the
Amine Regenerator 9103-C-12 through the minimum flow control valve 91-FV-1512.
10. Put the minimum flow control valve 91-FV-1512 in ‘Auto’ with a set point of
250 m3/hr.
11. Ensure that the Hot Lean Amine Pumps 9103-P-17A/B discharge ON-OFF valve
91-XV-1507 is opened.
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12. Open the Hot Lean Amine Pump 9103-P-17A discharge isolation valve slowly and
fill the Lean/Rich Exchanger 9103-E-11A/B inlet strainer and the lean amine side
of the Lean/Rich Exchanger 9103-E-11A/B.
13. Open the Lean/Rich Amine Exchanger 9103-E-11A/B outlet isolation valve and fill
the outlet lines.
14. Open the Lean Amine Cooler 9103-E-14 inlet isolation valves and start filling the
Exchanger.
15. Open the high point vent in the Lean Amine Cooler 9103-E-14 and release
Nitrogen.
16. Close the vent valve when the amine just starts to come out of the vent valve.
17. Open the outlet isolation valve of the Lean Amine Cooler 9103-E-14 and fill the
outlet lines.
18. Ensure that the Amine line from the Lean Amine Cooler 9103-E-14 outlet to the
Analyzer AT-1506 isolation valve is closed.
19. Open the Lean Amine Trim Cooler 9103-E-15 inlet isolation valve and fill the
Cooler with amine.
20. Ensure that the Lean Amine Trim Cooler 9103-E-15 bypass control valve 91-TV1509 is closed.
21. Open the high point vent in the Lean Amine Trim Cooler 9103-E-15 and release
Nitrogen.
22. Close the high point vent isolation valve when the amine just starts to overflow.
23. Open the outlet isolation valve of the Lean Amine Trim Cooler 9103-E-15 and fill
the outlet lines.
24. Check the level in the Amine Regenerator 9103-C-12 through the 91-LT-1510. If
the level is less than 30%, make up the level as previously mentioned to 50%.
25. Put 91-FV-1530 in ‘Manual’ and open the control valve by 10% and line up the
amine to Amine Surge Tank 9103-T-11.
26. Open the Amine Surge Tank inlet isolation valve and line up lean amine to Amine
Surge Tank 9103-T-11.
27. Stop the Hot Lean Amine Pump 9103-P-17A from the local control station.
6.3.2.11 Establishing Amine Circulation in the System
1.
Ensure that Amine Surge Tank 9103-T-11 is having more than 50% level. If not then
make up the tank from road tankers as mentioned previously.
2.
Ensure that the Lean Amine Pump 9103-P-13A/B suction, discharge and minimum
flow lines are lined up.
3.
Put the LOR switch of the Lean Amine Pump in ‘Remote’.
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4.
Start the Lean Amine Pump 9103-P-13A from ICSS and put 9103-P-13B in AUTO.
5.
Open the minimum flow control valve 91-FV-1511 in manual and adjust the valve
opening to ensure a minimum flow of 375 m3/Hr.
6.
Now put the minimum flow control valve in auto with a set point of 375 m3/hr.
7.
Reset Process Shutdown and ensure that the Acid Gas Amine Absorber 9103-C-11
inlet ON-OFF valve 91-XV-1504 is opened.
8.
Open the Lean Amine Pump 9103-P-13A/B discharge valve to the Acid Gas Amine
Absorber 9103-C-11.
9.
Open the Acid Gas Amine Absorber 9103-C-11 inlet flow control valve 91-FV-1501
in manual by 10%.
10. Ensure that the level in Acid Gas Amine Absorber 9103-C-11 is rising by checking
the level transmitter 91-LT-1505.
11. Ensure that the Acid Gas Rich Amine Pumps 9103-P-12A/B suction, discharge and
minimum flow isolation valves are lined up and the pumps are primed.
12. Put the Acid Gas Rich Amine Pumps 9103-P-12A/B LOR switch in ‘Remote’ and
start the pump 9103-P-12A from ICSS and put the pump 9103-P-12B in AUTO.
13. Open the minimum flow control valve 91-FV-1508 in manual and adjust the valve
opening to get a flow of 375 m3/hr.
14. Take the minimum flow control valve 91-FV-1508 in Auto with a set point of
375 m3/hr.
15. Ensure that the Rich Amine to the Amine Regenerator 9103-C-12 isolation valves
are lined up.
16. Open the Amine Regenerator inlet control valve 91-FV-1520 to 10% in manual.
17. Ensure that the level in the Amine Regenerator started to rise through 91-LT-1510.
18. Ensure that the suction, discharge and the minimum flow lines are lined up.
19. Put the LOR switch of the Hot Lean Amine Pumps 9103-P-17A/B in ‘Remote’ and
start the pump 9103-P-17A from ICSS and put the pump 9103-P-17B in AUTO.
20. Open the minimum flow control valve 91-FV-1512 in manual and adjust the control
valve opening to get a minimum flow of 250 m3/hr.
21. Put the control valve 91-FV-1512 in auto with a set point of 250 m3/hr.
22. Ensure that the Hot Lean Amine Pumps 9103-P-17A/B discharge ON-OFF valve
91-XV-1507 is open.
23. Line up the Hot Lean Amine Pumps discharge to the Lean/Rich Amine Exchanger
9103-E-11, Lean Amine Cooler 9103-E-14, Lean Amine Trim Cooler 9103-E-15 and
the Amine Surge Tank 9103-T-11.
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24. Slowly increase the flow rate from the Lean Amine Surge Tank 9103-T-11 to the
Acid Gas Amine Absorber 9103-C-11 by opening the control valve 91-FV-1501 to
487 m3/hr.
25. Ensure that the minimum flow control valve of the Lean Amine Pumps 9103-P13A/B is closed.
26. Correspondingly to maintain level in the Acid Gas Amine Absorber, open the flow
Control valve 91-FV-1520 manually till the level is maintaining. Now put the flow
control valve in auto with a set point of 487 m3/hr.
27. Ensure that the minimum flow control valve 91-FV-1508 of the Acid Gas Rich
Amine Pumps 9103-P-12A/B is closed.
28. To maintain the level in the Amine Regenerator 9103-C-12, open the flow control
valve 91-FV-1530 slowly till the level in the Regenerator is maintaining.
29. Put flow control valve 91-FV-1530 in auto with a set point of 487 m3/hr.
30. Ensure that the minimum flow control valve 91-FV-1512 of the Hot Lean Amine
Pumps 9103-P-17A/B is closed.
31. Open the Sea Cooling water inlet isolation valve of the Lean Amine Trim Cooler
9103-E-15 and fill the cooler.
32. Open the Sea Cooling water outlet isolation valve and establish the cooling water
flow.
33. Ensure that the temperature control valve 91-TV-1509 of the lean amine in the
Lean Amine Trim Cooler 9103-E-15 is closed.
34. Ensure that the temperature control valve 91-TV-1513 of the lean amine in the
Lean/Rich Exchanger 9103-E-11A/B is closed.
6.3.2.12 Lining up of Regenerator Overhead System
1.
Ensure that the drain and vent isolation valves in the Regenerator overhead
system are closed.
2.
Ensure that the Regenerator overhead 91-PSV-1508 isolation valves are lined up,
91-PSV-1509 upstream isolation valve is closed and the bypass valves are closed.
3.
Ensure that the Regenerator Condenser Cooler 9103-E-12 inlet and outlet isolation
valves are lined up and the vent and drain valves are closed.
4.
Ensure that the Regenerator Condenser Trim Cooler 9103-E-16 inlet and outlet
isolation valves are lined up and the vent and drain valves are closed.
5.
Ensure that the Regenerator Reflux Drum 9103-V-12 drain and vent valves are
closed.
6.
Ensure that the Regenerator Reflux Drum 9103-V-12 pressure control valves 91-PV1503A/B are lined up and they are in closed condition.
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7.
Ensure that the Regenerator Reflux Drum 9103-V-12 acid gas to Acid Gas KO Drum
9101-V-04 line ON-OFF valve XV-1516 is open.
8.
Put the Regenerator Reflux Drum 9103-V-12 pressure controller 91-PIC-1503 in
Auto with a set point of 1.0 barg and the pressure control valves 91-PV-1503A/B in
Remote.
9.
Line up DM water to the Regenerator Reflux Drum 9103-V-12 by opening the flow
control valve 91-FV-1521 manually.
10. Check that the level in the Regenerator Reflux Drum 9103-V-12 is increasing by
checking the level gauge 91-LG-1502 and 91-LT-1506.
11. When the level in the Regenerator Reflux Drum 9103-V-12 is around 40% close the
DM water make up and the flow control valve 91-FV-1521.
12. Start the Regenerator Condenser Cooler fans 9103-EM-12AA/AB/AC/BA/BB/BC/
CA/CB/CC/DA/DB/DC.
13. Line up sea cooling water to the Regenerator Condenser Trim Cooler 9103-E-16 by
opening the inlet and outlet isolation valves.
14. Line up the Regenerator Condenser Trim Cooler 9103-E-16 temperature control
valve 91-TV-1509 and put it on Auto with a set point of 49°C.
6.3.2.13 Lining up of Regenerator Reboiler 9103-E-13 System
1.
Ensure that the Regenerator Reboiler 9103-E-13 is filled with amine solution by
checking the level gauge 91-LG-1503.
2.
Open the drain valve upstream of Reboiler steam inlet ON-OFF valve 91-XV-1505
and drain all the condensate.
3.
Warm up the steam line upstream of Reboiler steam inlet ON-OFF valve 91-XV1505 till there is full fledged steam coming out from the drain valve.
4.
Close the drain valve. Open the drain valve downstream of the Reboiler steam
inlet ON-OFF valve 91-XV-1505 and drain all the condensate.
5.
Reset Process shutdown and ensure that Reboiler steam inlet ON-OFF valve 91-XV1505 is open.
6.
Open the bypass valves of the Reboiler Steam inlet flow control valve 91-FV-1503
and start warming up the steam lines and Reboiler tubes.
7.
Ensure that Regenerator Reboiler Condensate Pot 9103-V-13 is also being warmed
up through the equalisation line.
8.
Open the drain valve in the condensate outlet line of the Regenerator Reboiler
Condensate Pot 9103-V-13.
9.
When all the condensate is drained and steam is coming out of the drain, close the
drain valve.
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10. Open the Reboiler condensate outlet line drain valve and drain all the condensate.
11. Warm up the Reboiler tubes till hot condensate comes out of the drain line.
12. Open the Reboiler steam inlet flow control valve 91-FV-1503 by 5% and heat the
Reboiler amine solution.
13. Close the drain line valve and allow the condensate level to be built up in the
Regenerator Reboiler Condensate Pot 9103-V-13.
14. Ensure that the level is building up in the Regenerator Reboiler Condensate Pot
9103-V-13 by checking the level gauge 91-LG-1504A/B.
15. Ensure that low level alarm 91-LAL-1508 is cancelled in the Pot.
16. Line up Regenerator Reboiler Condensate Pot 9103-V-13 condensate outlet line
level control valve 91-LV-1508 and put the controller in auto with a set point of
50%.
17. Ensure that the level in Regenerator Reboiler Condensate Pot 9103-V-13 is
maintained at 50%.
18. Gradually increase the opening of the steam inlet control valve 91-FV-1503 and
heat the amine solution at a rate of 25°C/hr till the Regenerator bottom
temperature reaches 130°C.
19. Put the Reboiler steam inlet flow controller 91-FIC-1503 in “Remote” and enter
the ratio of steam to rich amine at 118.5 in the ratio controller 91-HIC-1503 and
take the ratio controller in Auto.
20. Put the Regenerator top temperature controller 91-TIC-1510 in Auto with a set
point of 118°C.
21. Line up the Regenerator Reflux Drum Pumps 9103-P-11A/B by opening the suction
and discharge valves and priming the pumps by opening the casing vent and
releasing Nitrogen.
22. Ensure that the Regenerator Reflux Drum Pumps 9103-P-11A/B discharge to the
Waste Water Degasser is isolated.
23. Ensure that the Regenerator Reflux Drum Pumps 9103-P-11A/B minimum flow line
control valve FV-1505 is lined up.
24. Put the minimum flow controller 91-FIC-1505 in Auto with a set point of 20 m3/hr.
25. Put the LOR switch of the Regenerator Reflux Drum Pumps 9103-P-11A/B in
‘Remote’ position.
26. Start the Regenerator Reflux Drum Pumps 9103-P-11A from the ICSS and put
9103-P-11B in AUTO.
27. Line up the reflux from the Regenerator Reflux Drum Pumps 9103-P-11A to the
Regenerator 9103-C-12 by lining up the control valve 91-FV-1531.
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28. Put the level controller 91-LIC-1506 of the Regenerator Reflux Drum 9103-V-12 in
Auto with a set point of 50%.
29. Put the reflux flow control valve 91-FV-1531 in remote mode.
30. Ensure that the top temperature of the Regenerator is being maintained at around
118°C.
6.3.2.14 Lining up of Acid Gas to the Acid Gas Amine Absorber
1.
Ensure that the vent and drain valves in the Acid Gas Coolers 9103-E-101A/B, Lean
Acid Gas KO Drum 9103-V-14, Acid Gas KO Drum Return Pumps 9103-P-14A/B are
closed.
2.
Ensure that the sea cooling water to Acid Gas Coolers 9103-E-101A/B inlet filter
elements are fixed and boxed up.
3.
Open the Sea Cooling water inlet and outlet isolation valves and line up sea
cooling water to Acid Gas Coolers 9103-E-101A/B.
4.
Ensure that the 91-VRV-1577 upstream isolation valve is lined up in the sea cooling
water inlet of Acid Gas Coolers 9103-E-101A/B.
5.
Ensure that the 91-VRV-1578 upstream isolation valve is lined up in the sea cooling
water outlet of Acid Gas Coolers 9103-E-101A/B.
6.
Ensure that the 91-TSV-1501 upstream isolation valve is opened & 91-TSV-1502
upstream isolation valve is closed in the sea cooling water outlet of Acid Gas
Coolers 9103-E-101A/B.
7.
Ensure that the 91-PSV-1501 in Lean Acid Gas KO Drum 9103-V-14 isolation valves
is opened, 91-PSV-1502 upstream isolation valves are closed and the bypass valves
are closed.
8.
Reset Process shutdown from ICSS.
9.
Ensure that Acid Gas inlet ON-OFF valve 91-XV-1501 is opened to the Acid Gas
Cooler 9103-E-101A/B and the ON-OFF valve 91-XV-1502 to the Acid Gas Flare
Header is closed.
10. Open the isolation valves downstream of ON-OFF valve 91-XV-1502 and lock the
valves in open position.
11. Open the isolation valve upstream of ON-OFF valve 91-XV-1501 and lock the valve
in open position.
12. Line up pressure control valve 91-PV-1502 of the Acid Gas Amine Absorber 9103-C11 and take the pressure controller 91-PIC-1502 in Auto with a set point of
0.2 barg.
13. Ensure that the 91-PSV-1503 in Acid Gas Amine Absorber 9103-C-11 isolation valves
are lined up and the PSV-1504 upstream isolation valves are closed and the bypass
valves are closed.
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14. Inform AGRU 1 & 2 (Existing units) to line up Acid Gas to AGEU.
15. Open the isolation valves of the Acid Gas line to AGEU in the battery limit slowly
and admit acid gas into the Acid Gas Coolers 9103-E-101A/B.
16. Ensure that the temperature of the acid gas at the outlet of the acid gas coolers is
53°C by checking the temperature indicator 91-TI-1501.
17. When there is an increase in the level of the Lean Acid Gas KO Drum which is read
from the LG-1501A/B & LT-1501, Line up Acid Gas KO Drum Return Pumps 9103-P14A/B.
18. Open the suction isolation valves of the Acid Gas KO Drum Return Pumps 9103-P14A/B and prime the pumps by opening the casing vents and releasing Nitrogen.
19. Reset process shutdown and ensure that the ON-OFF valve 91-XV-1503 in the pump
discharge is open.
20. Ensure that the pumps 9103-P-14A/B discharge to the Sour Water Stripper 6922-C01 is isolated.
21. Put the LOR switch of the pumps in ‘Remote’ and start the pump 9103-P-14A from
ICSS and put pump 9103-P-14B in AUTO.
22. Open the pump discharge valves and then open LV-1501 gradually.
23. Put the Lean Acid Gas KO Drum level controller 91-LIC-1501in auto with a set point
of 50%.
24. Put the lean amine flow control valve 91-FV-1501 to the Acid Gas Amine Absorber
9103-C-11 in ratio control with the acid gas feed.
25. Check the Incinerator 9101-F-14 performance as acid gas is routed to it from the
Acid Gas Amine Absorber.
26. Open 91-PV-1503A in manual and route acid gases from Regenerator Reflux Drum
9103-V-12 to flare. Keep 91-PV-1503B closed in manual.
27. When the acid gases produced from Regenerator is stabilized, put the pressure
controller 91-PIC-1503 in Auto with a set point of 1.0 barg.
28. Check the differential pressure 91-PDT-1522 in the Acid Gas Amine Absorber and
91-PDT-1523 in the Amine Regenerator 9103-C-12. If the differential pressures
shows increasing trend then antifoam has to be dosed to amine feed to that
tower.
29. After stabilising the plant, inform NGL-1/2/4 to line up acid gases one by one.
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6.3.3
Start-Up of Sulphur Recovery Unit
The first start-up of the SRU following a major overhaul may be carried out
independent of the TGTU BSR Section. In this case the SRU tail gases will be routed to
the Incinerator and closed to the TGTU. The start-up of sulphur recovery unit involves
the following activities:
1.
Confirm LP heating steam is in service to all sulphur lines, Sulphur Degassing Pit
9101-T-01/01B heating coils and trace heating lines.
2.
Confirm acid gas shutdown valve 9103-XV-1516 from the upstream amine
Regenerator Reflux Drum 9103-V-12 to the Acid Gas KO Drum 9101-V-04 is closed.
3.
Confirm that the SRU tail gas ON/OFF valve 91-XV-1097 from the Final Separator
9101-V-05 to the Incinerator 9101-F-14 is open.
4.
Confirm that the SRU tail gas ON/OFF valve 9101-XV-1098 from Final Separator
9101-V-05 to the Tail Gas Treatment Unit is closed.
5.
Introduce BFW to the SRU Reaction Furnace Boiler 9101-E-07 Steam Drum 9101-V07 and establish a normal operating water level in the vessel.
6.
Introduce BFW through the BFW Preheater and establish normal operating levels in
the Last Condenser, Reaction Furnace Condenser 9101-E-01 and 1st Stage
Condenser 9101-E-02.
7.
Now Reaction Furnace burner to be started to heat up the system.
6.3.3.1
Start-up of Reaction Furnace (9101-F-01) Burner
Reaction Furnace-BMS sequence
The burner management system of Reaction Furnace is incorporated in ESD system.
Reaction furnace LCP 9101-F-01–LP-005 hand switches detail is tabulated below:
Sl. #
Tag No.
Description
1.
91-HS-1211
Start purge
2.
91-HS-1212
Start ignition
3.
91-HS-1213
Emergency shutdown
4.
91-HS-1214
Lamp test
Reaction Furnace 9101-F-01 hardwired auxiliary console hand switches detail is
tabulated below:
Sl. #
Tag No.
Description
1.
91-HS-1217
Acid gas ON/OFF
2.
91-HS-1218
Fuel gas ON/OFF
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Reaction furnace LCP 9101-F-01–LP-005 lamp indication detail is tabulated below:
Sl. #
Tag No.
Description
1.
91-XA-1211
Reaction furnace burner shutdown
2.
91-XL-1212
Ready for purge
3.
91-XL-1213
Purge ON
4.
91-XL-1214
Ready for ignition
5.
91-XL-1215
Ignition ON
6.
91-XL-1216
Fuel gas ON
7.
91-XL-1217
Acid gas ON
8.
91-BAL-1055A
Flame-1 ON
9.
91-BAL-1055B
Flame-2 ON
Reaction Furnace 9101-F-01 soft pushbutton details in DCS is tabulated below:
Sl. #
Tag No.
Description
1.
91-HS-1216
Quench steam valve 91-XV-1078 ON/OFF
2.
91-HS-1040
Quench steam valve 91-XV-1079 ON/OFF
3.
91-HS-1219
Nitrogen valve ON/OFF switch
4.
91-HS-1220
System reset
5.
91-HS-1017
Start-up bypass for 91-PALL-1025
Control valve/ON-OFF valve details are tabulated below:
Sl. #
Tag No.
Description
1.
91-XV-1048
Fuel gas shut-off valve-1
2.
91-XV-1099
Fuel gas shut-off valve-2
3.
91-XV-1100
Fuel gas vent valve
4.
91-FV-1009
Fuel gas flow control valve
5.
91-XV-1001
Acid gas shut-off valve
6.
91-XV-1102
Acid gas shut-off valve
7.
91-XV-1110
Nitrogen shut-off valve
8.
91-XV-1127
Nitrogen shut-off valve
9.
91-XV-1101
Main combustion air shut-off valve
10.
91-FV-1002
Combustion air control valve
11.
91-FV-1002B
Secondary air control valve
12.
91-FV-1003
Make-up air control valve
13.
91-XV-1078
Quench steam ON/OFF valve
14.
91-XV-1079
Quench steam ON/OFF valve
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The burner light-on is carried out in three steps:
i.
System reset
ii.
Pre-ignition purge
iii.
Fuel gas burner light-on
i.
System Reset
1.
Check the following shutdown interlocks are absent in the ICSS:
Sl. #
Tag No.
Description
1.
91-HS-1012A
Reaction furnace ESD pushbutton (CCR)
2.
91-HS-1213
Reaction furnace ESD pushbutton (LCP)
3.
65-XS-1008
AGR shutdown
4.
91-BSL-1055A/B
Flame failure of reaction furnace (2oo2)
5.
65-HS-001
General plant shutdown activation (existing)
6.
65-XA-1001
Existing SRU shutdown
7.
91-TT-1050
Rupture pin failure
8.
65-XS-1024
Total power Shutdown
9.
65-PT-1003A/B/C
Instrument air pressure low-low
10.
65-XS-1015
Steam pressure failure (low low pressure)
11.
91-HS-1011
Unit-91 general shutdown button
12.
91-XS-1901
Confirmed gas detection
13.
65-XS-1020
Fuel gas low-low pressure
14.
91-LT-1003
Acid gas KOD (9101-V-04) high-high level
15.
91-LT-1006
Steam drum (9101-V-07) low-low level
16.
91-LT-1009
RF condenser (9101-E-01) low-low level
17.
91-LT-1012
1st condenser (9101-E-02) low-low level
18.
91-PT-1025
Acid gas inlet low-low pressure
19.
91-XS-1063/1064
Blowers (9101-K-01A/B) are not running
20.
91-PT-1054A/B/C
Air for acid gas burner high-high pressure
21.
91-FT-1140
Acid gas to reaction furnace low-low flow
22.
91-FT-1129
Process air to acid gas burner flow low-low
23.
91-FT-1130
Fuel gas to reaction furnace flow low-low
If the above conditions do not exist, the Reaction furnace BMS system can be reset.
When the BMS reset is pressed, following shutdown causes are automatically bypassed
during start-up:
a.
91-FT-1129 (Combustion Air low-low flow)
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b.
91-FT-1130 (Fuel gas to reaction furnace low-low)
c.
91-FT-1140 (Acid gas to reaction furnace low-low)
d.
91-BSL-1055A/B (Flame detector signal)
e.
91-PT-1025 (Acid gas I/L pressure low-low)
2. Start any one of Process Air Blower 9101-K-01A & 9101-K-01B.
3. The following conditions are to be satisfied for the pre-ignition purge:
a.
No flame present – 91-BSL-1055A/91-BSL-1055B.
b.
Fuel Gas cut-in valve XV-1048 is in close position – 91-ZSC-1048.
c.
Fuel Gas cut in valve XV-1099 is in close position - 91-ZSC-1099.
d.
Fuel Gas vent valve XV-1100 is in open position - 91-ZSO-1100.
e.
Ensure “READY FOR RESET” (91-XL-1218) is lit in ICSS.
4. RESET the system by pressing the Soft switch 91-HS-1220 from DCS and ensure the
following:
a.
Energizing of combustion air control valve SOV 91-FY-1002B and 91-FY-1002.
b.
Process air flow controller 91-FIC-1002, 91-FIC-1002B to manual mode and
output at start position.
c.
Fuel gas flow controller 91-FRC-1009 to manual mode and output at start
position.
d.
“READY FOR PURGE” lamp (91-XL-1212) is lit on the local panel and also in
ICSS.
e.
“SYSTEM IN SHUTDOWN” lamp 91-XA-1211 will extinguish on the LCP and ICSS.
ii. Pre-ignition Purge
1.
Ensure the control valves for combustion air 91-FV-1002, fuel gas control valve
91-FV-1009 and steam valves are in start position at the ICSS and in field.
2.
Press the start purge button 91-HS-1211 at the local control panel.
3.
Ensure the “SYSTEM READY FOR PURGE” is unlit.
4.
Ensure that the Nitrogen shutdown valve 91-XV-1127 for furnace purging and 91XV-1110 for flame scanner, sight glass purging are opened.
5.
Ensure that main Process air shutdown valve 91-XV-1101 is closed.
6.
Verify whether the ‘PURGE ON’ lamp 91-XL-1213 is lit for 20 minutes (purge timer)
in the Local Control Panel.
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7.
After the purge time is over, ensure that the ‘PURGE ON’ lamp 91-XL-1213 is unlit
in the Local Control Panel.
8.
Ensure that ‘PURGE COMPLETE’ lamp 91-XL-1219 is lit on the ICSS.
9.
Ensure the “READY FOR IGNITION” lamp 91-XL-1214 is lit on local panel.
10. Ensure that the Nitrogen cut-in valve 91-XV-1127 is closed.
iii. Fuel Gas Burner Light On
1.
Ensure that the air inlets, burner and outlet passages are boxed up and free of
foreign material.
2.
Ensure that all personnel have been evacuated from the reaction furnace area,
ductwork and associated equipment and all access and inspecting doors closed and
sealed.
3.
Ensure that the Process Air Blower 9101-K-01A/B is running.
4.
Ensure that all safety shut off valves are closed.
5.
Ensure that the Fuel System vents are open and venting to atmosphere. Lines are
properly drained and cleared of condensate.
6.
Ensure that a complete functional check of the safety interlocks has been made.
7.
Ensure that the area is clear of obvious safety hazards and flammable gases are
not present in the area.
8.
Ensure that all lines have been blown down with plant air to insure they are free
of debris that might plug metering orifices and burner tips.
9.
Ensure that utilities like fuel gas, instrument air, nitrogen and plant air are
available and initial operational checks performed on the elements in each line.
10. Ensure that the burner elements are in their proper position.
11. Ensure that power has been supplied to control systems and to safety interlocks.
12. Ensure that the gauges indicating fuel header pressure to the unit are functional.
13. Ensure that the pressure self regulating valves are set according to the instrument
data sheets.
14. Ensure that the isolation valves for all the pressure gauges and pressure
transmitters are open and their respective bleed valves are closed. Valves are
sealed in position as indicated on P&IDs.
15. Ensure that the minimum purge period is satisfactorily completed.
16. Ensure that the control valves of the fuel gas 91-FV-1009, quench steam 91-XV1078, 91-XV-1079 and Combustion Air 91-FV-1002 are closed.
17. Ensure that the igniter is in the correct position and that the fuel gas gun is ready
for operation with fuel gas.
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18. Open the fuel gas control valve 91-FV-1009 and combustion air control valve
91-FV-1002B to the pre-determined position.
19. Press the ‘START IGNITION’ push button 91-HS-1212 from the local control panel.
20. Ensure that ‘READY FOR IGNITION’ lamp 91-XL-1214 is unlit.
21. Ensure that the igniters insert SOV 91-XY-1103 is energised.
22. Ensure that the igniter insertion is proved by limit switch 91-ZSC-1103.
23. Ensure the Process air shutdown valve 91-XV-1101 is opened.
24. Ensure fuel gas bleed valve 91-XV-1100 is closed and fuel gas shutdown valves
91-XV-1048 and 91-XV-1099 are opened.
25. Ensure that the igniter transformer is energised for 10 seconds and sparking
begins.
26. Ensure that the igniter transformer is de-energised and igniter retracts
automatically (91-ZSO-1103) after 10 seconds of ignition timer.
27. If flame is detected then ensure that the ‘FLAME ON’ lamps (91-BAL-1055A,
91-BAL-1055B) are lit on the local control panel.
28. Permit is provided to open the steam quench shutdown valve 91-XV-1078 and
91-XV-1079 from ICSS soft switches.
29. Permit is provided to open the acid gas shutdown valve 91-XV-1102.
30. Ensure that the ‘FUEL GAS ON’ lamp 91-XL-1216, 91-XL-1216A is lit in the Local
Control Panel and ICSS respectively.
31. Open the instrument air purge valve to sight glasses, flame scanners and nozzles.
32. Ensure that the Nitrogen purge valve to sight glasses, flame scanners and nozzles
is closed.
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Fig. 29 – Reaction Furnace Start-up
Start
A
&
Note A
B
Note B
Ready for Reset XL-1218
ON
Y
Purge completed
Acid gas cut-off valves XV-1102, XV1001 and XV-1516 opens
Purge complete XL-1219
System Reset
HS-1220
Acid gas XL-1217 ON
Nitrogen SDV-XV-1127 close
Automatic bypass of combustion
air flow (FT-1129), fuel gas flow
(FT-1130), acid gas flow (FT-1128)
low low alarm and acid gas inlet
pressure (PT-1025) low low alarm
Ready for ignition XL-1214
Start Ignition-HS1212
Furnace is fully operational
Burner light on timer 10 min
starts
Force combustion air FIC1002 and fuel gas FIC-1009
controllers to manual mode
and output to minimum 10%
System ready for purge XL1401
Purge start-HS1211
Common alarm XL1405
Nitrogen SDV-XV-1127,
XV-1110 open
· Igniter insert SOV XY-1103
energized
· combustion air XV-1101 opens
· Fuel gas vent valve XV-1100
closes
· Fuel gas block valves XV-1048
and XBV-1099 opens
· Igniter transformer energized for
10 seconds
Purge timer 20min starts
Purge ON XL-1213
Nitrogen
flow alarm FAL-1131
Should be healthy
within 15 sec
Flame detected
on 1oo2 logic
N
N
Y
BAL-1055A, BAL-1055B ON
Fuel Gas XL-1216
ON
Quench Steam StartHS-1216, HS-1040
Y
XV-1078, XV-1079 open
Purge interlocks
are healthy till purge
timer completes
N
Following causes should be healthy:
· ESD push button in CCR-HS-1012A
· ESD push button HS-1213 in LCP
· General plant shutdown activation 65-HS-001
· Existing SRU shutdown 65-XA-1001
· Total power shutdown 65-XS-1024
· Instrument air LL pressure 65-PT-1003A/B/C
· BFW/steam failure 65-XS-1015
· Unit 91 General shutdown 91-HS-1011
· Confirmed gas detection 91-XS-1901
· Fuel gas LL pressure 65-XS-1020
· Acid gas KOD HH level 91-LT-1003
· Steam drum level low low 91-LT-1006
· Furnace condenser level low low 91-LT-1009
· 1st Condenser level low low 91-LT-1012
· Both blowers (9101-K-01A/B) are not running
(91-XS-1063/1064)
· Air pressure Hi Hi 91-PT-1054A/B/C
· Process air flow low low 91-FT-1129
· Acid gas inlet pressure low low 91-PT-1025
· Fuel gas flow low low 91-FT-1130
· Acid gas flow low low 91-FT-1128
· AGR Shutdown 65-XS-1008
Acid Gas Start-HS1217
Light ON timer out XL-1406
Y
B
A
Gradually open acid gas control valve
91-FV-1503B and close fuel gas
control valve 91-FV-1009 close
Following are the permissives for purging:
· No flame detection by BSL-1055A/B
· FG Block valve XV-1048 in close position
· FG Block valve XV-1099 in close position
· FG Vent valve XV-1100 in open position
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6.3.3.2
Heating Up the System
1. Take fuel gas controller 91-FIC-1009 in manual and slowly increase the fuel gas to
Reaction Furnace.
2. Take the combustion air controller 91-FIC-1002/91-FIC-1002B in manual and
increase the combustion air to the Reaction Furnace.
3. Proceed to heat up the Reaction Furnace at 50°C/hr
Note
1) If the converters have been filled with catalyst following the unit’s precommissioning refractory dry out phase, then for the first start-up of the unit,
the rate of temperature increase of the process air must be initially controlled
to slowly heat up the converters at 10-15°C/hr to 90°C to ensure any free
water and moisture is removed in the converters catalyst beds. In this case the
introduction of BFW to the steam generators will be delayed until the
converters catalyst beds are first heated through to 90°C.
2) As the SRU process gas system and the SRU converters does not contain sulphur
compounds at this time, firing of fuel gas in the Reaction Furnace burner may
be carried out in excess air conditions.
4. Open LP steam shutdown valve 91-XV-1079 to the Reaction Furnace.
5. To suppress the formation of carbon and soot at stoichiometric firing conditions,
introduce LP steam to the SRU Reaction Furnace burner fuel gas line when a
temperature of >300°C is seen in the Reaction Furnace and the SRU converters are
heated through to >120°C. Set the steam flow in the ratio of 1:1 (by wt.) of fuel
gas. Note that the furnace temperature will dictate the amount of steam used. Too
much steam could result in interference of the burners flame detectors resulting in
a burner trip. Before opening steam valves ensure steam lines are fully drained of
condensate.
6. Continue to heat up the Reaction Furnace at 50°C/hr
7. When steam blows from the SRU Reaction Furnace Boiler 9101-E-07 atmospheric
vent, set Reaction Furnace Boiler pressure controller 91-PV-1003 in automatic
mode at 24.0 barg and route excess steam to the LP steam system.
8. Using the MS steam produced in the SRU Reaction Furnace Boiler, heat the Process
Air Pre-heater 9101-E-05 outlet process air temperature at 50°C/hr to 210°C
9. When steam emits from each LP Steam Generator 9101-E-01/9101-E-02
atmospheric vents, close vents and route excess steam to the LP steam system.
10. Open LP steam to 9101-E-08 and start heating the BFW to 120°C.
11. Now the 1st Stage Auxiliary Burner 9101-F-02 and the 2nd Stage Auxiliary Burner
9101-F-03 to be started to heat up the converters up to their normal operating
temperatures.
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6.3.3.3
1st Stage Auxiliary Burner 9101-F-02 Start-up
1st Stage Auxiliary Burner - BMS Sequence
The burner management system of 1st Stage Auxiliary Burner is incorporated in ESD
system.
1st stage auxiliary burner LCP 9101-F-102 –LP-006 hand switches detail is tabulated
below:
Sl. #
Tag No.
Description
1.
91-HS-1226
Start burner
2.
91-HS-1227
Stop burner
3.
91-HS-1228
Lamp test
1st stage auxiliary burner 9101-F-02 hardwired aux console hand switches detail is
tabulated below:
Sl. #
Tag No.
Description
1.
91-HS-1223
Acid gas ON/OFF
2.
91-HS-1224
Fuel gas ON/OFF
1st stage auxiliary burner LCP 9101-F-102–LP-006 lamp indication detail is tabulated
below:
Sl. #
Tag No.
Description
st
1.
91-XA-1226
1 stage burner shutdown
2.
91-XL-1227
Ready for ignition
3.
91-XL-1228
Ignition ON
4.
91-XL-1229
Fuel gas ON
5.
91-XL-1230
Acid gas ON
6.
91-BAL-1003A
Flame-1 ON
7.
91-BAL-1003B
Flame-2 ON
System Reset to be done by activating the soft push button 91-HS-1225 in DCS.
Control valve/ON-OFF valve details are tabulated below:
Tag No.
Sl. #
Description
1.
91-XV-1028
Fuel gas block valve-1
2.
91-XV-1131
Fuel gas block valve-2
3.
91-XV-1132
Fuel gas vent valve
4.
91-FV-1018
Process air control valve
5.
91-FV-1019
Acid gas control valve
6.
91-FV-1020
Fuel gas control valve
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The burner light-on is carried out in below steps:
i.
System Reset
ii.
Fuel Gas Burner Light-On
iii.
Acid Gas Introduction
i.
System Reset
1.
Check the following shutdown interlocks are absent in the ICSS:
•
Reaction furnace shutdown
•
1st stage auxiliary burner flame failure (91-BALL-1003A/B)
•
Acid gas flow low-low (91-FT-1134)
•
Fuel gas flow low-low (91-FT-1135)
•
Combustion air flow low-low (91-FT-1133)
If the above conditions do not exist, the 1st stage auxiliary burner BMS system can be
reset.
2. When the BMS reset is pressed, following shutdown causes are automatically
bypassed during start-up (start-up override)
a.
91-FT-1133 (Combustion Air low-low flow)
b.
91-FT-1135 (Fuel gas flow low-low)
c.
91-FT-1134 (Acid gas flow low-low)
3. Ensure that any one of Process Air Blower 9101-K-01A & 9101-K-01B is started and
running.
4. If the above conditions are satisfied then ensure “1st STAGE BURNER READY FOR
RESET” (91-XL-1232) is lit in ICSS.
5. RESET the system by pressing the Soft switch 91-HS-1225 from ICSS and ensure the
following:
a.
Energizing of fuel gas control valve SOV 91-FY-1020.
b.
Combustion air flow controller 91-FIC-1018 to manual mode and output at
start position.
c.
Fuel gas flow controller 91-FIC-1020 to manual mode and output at start
position.
d.
“READY FOR IGNITION” lamp 91-XL-1227 and 91-XL-1227A is lit on the local
panel and also in ICSS respectively.
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e.
“SYSTEM IN SHUTDOWN” lamp 91-XA-1226 and 91-XA-1226A will extinguish on
the LCP and ICSS, respectively.
ii. Fuel Gas Burner Light On
1.
Ensure that the air inlets, burner and outlet passages are boxed up and free of
foreign material.
2.
Ensure that all safety shut off valves are closed.
3.
Ensure that the Fuel System vents are open and venting to atmosphere. Lines are
properly drained and cleared of condensate.
4.
Ensure that a complete functional check of the safety interlocks has been made.
5.
Ensure that the area is clear of obvious safety hazards and flammable gases are
not present in the area.
6.
Ensure that all lines have been blown down with plant air to insure they are free
of debris that might plug metering orifices and burner tips.
7.
Ensure that utilities like fuel gas, instrument air, plant air and nitrogen are
available and initial operational checks performed on the elements in each line.
8.
Ensure that the burner elements are in their proper position.
9.
Ensure that power has been supplied to control systems and to safety interlocks.
10. Ensure that the gauges indicating fuel header pressure to the unit are functional.
11. Ensure that the pressure self regulating valves are set according to the instrument
data sheets.
12. Ensure that the isolation valves for all the pressure gauges and pressure
transmitters are open and their respective bleed valves are closed. Valves are
sealed in position as indicated on P&IDs.
13. Ensure that the minimum purge period is satisfactorily completed.
14. Ensure that the control valves of the fuel gas 91-FV-1020, quench steam and
Combustion Air 91-FV-1018 are closed.
15. Ensure that the igniter is in the correct position and that the fuel gas gun is ready
for operation with fuel gas.
16. Open the fuel gas control valve 91-FV-1020 and Process air control valve 91-FV1018 to the pre-determined position.
17. Press the ‘START IGNITION’ push button 91-HS-1226 from the local control panel.
18. Ensure that ‘READY FOR IGNITION’ lamp 91-XL-1227 is unlit on the local control
panel and 91-XL-1227A is unlit on the ICSS.
19. Ensure “IGNITION ON” 91-XL-1288A lamp lit in ICSS and 91-XL-1228 lamp in Local
panel.
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20. Ensure “Ist STAGE BURNER IN SHUTDOWN” 91-XA-1126 lamp extinguished in Local
panel and 91-XA-1126A lamp extinguished in ICSS.
21. Ensure combustion air control valve SOV 91-FY-1018 energized.
22. Ensure Combustion air flow controller 91-FIC-1018 and fuel gas controller 91-FIC1020 to manual mode and output forced to start position at 10%
23. Ensure that the igniters insert SOV 91-XY-1234 is energised.
24. Ensure that the igniter insertion is proved by limit switch 91-ZSC-1234.
25. Ensure fuel gas bleed valve 91-XV-1132 is closed and fuel gas shutdown valves
91-XV-1028 and 91-XV-1131 are opened.
26. Ensure that the igniter transformer is energised for 10 seconds and sparking
begins.
27. Ensure that the igniter transformer is de-energised and Igniter retracts
automatically (91-ZSO-1234) after 10 seconds ignition timer.
28. If flame is detected then ensure that the ‘FLAME ON’ lamp 91-BAL-1003A, 91-BAL1003B) are lit on the local control panel.
29. Permit is provided to open the steam quench valve.
30. Permit is provided to open the acid gas control valve 91-FV-1019.
31. Ensure that the ‘FUEL GAS ON’ lamp 91-XL-1229 is lit in the Local Control Panel.
32. Ensure combustion air controller 91-FIC-1018 and fuel gas controller 91-FIC-1020
force signal removed.
33. Ensure that the ‘FUEL GAS ON’ lamp 91-XL-1229A is lit in ICSS.
34. Open the instrument air purge valve to sight glasses, flame scanners and nozzles is
opened.
35. Ensure that the Nitrogen purge valve to sight glasses, flame scanners and nozzles
is closed.
36. Take the fuel gas controller 91-FIC-1020 in manual and slowly increase the fuel
gas to the burner.
37. Take the combustion air controller 91-FIC-1018 in manual and increase the air to
the burner.
38. Slowly open the fuel gas and combustion air and increase the 1st Stage Converter
inlet temperature to 230°C.
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Fig. 30 - 1st Stage Auxiliary Burner Management Sequence
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6.3.3.4
2nd Stage Auxiliary Burner 9101-F-03 Start-up
2nd Stage Auxiliary Burner-BMS Sequence
The burner management system of 2nd Stage Auxiliary Burner is incorporated in ESD
system.
2nd Stage Auxiliary Burner LCP 9101-F103–LP-007 hand switches detail is tabulated below:
Sl. #.
Tag No.
Description
1.
91-HS-1195
Start burner
2.
91-HS-1196
Stop burner
3.
91-HS-1197
Lamp test
2nd Stage Auxiliary Burner hardwired aux console hand switches detail is tabulated below:
Sl. #
Tag No.
Description
1.
91-HS-1192
Acid gas ON/OFF
2.
91-HS-1193
Fuel gas ON/OFF
2nd Stage Auxiliary Burner LCP 9101 F103–LP-007 lamp indication detail is tabulated below:
Sl. #
Tag No.
Description
1.
91-XA-1191
2nd stage burner shutdown
2.
91-XL-1192
Ready for ignition
3.
91-XL-1193
Ignition ON
4.
91-XL-1194
Fuel gas ON
5.
91-XL-1195
Acid gas ON
6.
91-BAL-1003A
Flame -1 ON
7.
91-BAL-1003B
Flame-2 ON
System Reset to be done by activating 91-HS-1194 in DCS.
Control valve/ON-OFF valve details are tabulated below:
Sl. #
Tag No.
Description
1.
91-XV-1031
Fuel gas block valve-1
2.
91-XV-1133
Fuel gas block valve-2
3.
91-XV-1134
Fuel gas vent valve
4.
91-FV-1025
Process air control valve
5.
91-FV-1026
Acid gas control valve
6.
91-FV-1027
Fuel gas control valve
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The burner light-on is carried out in below steps:
i.
System reset
ii.
Fuel gas burner light-on
iii.
Acid gas introduction
i.
System Reset
1.
Check the following shutdown interlocks are absent in the ICSS:
•
Reaction Furnace shutdown
•
2nd Stage Auxiliary Burner flame failure (91-BALL-1004A/B).
•
Acid gas flow low-low (91-FT-1137)
•
Fuel gas flow low-low (91-FT-1138)
•
Combustion air flow low-low (91-FT-1136)
If the above conditions do not do not exist “2nd Stage Auxiliary Burner” BMS system can
be reset.
2. When the BMS reset is pressed, following shutdown causes are automatically
bypassed during start-up (start-up override)
a.
91-FT-1136 (Combustion Air low-low flow)
b.
91-FT-1138 (Fuel gas flow low-low)
c.
91-FT-1137 (Acid gas flow low-low)
3. Ensure that any one of Process Air Blower 9101-K-01A & 9101-K-01B is running.
4. If the above conditions are satisfied then Ensure “2nd STAGE BURNER READY FOR
RESET” (91-XL-1197) is lit in ICSS.
5. “RESET” the system by pressing the Soft switch 91-HS-1194 from ICSS and ensure
the following:
a. Energizing of fuel gas control valve SOV 91-FY-1027.
b. Combustion air flow controller 91-FIC-1025 to manual mode and output at start
position.
c. Fuel gas flow controller 91-FIC-1027 to manual mode and output at start
position.
d. “READY FOR IGNITION” lamp 91-XL-1192 and 91-XL-1192A is lit on the local
panel and ICSS respectively.
e. “SYSTEM IN SHUTDOWN” lamp 91-XA-1191 and 91-XA-1191A will extinguish on
the LCP and ICSS, respectively.
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ii. Fuel Gas Burner Light On
1.
Ensure that the air inlets, burner and outlet passages are boxed up and free of
foreign material.
2.
Ensure that all safety shut off valves are closed.
3.
Ensure that the Fuel System vents are open and venting to atmosphere. Lines are
properly drained and cleared of condensate.
4.
Ensure that a complete functional check of the safety interlocks has been made.
5.
Ensure that the area is clear of obvious safety hazards and flammable gases are
not present in the area.
6.
Ensure that all lines have been blown down with plant air to insure they are free
of debris that might plug metering orifices and burner tips.
7.
Ensure that utilities like fuel gas, instrument air, nitrogen and plant air are
available and initial operational checks performed on the elements in each line.
8.
Ensure that the burner elements are in their proper position.
9.
Ensure that power has been supplied to control systems and to safety interlocks.
10. Ensure that the gauges indicating fuel header pressure to the unit are functional.
11. Ensure that the pressure self regulating valves are set according to the instrument
data sheets.
12. Ensure that the isolation valves for all the pressure gauges and pressure
transmitters are open and their respective bleed valves are closed. Valves are
sealed in position as indicated on P&IDs.
13. Ensure that the control valves of the fuel gas 91-FV-1027, quench steam and
Combustion air 91-FV-1025 are closed.
14. Ensure that the igniter is in the correct position and that the fuel gas gun is ready
for operation with fuel gas.
15. Open the fuel gas control valve 91-FV-1027 and combustion air control valve 91FV-1025 to the pre-determined position.
16. Press the ‘START IGNITION’ push button 91-HS-1195 from the local control panel.
17. Ensure that ‘READY FOR IGNITION’ lamp 91-XL-1192, 91-XL-1192A is unlit on the
local control panel and ICSS respectively.
18. Ensure “IGNITION ON” lamp 91-XL-1193A, 91-XL-1193 lamp lit in ICSS and Local
panel respectively.
19. Ensure “2nd STAGE BURNER IN SHUTDOWN” lamp 91-XA-1191 and 91-XA-1191A
extinguished in Local panel and ICSS respectively.
20. Ensure combustion air control valve SOV 91-FY-1025 energized.
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21. Ensure Combustion air flow controller 91-FIC-1025 and fuel gas controller 91-FIC1027 forced to manual mode and output forced to start position at 10%.
22. Ensure that the igniters insert SOV 91-XY-1199 is energised.
23. Ensure that the igniter insertion is proved by limit switch 91-ZSC-1199.
24. Ensure fuel gas bleed valve 91-XV-1134 is closed and fuel gas shutdown valves 91XV-1031 and 91-XV-1133 are opened.
25. Ensure that the igniter transformer is energised for 10 seconds and sparking
begins.
26. Ensure that the igniter transformer is de-energised and Igniter retracts
automatically (91-ZSO-1199) after 10 seconds ignition timer.
27. If flame is detected then ensure that the ‘FLAME ON’ lamps (91-BAL-1004A, 91BAL-1004B) are lit on the LCP and ICSS.
28. Permit is provided to open the steam quench valve.
29. Permit is provided to open the acid gas control valve 91-FV-1026.
30. Ensure that the ‘FUEL GAS ON’ lamp 91-XL-1194 is lit in the Local Control Panel.
31. Ensure that the ‘FUEL GAS ON’ lamp 91-XL-1194A is lit in ICSS.
32. Ensure combustion air controller 91-FIC1025 and fuel gas controller 91-FIC-1027
force signals removed.
33. Open the instrument air purge valve to sight glasses, flame scanners and nozzles.
34. Ensure that the Nitrogen purge valve to sight glasses, flame scanners and nozzles
is closed.
35. Slowly increase the fuel gas to the burner by keeping the Fuel gas flow controller
91-FIC-1027 in manual.
36. Slowly increase the combustion air to the burner by keeping the Combustion air
flow controller 91-FIC-1025 in manual.
37. Slowly open the fuel gas and combustion air and increase the 2nd Stage Converter
inlet temperature to 230°C.
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Fig. 31 - 2nd Stage Auxiliary Burner Management Sequence
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6.3.3.5
Lining up Of Acid Gas to Reaction Furnace
1. When the Reaction Furnace temperature is >1250°C set the Reaction Furnace
burner control system to slightly sub-stoichiometric firing conditions with steam
being injected as noted above to prevent the formation of carbon.
2. Acid gas may now be introduced to the SRU Reaction Furnace burner provided the
following points are first confirmed:
•
The SRU converters catalyst beds are at their normal operating temperatures
of 230 and 210°C, respectively
•
The SRU Reaction Furnace burner is operating on fuel gas in slightly substoichiometric firing conditions with steam injection to fuel gas and process
air lines
•
There is sufficient acid gas available from the upstream Amine Regenerator, at
a stable flow rate of and at/or above the minimum design flow required for
the SRU to operate satisfactorily.
3. Confirm that the acid gas system has been purged with nitrogen.
4. Using a utility water hose connected to the Acid Gas KO Drum utility connection,
introduce water to establish a low level of water in the Acid Gas KO Drum 9101-V-04.
5. Using MS steam from the SRU Reaction Furnace Boiler 9101-E-07, continue
increasing the Acid Gas Pre-heater 9101-E-06 outlet temperature at 50°C/hr to
210°C.
6. Confirm available acid gas flow is at or above the minimum turndown required of
5935 kg/hr, (2349 m3/hr) for the SRU to operate.
6.3.3.6
Reaction Furnace Acid Gas Burner Light-On
1.
Ensure the acid gas control valves 91-PV-1503A/91-PV-1503B from AGEU
Regenerator Reflux Drum 9103-V-12 is closed.
2.
Ensure the 1st Stage and 2nd Stage Auxiliary Burner “FLAME ON” indication is
available.
3.
Ensure Acid Gas KOD 9101-V-04 level 91-LAHH-1003 and acid gas feed pressure
91-PALL-1025 is healthy.
4.
Activate the “ACID GAS ON SWITCH” 91-HS-1217 on hardwired console.
5.
Ensure acid gas cut-off valve 91-XV-1102, 91-XV-1001 and 91-XV-1516 is open.
6.
After 30 seconds “ACID GAS ON” lamp 91-XL-1217, 91-XL-1217A is lit on the local
panel and ICSS respectively.
7.
Gradually open the acid gas valve 91-PV-1503B and close the fuel gas control valve
91-FV-1009 and combustion air controller 91-FIC-1018 to be adjusted accordingly
to provide the process air requirement for the acid gas.
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8.
Ensure the minimum air flow rate while switching between fuel gas and acid gas.
9. As soon as a flow of acid gas is introduced to the Reaction Furnace burner,
commence reducing fuel gas flow to the burner.
10. When fuel gas flow has stopped, isolate fuel gas line by closing fuel gas shutdown
valves.
11. Stop steam injection to the fuel gas and process air lines to the Reaction Furnace
burner.
12. Set all controllers in automatic mode.
13. Remove the override from the acid gas low flow trip.
14. Acid Gas is now to be introduced to the 1st and 2nd Stage Auxiliary Burners
6.3.3.7
1st Stage Auxiliary Burner Acid Gas Burner Light-On
1.
Ensure the acid gas control valve 91-FV-1019 is closed.
2.
Activate the acid gas on switch 91-HS-1223 on hardwired console.
3.
Ensure acid gas control valve SOV 91-FY-1019 energized.
4.
Acid gas controller is forced at the start-up position to ensure acid gas flow is
above low-low flow trip setting
5.
“1ST STAGE ACID GAS ON” lamp 91-XL-1230, 91-XL-1230A is lit on the local panel
and ICSS respectively.
6.
Gradually open the acid gas valve 91-FV-1019 and close the fuel gas control valve
91-FV-1020 and combustion air controller 91-FIC-1018 to be adjusted accordingly
to provide the process air requirement for the acid gas.
7.
Ensure the minimum air flow rate while switching between fuel gas and acid gas.
6.3.3.8
2nd State Auxiliary Burner Acid Gas Burner Light-On
1.
Ensure the acid gas control valve 91-FV-1026 is closed.
2.
Activate the acid gas on switch 91-HS-1192 on hardwired console.
3.
Ensure acid gas control valve SOV 91-FY-1026 energized.
4.
Acid gas controller is forced at the start-up position to ensure acid gas flow is
above low-low flow trip setting.
5.
Ensure “2nd STAGE ACID GAS ON” lamp 91-XL-1195, 91-XL-1195A is lit on the local
panel and ICSS respectively.
6.
Gradually open the acid gas valve 91-FV-1026 and close the fuel gas control valve
91-FV-1027, Combustion air controller 91-FIC-1025 to be adjusted accordingly to
provide the process air requirement for the acid gas.
7.
Ensure the minimum air flow rate while switching between fuel gas and acid gas.
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6.3.3.9
Sulphur Production
1. When the SRU operation has stabilised, commission the tail gas analyser and set in
automatic with the trim air control valve to maintain a H2S:SO2 of 2.0:1.0.
2. Following a period of approximately 30-60 minutes after the introduction of acid
gases to the SRU Reaction Furnace Burner, commence checking of the SRU
condensers, sultraps for liquid sulphur.
3. If the sultraps have not been pre-filled with flake or powdered sulphur then the
following procedure should be adopted to fill the sultraps with liquid sulphur.
Note: It is necessary to use a respirator or fresh air breathing apparatus to ensure
complete operator safety during this operation.
•
Slowly open each of the condensers sulphur outlet drain valves and observe
through the open sultrap inspection door
•
When opening a sultrap if acid gas vapour appears, usually as a white smoky
gas, this will indicate that no liquid sulphur has collected behind the isolation
valve. The sultrap should be closed immediately in this case and only opened
again after about 10 minutes. If only a bluish haze with little pressure behind
it shows from the sultrap, this indicates that the sultrap is filling with liquid
sulphur and the condensers sulphur outlet valve can be left open.
•
Check the sultrap inspection door at regular intervals until sulphur is seen to
flow from each seal
•
When sulphur is seen at the condensers sulphur outlet valve may now be left
open to allow the sulphur to flow freely
•
Repeat this exercise until sulphur is seen to flow from all three seals
Note: It may take a considerable period of time, possibly several hours before
sulphur is seen to flow from the third condenser.
•
Check the Sulphur Degassing Pit 9101-T-01/01B is showing an increase in level
•
When there is sufficient level in Sulphur Degassing Pit 9101-T-01/01B, start
Sulphur Degassing Pumps 9103-P-03A/B/09A/B recirculating the liquid sulphur
back to the pit
•
Start steam ejector and line up the vent gases to Incinerator
•
Ensure that the air flow 91-FI-1056 from safe location shows the normal value.
•
Start AQUISULF catalyst injection to the Degassing pit
•
Start Sulphur Product Pumps 9101-P-04A/B/10A/B and line up liquid sulphur to
the Sulphur Storage Tank 9101-T-02 via the level control valve 91-LV-1014/1051.
•
When sufficient level is there in the Sulphur Storage Tank 9101-T-02 start the
Sulphur Tank Pumps 9101-P-15A/B and transfer liquid sulphur to QAPCO.
The start-up of the SRU is now complete.
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6.3.4
Start-up of Tail Gas Treatment Unit
6.3.4.1
Pre-requisites
I.
Preparation of Caustic Solution
1.
Ensure that the Caustic Storage Tank 9103-T-14 is cleaned internally.
2.
Ensure that the Caustic Injection Pumps 9103-P-103A/B and the Agitator 9103-M-14
are energised in MCC.
3.
Ensure that all the drain and vent valves in the package are closed.
4.
Procure the Caustic Solution drums/tanks to the site and place it near the
unloading pump 9103-P-104.
5.
Connect the drums/tanks to the unloading pump.
6.
Start the unloading pump and transfer the required amount of Caustic Solution to
the tank.
7.
Make up the required concentration of the Caustic Solution by adding DM water to
the tank.
8.
Ensure that the low low level trip 91-LALL-1524 is cancelled while making up the
solution.
9.
Ensure the level in the tank from 91-LG-1512 and 91-LT-1525 and ensure the tank
is filled upto the required level.
10. Start agitator 9103-M-14 from the local panel to mix the solution thoroughly.
II.
Establishing Desuperheater/Contact Condenser 9102-C-11 circulation
1.
Ensure that the suction and discharge isolation valves of the Cooling Water
Circulation Pumps 9102-P-12A/B are closed.
2.
Ensure that the Cooling Water Circulation Pumps 9102-P-12A/B suction to the
Waste Water Degasser 6922-V-07 isolation valves are closed.
3.
Open the DM water make up to the suction of the Cooling Water Circulation Pumps
9102-P-12A/B and increase level in the top section of the Desuperheater/Contact
Condenser 9102-C-11.
4.
When the level in the Desuperheater/Contact Condenser 9102-C-11 top section
reaches 50% which is noted through the 91-LG-1302/91-LT-1305, close the DM
water make up to the pumps suction.
5.
Take the flow control valve 91-FV-1307 in auto with a set point of 197 m3/hr.
6.
Ensure that the flow control valve 91-FV-1305 is closed fully on manual and the
upstream and downstream isolation valves are closed.
7.
Start Cooling Water Circulation Pump 9102-P-12A from ICSS and circulate the
water in the Desuperheater/Contact Condenser 9102-C-11 top chimney tray.
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8.
Select Cooling Water Circulation Pump 9102-P-12B in AUTO from ICSS and open
the suction and discharge isolation valves and prime the pump.
9.
Line up 91-LV-1307 to top up Desuperheater/Contact Condenser 9102-C-11 bottom
section.
10. Open 91-LV-1307 manually and top up Desuperheater/Contact Condenser 9102-C-11
bottom section.
11. Open the DM water make up to the suction of the Cooling Water Circulation Pumps
9102-P-12A/B to maintain the level at 50% at top section.
12. Check the level in the Desuperheater/Contact Condenser 9102-C-11 bottom by
checking 91-LG-1303A/B & 91-LT-1307.
13. When the level in the Desuperheater/Contact Condenser 9102-C-11 bottom
reaches 50%, close the DM water make up to the pump suction and put the level
control valve 91-LV-1307 in auto with a set point of 50%.
14. Take the flow control valve FV-1314 in auto with a set point of 199 m3/hr.
15. Start Desuperheater Circulation Pump 9102-P-11A from ICSS and start circulating
the water.
16. Ensure that the Desuperheater Circulation Pump 9102-P-11B is taken in AUTO from
ICSS and the suction and discharge isolation valves are opened and primed.
17. Line up pH analyzer 91-AT-1302 in the suction of the Desuperheater Circulation
Pumps 9102-P-11A/B.
III.
Lining up of Caustic Solution Injection Pumps 9103-P-103A/B
1.
Ensure that the Caustic Solution Injection pumps 9103-P-103A/B suction strainer
elements are fixed and boxed up.
2.
Ensure that the Caustic Solution Injection Pumps 9103-P-103A/B discharge PSVs
PSV-1606/1607 are lined up.
3.
Open the Caustic Storage Tank outlet isolation valve to the injection pumps and
fill the lines with the Caustic Solution.
4.
Open the suction isolation valves of the injection pumps.
5.
Open the discharge isolation valve of the Caustic Injection Pump 9103-P-103A.
6.
Put the LOR switch of the Caustic Injection Pump 9103-P-103A in ‘Local’.
7.
Start the Caustic Solution Injection Pump 9103-P-103A from LCP.
8.
Put the stroke length of the Caustic Solution Injection Pump 9103-P-103A at 10%.
9.
Ensure that the Caustic Solution Injection Pump 9103-P-103A is developing
pressure by checking the discharge pressure transmitter 91-PT-1563.
10. Open the drain valve near the dosing point and ensure that the line is clear.
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11. Line up Caustic Solution to the Desuperheater Circulation Pump suction till a pH of
9.0 to 10.0 is achieved in the circulating solution.
IV.
Calibration of Caustic Injection Pumps
1.
Stop the Caustic Injection Pumps 9103-P-103A/B from ICSS.
2.
Slowly open the calibration pot inlet isolation valves and fill up the pot up to the
full level.
3.
Close the suction isolation valves of the Pumps upstream of the calibration pot.
4.
Open the Caustic Injection Pump 9103-P-103A discharge isolation valve.
5.
Set the Caustic Injection Pump 9103-P-103A stroke to 10%.
6.
Start the Caustic Injection Pump 9103-P-103A from ICSS.
7.
Note down the time taken to pump out the liquid from the calibration pot.
8.
Calculate the pumping rate from the volume of the calibration pot and time taken
to pump the liquid from the pot.
9.
Repeat the above procedures for stroke length of 20%, 30%, 40%, 50%, 60%, 70%,
80%, 90% and 100%.
10. List all the values and find out the pumping rate at different stroke lengths.
6.3.4.2
Preparation for Start-up
1.
Ensure that the instrument air from instrument air header to the Reducing Gas
Generator 9102-F-11 isolation valve is closed.
2.
Ensure that the spectacle blind is in open position downstream of the isolation
valve of the instrument air from instrument air header to the Reducing Gas
Generator 9102-F-11.
3.
Ensure that the fuel gas from fuel gas distribution to Reducing Gas Generator
9102-F-11 isolation valve is closed.
4.
Ensure that the spectacle blind is in open position downstream of the isolation valve
of the fuel gas from fuel gas distribution to Reducing Gas Generator 9102-F-11.
5.
Ensure that the steam from steam distribution to Reducing Gas Generator 9102-F-11
isolation valve is closed.
6.
Ensure that the spectacle blind is in open position downstream of the isolation
valve of the steam from steam distribution to Reducing Gas Generator 9102-F-11.
7.
Ensure that the combustion air from combustion air blower 9102-K-11A/B to
Reducing Gas Generator 9102-F-11 isolation valve is closed.
8.
Ensure that the spectacle blind is in open position downstream of the isolation
valve of the combustion air from combustion air blower 9102-K-11A/B to Reducing
Gas Generator 9102-F-11.
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9.
Ensure that the Nitrogen from Nitrogen distribution header to Reducing Gas
Generator 9102-F-11 isolation valve is closed.
10. Ensure that the spectacle blind is in open position downstream of the isolation
valve of the Nitrogen from Nitrogen distribution header to Reducing Gas Generator
9102-F-11.
11. Ensure that the drain and vent valves in the Reducing Gas Generator 9102-F-11
section is closed.
12. Ensure that all the instruments in Reducing Gas Generator 9102-F-11,
Hydrogenation Reactor 9102-V-11, Reactor Effluent Cooler 9102-E-11 are lined up.
13. Ensure that the Reactor Effluent Cooler 9102-E-11 atmospheric steam vent
isolation valves are open.
14. Ensure that the Reactor Effluent Cooler 9102-E-11 vents and drains isolation valves
are closed.
15. Ensure that the SRU tail gas valve to the TGTU 91-XV-1098 is closed at SRU.
6.3.4.3
Lining up of Reactor Effluent Cooler 9102-E-11
1.
Open Reactor Effluent Cooler 9102-E-11 tail gas outlet to Desuperheater/Contact
Condenser 9102-C-11 ON-OFF valve 91-XV-1332 from ICSS by selecting open
position in HS-1303A.
2.
Close the Reactor Effluent Cooler 9102-E-11 tail gas outlet to Incinerator 9101-F-14
bypass ON-OFF valve 91-XV-1331 from ICSS by selecting close position in HS-1303A.
3.
Ensure that the steam outlet isolation valve from Reactor Effluent Cooler 9102-E-11
is closed.
4.
Ensure that the Boiler Feed Water from distribution header to the Reactor Effluent
Cooler isolation valves are closed and the level control valve 91-LV-1302 is closed
fully on manual.
5.
Ensure that the Boiler Feed Water is available from utility plant.
6.
Ensure that the process gas from the Desuperheater/Contact Condenser 9102-C-11
to the Tail Gas Amine Absorber 9102-C-12 isolation valve is closed.
7.
Open the process gas recycle isolation valve from the Desuperheater/Contact
Condenser 9102-C-11 top to the Reducing Gas Generator 9102-F-11.
8.
Ensure that the process gas start-up bypass from the Desuperheater/Contact
Condenser 9102-C-11 to the Incinerator 9101-F-14 is lined up and take the
pressure controller 91-PIC-1308 in Auto with a set point of 0.25 barg.
9.
Connect a Nitrogen hose to the vent line of the start-up bypass line from the
Desuperheater/Contact Condenser 9102-C-11 to the Reducing Gas Generator
9102-F-11.
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10. Open the isolation valve of the start-up bypass line near the Reducing Gas
Generator 9102-F-11.
11. Introduce Nitrogen through the hose to the Reducing Gas Generator via the
process gas inlet line.
12. Ensure that the start-up pressure control valve PIC-1308 opening to control the
excess Nitrogen gases to the Incinerator from Desuperheater/Contact Condenser
9102-C-11. Close the nitrogen valve.
13. Open the Start-up Gas Steam Ejector 9102-X-11 process gas inlet and outlet
isolation valves.
14. Open the Boiler Feed Water to Reactor Effluent Cooler 9102-E-11 isolation valves.
15. Open the level control valve 91-LV-1302 in manual and introduce Boiler Feed
Water to the Reactor Effluent Cooler 9102-E-11.
16. Slowly increase the level in the Reactor Effluent Cooler 9102-E-11.
17. When the level in the Reactor Effluent Cooler 9102-E-11 is around 85%, take the
level control valve LV-1302 in Auto with a set point of 80%.
6.3.4.4
Circulating Nitrogen through TGTU
1.
Ensure that RGG, Hydrogenation Reactor, Reactor Effluent
Desuperheater/Contact Condenser is pressurised with nitrogen.
Cooler
and
2.
Open LP Steam drain valve and slowly open the upstream isolation valve to the
Start-Up Gas Steam Ejector 9102-X-11.
3.
Drain the condensate from the LP steam line and slowly warm up the line.
4.
Open the steam ejector outlet isolation valve and then open the steam inlet
isolation valve to the steam ejector 9102-X-11.
5.
Open the process gas inlet line to the steam ejector and start circulating Nitrogen
around the TGTU BSR Section. Nitrogen gases will flow through and around the
RGG,
Hydrogenation
Reactor,
Reactor
Effluent
Cooler
and
DCC
Desuperheater/Contact Condenser 9102-C-11 with excess gases being vented to
the Incinerator through 91-PV-1308.
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Fig. 32 - Burner Management Sequence for RGG
Start
A
Note A
Note B
&
Y
Fuel gas vent valve XV-1308 close, Fuel
gas XV-1303, XV-1304 and air shutdown
valve XV-1306 open, igniter insertion,
activation of 10 sec timer for ignition
transformer
System Reset HS-1400
Automatic bypass of
combustion air (FT-1309), fuel
gas (PT-1305) low low alarm
Confirm FG,
combustion air,
quench steam control
valve closed
System ready for purge-XL-1401
Burner ignition timer
completed
N
Flame
Detected on
2oo3 logic
Purge start
HS-1401
Nitrogen SDV-XV-1307,
XV-1301 open
Y
BAL-1301, BAL-1302, BAL-1303 ON
Fuel Gas ON-XL-1404
Nitrogen
flow alarm
FAL-1308
Y
Quench steam start-HS-1406
N
XV-1305 open, XL-1407 ON
Common Alarm XL-1405
Purge timer –
7.5 minutes
completed
N
Tail gas Start-HS-1052A
from DCS
Light ON timer out XL-1406
Y
Purge Complete XL-1403
Nitrogen SDV-XV-1307
close, 10 min light on
cycle initiated
XV-1098 open
Instrument air purge valve
XV-1032 open and close
nitrogen purge valve
XV-1301
Furnace is fully operational
Burner start
HS-1402
A
Note A
Following causes should be healthy for system reset:
1. RGG DCS soft push button HS-1336
2. RGG ESD push button HS-1337 in LCP
3. ESD total plant shutdown XS-1101
4. ESD level-1 shutdown XS-1102
5. ESD level-2 shutdown XS-1103
6. FG to RGG burner HI HI pressure PAHH-1303
7. Combustion air high high pressure PT-1341
8. Reactor effluent cooler low low level LT-1309
9. RGG process gas Outlet temperature high high TT1305
Note B
Following are the interlocks for purging:
1. No flame detection by BSL-1301/1302/1303
2. Nitrogen flow low should be absent
3. FG control valve at low fire position
4. FG Block valve XV-1303 in close position
5. FG Block valve XV01304 in close position
6. FG vent valve XV-1308 in open position
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6.3.4.5
Lighting up of Burner in Reducing Gas Generator 9102-F-11
Burner Light On
The burner light-on is carried out in three steps.
i.
System reset
ii.
Pre-ignition purge
iii.
Direct fuel gas light-on
i.
System Reset
1.
Check the following shutdown interlocks are absent in the ICSS:
a.
RGG Shutdown soft push button from DCS – 91-HS-1336
b.
RGG ESD push button (Local Panel) – 91-HS-1337
c.
ESD Level 0 Total Plant Shutdown – 65-XS-1101
d.
ESD Level 1 Shutdown – 65-XS-1102
e.
ESD Level 2 Shutdown – 65-XS-1103
f.
Fuel Gas to RGG burner high high pressure – 91-PT-1303
g.
Combustion air high high pressure – 91-PT-1341
h.
Reactor Effluent Cooler low low level – 91-LT-1309
i.
RGC Process gas outlet high high temperature – 91-TT-1305
If the above conditions are not exists, then the RGG BMS system can be reset.
2. The following shutdown causes are automatically bypassed during start-up
a.
91-PT-1305 (Fuel Gas low low pressure)
b.
91-FT-1309 (Combustion Air low low flow)
3. Start Combustion Air Blower 9102-K-11A
To start the Blower 9102-K-11A, the following permissives are to be satisfied:
a.
Instrument air must be available and the seal air low low pressure 91-PALL1460 is reset.
b.
The lube oil tank level 91-LT-1451 is more than 30%.
c.
Lube oil temperature in the tank 91-TT-1473 is greater than 15°C.
d.
The auxiliary lube oil pump 91-P-13A is started and running and the low low
lube oil pressure 91-PI-1459 is reset.
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e.
All trip functions must be healthy.
f.
Three minute restart timer is completed.
g.
The Blower is not running
h.
IGV valve 91-PCV-1453 is closed
i.
Blow off valve 91-FV-1451 is open
j.
Blower ready to start indication is ON
k.
Blower running indication is OFF.
l.
Blower common trip alarm is OFF.
Blower Start-up
a.
Ensure that blower ready to start indication is available in the Local Control
Panel.
b.
Switch ON the electrical heater for the Lube Oil tank 91-E-15AA.
c.
Ensure that the temperature of the Lube oil is increasing by checking 91-TI-1463.
d.
When the temperature reaches 45°C ensure that the heater is cut off
automatically.
e.
Ensure that when the temperature reaches 40°C, the heater is cut in
automatically.
f.
Start the Auxiliary Oil Pump 91-P-13A.
g.
Ensure that the Auxiliary Oil Pump 91-P-13A develops a discharge pressure of
5.50 barg.
h.
Line up the instrument air to the seal system of the blower and ensure that the
low low seal air pressure 91-PALL-1460 is reset by 91-HS-1471.
i.
Select “Local” from the Local Control Panel 9102K11A-LP-003 selector switch
91-HS-1452.
j.
Start the Blower by pushing the start push button 91-HS-1454.
k.
Ensure that the Blower is started and running.
l.
Ensure that the Lube Oil Cooler duty fan is started and running.
m. Ensure that the air filter inlet inertial fan is started and running.
n.
Ensure that the IGV valve opens in unloaded condition.
o.
Ensure that the blow off valve 91-FV-1451 is open.
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p.
After 17 minutes ensure that the Auxiliary Oil Pump 91-P-13A is stopped and the
Blower load function is enabled.
q.
Load the Blower from the Local Control Panel selector switch 91-HS-1455.
r.
Ensure the discharge pressure of the blower is 1.57 bara.
s.
The following conditions are to be satisfied for the pre-ignition purge:
i. No flame present – 91-BSL-1301/1302/1303
ii. Sufficient purge Nitrogen flow rate – 91-FAL-1308
iii. FG Control valve at low fire position – 91-FZSL-1311
iv. Fuel Gas cut-in valve XV-1303 is in close position – 91-ZSC-1303
v. Fuel Gas cut in valve XV-1304 is in close position - 91-ZSC-1304
vi. Fuel Gas vent valve XV-1308 is in open position - 91-ZSO-1308
Ensure the above conditions are satisfied.
t.
Ensure that the combustion air flow control valve 91-FV-1304, Fuel Gas flow
control valve FV-1311 and quench steam flow control valve FV-1310 are closed.
u.
RESET the system by pressing the pushbutton 91-HS-1400 from the local control
panel.
ii. Pre-ignition Purge
1.
Verify whether the ‘System ready for purge’ lamp 91-XL-1401 is lit after RESET at
Local Control Panel.
2.
Ensure that the Nitrogen shutdown valve 91-XV-1307 for furnace purging and
91-XV-1301 for flame scanner, sight glass purging are opened.
3.
Ensure that main combustion air shutdown valve 91-XV-1306 & instrument air
valve 91-XV-1302 (for flame scanner, sight glass purging) are closed.
4.
Open the Nitrogen line isolation valve slowly and set a flow rate of 125 m3/hr read
by 91-FT-1308.
5.
Press ‘Purge Start’ Pushbutton 91-HS-1401 from the Local Control Panel.
6.
Ensure that the ‘Purge On’ lamp 91-XL-1402 is lit in the Local Control Panel.
7.
Set the purge timer at 7.5 minutes.
8.
Verify whether the ‘Purge On’ lamp 91-XL-1402 is lit for 7.5 minutes in the Local
Control Panel.
9.
After the purge time is over, ensure that the ‘Purge On’ lamp 91-XL-1402 is unlit
in the Local Control Panel.
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10. Ensure that ‘Purge Complete’ lamp 91-XL-1403 is lit on the Local Control Panel.
11. Ensure that the Nitrogen cut-in valve 91-XV-1307 is closed.
iii. Fuel Gas Burner Light On
1.
Ensure that the air inlets, burner and outlet passages are boxed up and free of
foreign material.
2.
Ensure that all personnel have been evacuated from the RGG area, ductwork and
associated equipment and all access and inspecting doors closed and sealed.
3.
Ensure that the Combustion Air Blower 9102-K-11A/B is running.
4.
Ensure that all safety shut off valves are closed.
5.
Ensure that the Fuel System vents are open and venting to atmosphere. Lines are
properly drained and cleared of condensate.
6.
Ensure that a complete functional check of the safety interlocks has been made.
7.
Ensure that the area is clear of obvious safety hazards and flammable gases are
not present in the area.
8.
Ensure that all lines have been blown down with plant air to insure they are free
of debris that might plug metering orifices and burner tips.
9.
Ensure that utilities like fuel gas, instrument air, Nitrogen and plant air are
available and initial operational checks performed on the elements in each line.
10. Ensure that the burner elements are in their proper position.
11. Ensure that power has been supplied to control systems and to safety interlocks.
12. Ensure that the gauges indicating fuel header pressure to the unit are functional.
13. Ensure that the pressure self regulating valves are set according to the instrument
data sheets.
14. Ensure that the isolation valves for all the pressure gauges and pressure
transmitters are open and their respective bleed valves are closed. Valves are
sealed in position as indicated on P&IDs.
15. Ensure that the 2” steam drum vent isolation valves of the reactor effluent cooler
are open.
16. Ensure that the Reactor Effluent Cooler is filled with boiler feed water and the
level is being maintained at 80%.
17. Ensure that the minimum purge period is satisfactorily completed.
18. Ensure that the control valves of the fuel gas - 91-FV-1311, quench steam – 91-FV1310 and Combustion Air – 91-FV-1304 are closed.
19. Ensure that the igniter is in the correct position and that the fuel gas gun is ready
for operation with fuel gas.
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20. Ensure that the ‘Purge Complete’ lamp 91-XL-1403 is lit in the local control panel.
21. Open the fuel gas control valve 91-FV-1311 from ICSS to the pre-determined
position signalled by the lamp 91-FZAL-1311 at the local control panel.
22. Open the combustion air control valve 91-FV-1304.
23. Press the ‘Burner Start’ push button 91-HS-1402 from the local control panel.
24. Ensure that ‘Purge Complete’ lamp 91-XL-1403 is unlit.
25. Ensure that the igniter insert SOV is energised.
26. Ensure that the igniter insertion is proved by limit switch 91-ZSC-1400.
27. Ensure that the igniter transformer is energised for 10 seconds and sparking
begins.
28. Ensure that the combustion air shutdown valve 91-XV-1306 is opened.
29. Ensure that the fuel gas bleed valve 91-XV-1308 is closed.
30. Ensure that the fuel gas shutdown valves 91-XV-1303 and 1304 are opened.
31. Ensure that the igniter transformer is de-energised and Igniter retracts
automatically (91-ZSO-1400) after 10 seconds ignition timer.
32. If flame is detected then ensure that the ‘FLAME ON’ lamps (91-BAL-1301, 91-BAL1302, 91-BAL-1303) are lit.
33. Ensure that the fuel gas control valve correct start-up position lamp 91-FZSL-1311
is unlit.
Note: Permit is provided to open the steam quench shutdown valve 91-XV-1305
from ICSS soft switch 91-HS-1406
34. Permit is provided to open the tail gas shutdown valve 91-XV-1098 from ICSS soft
switch 91-HS-1052A.
35. Ensure that the ‘FUEL GAS ON’ lamp 91-XL-1404 is lit in the Local Control Panel.
36. Ensure that the ‘FUEL GAS ON’ lamp 91-XL-1410 is lit in ICSS.
37. Ensure that the instrument air purge valve 91-XV-1302 to sight glasses, flame
scanners and nozzles is opened.
38. Ensure that the Nitrogen purge valve 91-XV-1301 to sight glasses, flame scanners
and nozzles is closed.
6.3.4.6
Hydrogenation Reactor Catalyst Sulphiding
1.
Warm up the Hydrogenation Reactor 9102-V-11 at 50°C/hr by opening the
combustion air and the fuel gas to the RGG.
2.
Open the LP steam shutdown valve 91-XV-1305 to the RGG by manual reset of the
soft push button 91-HS-1406 from ICSS.
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3.
When RGG outlet and Hydrogenation Reactor inlet temperature is 200°C and the
Hydrogenation Reactor is heated through to >120°C, introduce LP steam to the
RGG by opening the steam inlet control valve 91-FV-1310.
4.
Set the steam flow in a ratio of 2:1 by weight to fuel gas in 91-HIC-1311.
5.
Boiler feed water in the Reactor Effluent Cooler 9102-E-11 are heated by the
effluent gases from the Hydrogenation Reactor 9102-V-11 and steam will start
coming out of the drum vent.
6.
Slowly close the drum vent and increase the pressure in the drum to the LP steam
header pressure of 5.0 barg which is read by the drum pressure gauge 91-PT-1309.
7.
When the drum pressure reaches 5.0 barg, open the steam outlet isolation valve
connecting to the header and close the drum vent fully at the same time.
8.
When the Hydrogenation Reactor has heated through to 200°C the sulphiding of
the catalyst should be started.
9.
Check the temperature transmitters in the catalyst bed 91-TT-1303/1306/1308/
1309/1318/1319/1320/1321/1322 from ICSS.
10. All the temperature points should be around 200°C.
11. Line up the isolation valves of the Acid Gas sulphiding line from Regenerator
Reflux Drum 9103-V-12 to the Hydrogenation Reactor 9102-V-11.
12. Open the Acid Gas sulphiding line control valve 91-HV-1301 slowly and introduce
acid gases to the Hydrogenation Reactor 9102-V-11.
13. Introduce acid gases for 1% - 2% volume of H2S initially in the process gases.
Note: The reaction of H2S in the Hydrogenation Reactor catalyst is exothermic.
For every 1% volume of H2S entering the reactor a catalyst temperature increase
of approximately 15°C can be expected.
14. Slowly increase Hydrogenation Reactor inlet temperature at a rate of
approximately 15°C/hr to 315°C whilst keeping the catalyst bed delta
temperature <25°C.
15. If the exothermic reactions produce a catalyst bed delta temperature >25°C then
reduce the flow of H2S acid gas into the Hydrogenation Reactor.
Note: Under no circumstances should catalyst temperature be allowed to exceed
425°C as damage to the catalyst and equipment will occur.
16. As soon as amine acid gas is introduced into the Hydrogenation Reactor inlet line
start sampling the reactors inlet and outlet process gas.
17. A hand held Drager tube type sampling system is suggested where an immediate
read out of H2S in % or ppm can be seen.
18. Continue sampling reactor outlet gas at one hour intervals.
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19. When the Hydrogenation Reactor has been fully sulphided, the reactor outlet gas
H2S concentration will equal the inlet gas H2S concentration.
20. Maintain the reactor catalyst bed temperature at 390°C with the H2S rich amine
acid gas flow to the reactor for a minimum of 4 hours to ensure the catalyst is
fully sulphided.
21. Stop the flow of the H2S rich amine acid gas to the inlet of the Hydrogenation
Reactor by closing the isolation valves near the Hydrogenation Reactor inlet line
and the Regenerator Reflux Drum.
22. Depressurise the line through the drain line given upstream of the check valve.
23. Connect a Nitrogen hose to the acid gas line and purge the line through the drain
line to acid gas flare.
24. Close the control valve 91-HV-1301 in the acid gas line.
25. Reverse the spectacle blinds to close position at both the ends of the acid gas
line.
26. Reduce the reactor inlet temperature to 290°C by slowly reducing the firing.
27. Sulphiding of the reactor catalyst is now complete and the TGTU is now ready to
receive and process SRU tail gases.
6.3.4.7
Lining up of Tail Gases to the TGTU
1.
Confirm that the SRU is operating at near to its minimum design acid gas feed
rate.
2.
When the SRU operation has stabilised commission the tail gas analyzer 91-AT-1001.
3.
Set a H2S:SO2 ratio of 4.0:1.0 in the controller 91-ARC-1001.
4.
Open the Reactor Effluent Cooler 9102-E-11 outlet ON-OFF valve 91-XV-1331 to
the Incinerator 9101-F-14.
5.
Close the Reactor Effluent Cooler 9102-E-11 outlet ON-OFF valve 91-XV-1332 to
the Desuperheater/Contact Condenser 9102-C-11.
6.
Open the manual isolation valve in the Desuperheater/Contact Condenser 9102-C-11
gas outlet to the Tail Gas Amine Absorber 9102-C-12.
7.
Simultaneously open the SRU tail gas ON-OFF valve 91-XV-1098 to the TGTU and
close the ON-OFF valve 91-XV-1097 to the Incinerator 9101-F-14.
8.
Slowly open the downstream isolation valve of the ON-OFF valve 91-XV-1098 and
start the tail gas flow to the Reducing Gas Generator.
9.
Close the LP steam supply isolation valve to the Start-up Gas Steam Ejector
9102-X-11.
10. Close the process gas inlet isolation valve to the Start-up Gas Steam Ejector
9102-X-11 and outlet valve from the Start-up Gas Steam Ejector 9102-X-11.
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11. Close BSR section start-up vent gas pressure control valve 91-PV-1308 and manual
isolation valves.
12. Close Nitrogen supply to the RGG process gas inlet line.
13. Observe Hydrogenation Reactor operation, catalyst temperature will increase as
exothermic reactions take place in the reactors catalyst.
6.3.4.8
Lining up of TGTU Wet Section
1.
Ensure that the DCC 9102-C-11 process outlet gas isolation valve to the Tail Gas
Amine Absorber 9102-C-11 is open.
2.
Ensure that DCC top chimney tray level is made up and the Cooling Water
Circulation Pump 9102-P-12A/B is running circulating water back to the DCC top
section.
3.
Ensure that sea cooling water is lined up to the Contact Condenser Trim Cooler
9102-E-13A/B.
4.
Ensure that the Contact Condenser Cooler 9102-E-12 fans are started and running.
5.
Ensure that the DCC bottom Desuperheater section water level is made up and the
Desuperheater Circulation Pump 9102-P-11A/B is started and circulating water to
the Desuperheater bottom 9102-C-11.
6.
Ensure that the desuperheater circulating water pH is maintained in the range of
9.0-10.0.
7.
Line up lean amine to the Tail Gas Amine Absorber 9102-C-12 by opening all the
isolation valves from the Lean Amine Pumps 9103-P-13A/B discharge.
8.
Reset process shutdown and ensure that lean amine to Tail Gas Amine Absorber
9102-C-12 inlet ON-OFF valve 91-XV-1310 is opened.
9.
Open the lean amine flow control valve 91-FV-1301 slowly and establish a flow of
lean amine to the Tail Gas Amine Absorber 9102-C-12. Put the control valve 91-FV1301 in auto with a set point of 110 m3/hr.
10. Ensure that the low low level alarm 91-LALL-1301 in the Tail Gas Amine Absorber
9102-C-12 is cancelled.
11. Check the level transmitter 91-LT-1308 and ensure that the level is increasing in
the Tail Gas Amine Absorber 9102-C-12.
12. When the level reaches to about 50% in the Tail Gas Amine Absorber 9102-C-12,
line up the Tail Gas Rich Amine Pumps 9102-P-16A/B by opening the suction and
discharge isolation valves.
13. Keep the Tail Gas Rich Amine Pumps 9102-P-16A/B discharge control valves 91-FV1325 & 91-FV-1303 in closed condition.
14. Fill up the Tail Gas Rich Amine Pumps 9102-P-16A/B casing, by opening the casing
vent valve and releasing Nitrogen.
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15. Put the LOR switch of the Tail Gas Rich Amine Pumps 9102-P-16A/B in ‘Remote’.
16. Reset the process shutdown and ensure that the Tail Gas Rich Amine Pumps
9102-P-16A/B discharge ON-OFF valve 91-XV-1309 is opened.
17. Start the Tail Gas Rich Amine Pump 9102-P-16A from ICSS. Put the Tail Gas Rich
Amine Pump 9102-P-16B in AUTO from ICSS.
18. Open the minimum flow control valve 91-FV-1303 in manual and establish a flow
rate of 31.25 m3/hr. Put the controller 91-FIC-1303 in AUTO with a set point of
31.25 m3/hr.
19. Take the level controller 91-LIC-1308 in AUTO with a set point of 50%.
20. Take the flow controller 91-FIC-1325 in REMOTE and ensure the level of the Tail
Gas Amine Absorber is maintained at 50%.
21. Ensure that the level in the Acid Gas Amine Absorber 9103-C-11 is maintained due
to the lining up of the rich amine from Tail Gas Amine Absorber 9102-C-12.
22. Ensure that the SRU is in stable operation and the acid gas feed to the SRU at or
above the minimum design flow rate.
23. Ensure that the TGTU Hydrogenation Reactor is in a stable operation.
24. Open the Reactor Effluent Cooler process gas outlet valve 91-XV-1322 to the DCC
and the close the process gas outlet valve 91-XV-1331 to the Incinerator 9101-F-14
through the hand switch 91-HS-1303A from the ICSS.
25. Check the Tail Gas Amine Absorber 9102-C-12 outlet vent gas line H2 and H2S
analysers 91-AI-1301 in ICSS. The H2 analyser should show a minimum of 1.5%
excess H2 in the vent gases.
26. Closely observe the Incinerator’s operation as the unit stops incineration of the
H2S rich process gases from the Reactor Effluent Cooler and commences
incineration of the very dilute in H2S rich vent gases from the Tail Gas Amine
Absorber.
27. Ensure that the DCC cooling water circulation level control valve 91-LV-1305 is
taken in auto with a set point of 50%.
28. Ensure that the DCC Desuperheater top up water control valve 91-LV-1307 is taken
in auto with a set point of 50%.
29. Ensure that the level in the Contact Condenser is always maintained at 50% by
making up with DM water if needed.
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6.4
RAMP UP OF PLANT LOAD
1.
Check the flow of acid gases from Regenerator Reflux Drum 9103-V-12 to Acid Gas
KO Drum 9101-V-04 of SRU is above the minimum turndown required of
5935 kg/hr, for the SRU to operate.
2.
Gradually increase the flow from Regenerator Reflux Drum 9103-V-12 to Acid Gas
KO Drum 9101-V-04 of SRU.
3.
Ensure the Acid Gas Pre-heater 9101-E-06 outlet temperature is maintained at
200°C.
4.
Adjust the process air flow to the Reaction furnace accordingly.
5.
Ensure that the Process Air pre-heater 9101-E-05 outlet temperature is maintained
at 200°C.
6.
Ensure that steam drum 9101-V-07 level is maintained.
7.
Ensure that 1st Stage Converter 9101-V-01 inlet temperature is maintained at
230°C.
8.
Ensure that 2nd Stage Converter 9101-V-02 inlet temperature is maintained at
210°C.
9.
Ensure that the level in the Sulphur Degassing Pit 9101-T-01 is maintained.
10. Ensure that the tail gases from the SRU to the TGTU have gradually increased due
to the load increase in the SRU.
11. Ensure that the combustion air flow to the Reducing gas Generator has increased
accordingly.
12. Ensure that the Hydrogenation Reactor 9102-V-11 inlet temperature and outlet
temperature are maintained at 290°C and 320°C.
13. Ensure that the BFW level is maintained in the Reactor Effluent Cooler 9102-E-11.
14. Ensure that the Tail Gas Amine Absorber level, pressure and temperature
parameters are maintained.
15. Ensure that the Incinerator is at its normal operating temperature of 817°C.
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SECTION VII
OPERATION & MONITORING
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7.1
PROCESS PLANT OPERATION AND MONITORING
7.1.1
Acid Gas Enrichment Unit
The absorption of H2S by the Methyl Di Ethanol Amine (MDEA) in the Acid Gas Amine
Absorber 9103-C-11 is a function of the following:
•
The flow and distribution of MDEA falling down the Acid Gas Amine Absorber tower
through the upward flow of process gases
•
The temperature of the lean MDEA entering the Acid Gas Amine Absorber 9103-C-11.
•
The concentration and condition of the lean MDEA entering the Acid Gas Amine
Absorber 9103-C-11
Monitoring of the amine unit will include the following:
•
Regularly check the following vessels and towers level gauges and compare with
DCS indicated levels:
Sl. #
1.
•
Vessel
Lean Acid Gas KO Drum
Vessel Tag No.
Level Gauge Tag No.
9103-V-14
9103-LG-1501A
9103-LG-1501B
2.
Acid Gas Amine Absorber
9103-C-11
9103-LG-1505A
9103-LG-1505B
9103-LG-1505C
9103-LG-1505D
3.
Amine Regenerator
9103-C-12
9103-LG-1506A
9103-LG-1506B
4.
Regenerator Reflux Drum
9103-V-12
9103-LG-1502
5.
Regenerator Reboiler
Condensate Pot
9103-V-13
9103-LG-1504A
9103-LG-1504B
6.
Regenerator Reboiler
9103-E-13
9103-LG-1503
Regularly check the function of the following level transmitters and alarms to
confirm correct operation:
Sl. #
1.
2.
Vessel
Lean Acid Gas KO Drum
Acid Gas Amine Absorber
Vessel Tag No.
Level Transmitter Tag
No.
9103-V-14
9103-LT-1501
9103-LT-1502
9103-LT-1503
9103-C-11
9103-LT-1505
9103-LT-1504
9103-LT-1516
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Sl. #
•
Vessel Tag No.
Level Transmitter Tag
No.
3.
Amine Regenerator
9103-C-12
9103-LT-1509
9103-LT-1510
9103-LT-1517
4.
Regenerator Reflux Drum
9103-V-12
9103-LT-1506
9103-LT-1518
5.
Regenerator Reboiler
Condensate Pot
9103-V-13
9103-LT-1508
Confirm that the following pumps are operating satisfactorily. Periodically run
each spare pump and check the operation:
Sl. #
•
Vessel
Pump
Pump Tag No.
1.
Acid Gas KO Drum Return Pump
9103-P-14A/B
2.
Acid Gas Rich Amine Pumps
9103-P-12A/B
3.
Hot Lean Amine Pumps
9103-P-17A/B
4.
Regenerator Reflux Drum Pumps
9103-P-11A/B
5.
Lean Amine Pumps
9103-P-13A/B
6.
Amine Sump Pump
9103-P-15
Confirm that the following air cooler fans are operating satisfactorily. Periodically
run each spare fan and check the operation:
Sl. #
1.
2.
Fan
Fan Tag No
Regenerator Condenser Cooler
9103-E-12AA
9103-E-12AB
9103-E-12AC
9103-E-12BA
9103-E-12BB
9103-E-12BC
9103-E-12CA
9103-E-12CB
9103-E-12CC
9103-E-12DA
9103-E-12DB
9103-E-12DC
Lean Amine Cooler
9103-E-14AA
9103-E-14AB
9103-E-14AC
9103-E-14BA
9103-E-14BB
9103-E-14BC
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Sl. #
Fan
Fan Tag No
9103-E-14CA
9103-E-14CB
9103-E-14CC
9103-E-14DA
9103-E-14DB
9103-E-14DC
9103-E-14EA
9103-E-14EB
9103-E-14EC
9103-E-14FA
9103-E-14FB
9103-E-14FC
9103-E-14GA
9103-E-14GB
9103-E-14GC
9103-E-14HA
9103-E-14HB
9103-E-14HC
9103-E-14IA
9103-E-14IB
9103-E-14IC
9103-E-14JA
9103-E-14JB
9103-E-14JC
•
Maintain lean amine flows to the amine absorbers at the correct flows for efficient
absorption of H2S in the towers.
•
Maintain amine and gas temperatures as given below:
Flow
•
Pressure, bar(a)
Temp. °C
Amine flow to Acid Gas Amine Absorber
9103-C-11
4.69
45
Process gas flow to Acid Gas Amine Absorber
9103-C-11
1.38
49
Regularly test the concentration of the lean amine. Add fresh amine if the
strength is <50%. A low strength or weak solution will result in the inefficient
absorption of H2S in the absorber with the possibility of slippage of off
specification treated gas. This will be detected by the treated gas analyser
91-AI-1501 showing a higher than normal concentration of H2S and other sulphur
species in the absorber effluent vent gases to the Incinerator 9101-F-14 resulting
in an increase of SO2 emissions to atmosphere from the Incinerator Stack 9101-X01. Increasing the amine solution strength should correct this problem. An initial
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correction may be possible by increasing the circulating flow of the amine solution
above its normal design flow rate until the strength of the solution can be
corrected.
•
Regularly check the H2S/H2 analyzer 91-AT-1501 for normal operation.
•
Regularly check that the nitrogen blanketing systems to the Amine Surge Tank
9103-T-11 and to the Amine Sump 9103-V-10 are operating; failure of a blanketing
gas system and the ingress of air will result in the degradation of the amine and
the production of sludge in the system.
•
Maintain the Amine Surge Tank 9103-T-11 at minimum level, 20-30%, so that space
is available in the tank to store amine from the system at times when the unit is
shutdown for inspection.
•
Replace water losses by adding condensate to the Amine Surge Tank 9103-T-11.
•
Maintain a steam (Kg/hr) to the Regenerator Re-boiler 9103-E-13 to rich amine
(m3/hr) to the Amine Regenerator 9103-C-12 ratio of 118.5:1.0 to ensure efficient
stripping of H2S from the amine in the Amine Regenerator 9103-C-12. Insufficient
LP steam flow to the Regenerator Re-boiler 9103-E-13 or fouling of the Re-boiler
tubes will result in incomplete regeneration of the rich amine solution. Increasing
the LP steam flow should correct the problem, however severely fouled Re-boiler
tubes will require a unit shutdown to allow the Re-boiler to be cleaned.
•
Monitor the Acid Gas Amine Absorber 9103-C-11 differential pressure indicator and
Amine Regenerator 9103-C-13 differential pressure indicator as given below. A
gradual increase in pressure differential in a tower over a period of time will
indicate fouling, whilst an increase in pressure differential over a short period will
indicate foaming or flooding of the tower. In this case antifoam should be injected
into an injection point before the problem tower and the amine circulation flow
should be temporarily reduced to reduce the liquid/vapour loadings across the
towers packed sections.
Tower
•
Tag No.
High alarm
Acid Gas Amine Absorber 9103-C-11
9103-PDI-1522
0.15 bar
Amine Regenerator 9103-C-13
9103-PDI-1523
0.2 bar
Monitor the amine filters beds differential pressure indicators as given below.
When a filter pressure differential pressure reaches an advised number (high
alarm), remove the filter from service to replace its filtration medium/cleaning.
Tower
Tag No.
High alarm
Lean Amine Filter 9103-S-11
9103-PDI-1517
0.5 bar
Activated Carbon Filter 9103-S-12
9103-PDI-1518
0.5 bar
Fines Filter 9103-S-13
9103-PDI-1519
0.5 bar
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•
If corrosion is detected in the amine system then inject Corrosion Inhibitor into
one or more of the injection points to protect the system.
•
Normal Operating Parameters - AGEU
Tag. No
Description
Value
Unit
91-TI-1501
Acid gas feed to Acid Gas Amine Absorber
temperature
48
°C
91-FI-1501
Lean amine flow to Acid Gas Amine Absorber
487
m3/hr
91-TI-1511
Lean amine temperature to Acid Gas Amine
Absorber
45
°C
91-TI-1504
Treated gas from Acid Gas Amine Absorber
temperature
46
°C
91-AI-1501
Treated gas H2S analyser
560
ppmv
91-PIC-1502
Treated gas pressure
1.20
bara
91-FIC-1520A
Rich amine flow from Rich Amine Pump
635
m3/hr
91-TIC-1513
Rich amine to Amine Regenerator temperature
104
°C
91-PDI-1522
Differential Pressure across Acid Gas Amine
Absorber trays
0.1
barg
91-LIC-1505
Acid Gas Amine Absorber bottom level
50
%
91-TI-1506
Reboiler outlet Vapour temperature
131
°C
91-FIC-1503
LP steam flow to Reboiler
23789
m3/hr
91-TG-1515
LP steam inlet to Reboiler temperature
159
°C
91-LIC-1508
Regenerator Reboiler Condensate Pot level
50
%
91-PIC-1503
Regenerator Reflux Drum top pressure
1.0
barg
91-FIC-1530
Hot lean amine flow to Lean/Rich Amine
Exchanger flow
669
m3/hr
91-TI-1519/
1520
Hot lean amine from Lean/Rich Amine
Exchanger temperature
84
°C
91-TIC-1509
Lean amine to Amine Surge Tank temperature
45
°C
91-PIC-1526
Amine Surge Tank pressure
0.02
barg
91-FIC-1507
Lean amine flow to Lean Amine Filters
155.6
m3/hr
91-PDI-1517
Differential pressure across Lean Amine Filter
0.5
barg
91-PDI-1518
Differential pressure across Activated Carbon
Filter
0.5
barg
91-PDI-1519
Differential pressure across Fines Filter
0.5
barg
91-PDI-1523
Differential pressure across Regenerator trays
0.16
barg
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7.1.2
Sulphur Recovery Unit
The operation and monitoring of the SRU includes the following activities:
a. Acid Feed Gas System
•
Regularly check Acid Gas KO Drum 9101-V-04 level gauge 91-LG-1001 and compare
with DCS indicated level 91-LI-1001
•
Check for excessive liquid carryover from the upstream AGEU Amine Regenerator
9103-C-12
•
Do not drain sour water to the open sewer from low point drains due to the toxic
nature of the H2S saturated water and gas in the KO drums.
b. H2S:SO2 Ratio Control
The most important control variable in the operation of a SRU is the H2S:SO2 ratio in
the tail gas at the outlet of the SRU Final Separator 9101-V-05. The following points
should be noted:
•
If the Tail Gas Analyser 91-ARC-1001 should be temporarily out of service, sample
the tail gas and analyse for H2S:SO2. Analysis of the tail gas may be carried out
crudely by Drager tube or by chemical lab analysis.
•
Maintain the Tail Gas Analyser 91-ARC-1001 in good working order to ensure the
SRU is operating at its maximum efficiency for conversion of H2S to liquid sulphur
in the SRU converters (9101-V-01 & 9101-V-02) and have the correct ratio of H2S
and SO2 gases for the TGTU.
•
The main air to acid gas ratio controller 91-HIC-1001 point is adjusted as necessary
to change the main process air flow control valve position. The Tail Gas Analyser
91-ARC-1001 will control the trim air to fine tune the air required by the process
to achieve the desired H2S:SO2 ratio in tail gases. When the TGTU is in service with
the SRU then the SRU tail gases H2S:SO2 ratio should be 4.0:1.0. If the SRU is in
service without the TGTU then the tail gases H2S:SO2 ratio should be 2.0:1.0. If the
composition of the acid gas should change then the analyser may drive the trim air
control valve 91-FV-1003 fully open or fully closed; in this case a small adjustment
will have to be made to the main air to acid gas ratio controller to increase or
decrease the total air to allow the Tail Gas Analyser to bring the trim air control
valve 91-FV-1003 back onto control.
•
The control room operator responsible for the amine unit must inform the SRU
control room operator of impending changes in acid gas flow rates and/or upset
operating conditions in these units that will affect the operation of the SRU and
TGTU.
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c. Controllers Operation
To ensure good control of the processes at all times the following should be noted:
•
When the acid gas flow is steady, and the SRU is on automatic, set all controllers
for maximum speed and accuracy of response with control stability. A sudden
reduction in acid gas feed without the accompanied change in air rate could result
in high temperatures in the SRU converters (9101-V-01 & 9101-V-02) catalyst beds;
whilst a sudden increase in acid gas feed without the corresponding increase in air
rate will result in an increase in the amount of acid gas in the SRU tail gas and
increased load on the TGTU Desuperheater/Contact Condenser 9102-C-11 and
possibly the Incinerator 9101-F-14.
•
An increase in H2S concentration and decrease of SO2 in the SRU tail gas to the
TGTU will cause a decrease in temperature rise across the Hydrogenation Reactor
9102-V-11, whilst an increase in SO2 and decrease of H2S concentration in the SRU
tail gas to the TGTU will cause an increase in temperature rise across the
Hydrogenation Reactor 9102-V-11.
•
The SRU Tail Gas Analyser 91-ARC-1001 should be set to a maximum possible speed
and response in order not to cause the SRU tail gas compositions of H2S and SO2 to
vary too widely.
•
Steam Generators BFW level controllers should be set to maintain the water levels
at their recommended levels. A swinging water level may cause water to be
carried over into the steam system which will cause downstream problems with
process units operations.
d. Reaction Furnace Monitoring:
The following points should be noted to ensure good reaction furnace operation:
•
Control of the SRU Reaction Furnace 9101-F-01 temperature is most important to
ensure the correct reactions are occurring with the acid gas in the furnace. The
Reaction Furnace 9101-F-01 temperature should ideally be maintained >1250°C to
maximise thermal sulphur production in the Reaction Furnace 9101-F-01.
•
If Reaction Furnace 9101-F-01 temperatures appear excessive, check air and acid
gas or fuel gas meters, and the Tail Gas Analyser 91-ARC-1001, to be sure the air
to acid gas ratio is correct.
•
Be alert for hot spots on the outside of the shell of the Reaction Furnace 9101-F01 that would indicate refractory trouble.
•
Observe Reaction Furnace 9101-F-01 inlet pressure, an increase above normal will
indicate a possible partial blockage in downstream converters and condensers
and/or in the TGTU Hydrogenation Reactor and wet section towers.
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e. SRU Converters (9101-V-01 & 9101-V-02)
The following points will help ensure efficient converter operation:
•
Keep close surveillance of the temperatures at the inlet of SRU 1st Stage Converter
9101-V-01 and 2nd Stage Converter 9101-V-02. Keep these temperatures at
230/210ºC to avoid liquid sulphur deposition on the catalyst.
•
Sulphur deposition in a SRU 1st Stage Converter 9101-V-01 and 2nd Stage Converter
9101-V-02 catalysts is indicated by a progressive catalyst bed temperature drop
starting at the top and continuing downward. If this is noted, increase the
corresponding converter inlet temperature by adjusting the upstream auxiliary
burner outlet temperature to carry out a rejuvenation of the converters catalyst.
•
Over long periods of operation a decrease in the activity of a SRU 1st Stage
Converter 9101-V-01 and 2nd Stage Converter 9101-V-02 catalysts will be seen. The
reaction of the H2S and SO2 in the process gas combining to form sulphur vapour is
seen by the exothermic reaction in the converters. As the converters catalysts age
this exothermic temperature rise reaction will be seen to move further down the
converters catalyst bed. The temperature rise across the first converter will
decrease whilst the temperature increase across the second converter will
increase.
•
An increased pressure drop across the SRU, seen by an increased pressure on the
Reaction Furnace 9101-F-01 process air inlet line pressure indicator 91-PI-1054
A/B/C, could indicate the deposition of soot/carbon deposits on the converters
catalysts. Soot and carbon deposits are the result of operating the SRU at start-up
or during a hot inert gas sweep with insufficient process air or steam injection to
the fuel gas in the Reaction Furnace 9101-F-01 burner or the result of excess
hydrocarbons in the acid feed gases to the SRU.
•
SRU converters 1st Stage Converter 9101-V-01 and 2nd Stage Converter 9101-V-02
catalyst deterioration can be partially reversed by carrying out a catalyst
rejuvenation exercise. Failure of signs of improved catalyst activity following a
series of rejuvenations will require the catalyst to be sulphur stripped.
Note that soot/carbon deactivation can only be corrected by removal of the
contaminated top layers of catalyst from the reactors and replenishment with new.
f. SRU Steam Generators & Condensers
The following points should be carried out to ensure good operation of the Steam
Generators:
•
Regularly check the levels (as given below) of the SRU Reaction Furnace Boiler
9101-E-07 Steam Drum 9101-V-07, Reaction Furnace Condenser 9101-E-01, 1st
Stage Condenser 9101-E-02 and Last Condenser 9101-E-04. These levels can vary
on load change, especially during start-up, but will normally present no problem
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unless there is evidence of water carryover in the steam systems. In that case,
gradually lower the steam generators level by operating the intermittent blow
down. Blowing down too quickly could result in the start of a cycling level in the
steam generator by an over compensating level controller.
Sl. #
Column/Vessel
Level Gauges
Level Transmitters
1.
Reaction Furnace Boiler
9101-E-07 Steam Drum
9101-V-07
91-LG-1003
91-LG-1008
91-LT-1005
2.
Reaction Furnace Condenser
9101-E-01
91-LG-1004
91-LT-1008
3.
1st Stage Condenser 9101-E-02
91-LG-1005
91-LT-1011
•
Keep a record of the analysis of the treated Boiler Feed Water that enters the
unit. Also maintain a record of the analysis of each Steam Generator Boiler Feed
Water. These samples are drawn from the vessels continuous blow down lines
through the sample coolers.
•
Maintain total dissolved solids, TDS, in the boiler water to below 3000 ppm for the
LP Steam Generators and 1500 ppm for the SRU Reaction Furnace Boiler 9101-E-07.
Control the TDS in each Steam Generator by the setting of the continuous blow
down valve.
•
Carry out an intermittent blow down of each Steam Generator periodically to
remove any accumulated sludge in the bottoms of the vessels. The frequency of
this blow down will depend upon the quality of the Boiler Feed Water; a Boiler
Feed Water containing a high TDS content will require more frequent intermittent
blow downs than a demineralised or condensate based Boiler Feed Water that has
a lower TDS content. Not using these blow downs will result in solids carry over
from the Steam Generators into the steam systems. The long term result will be is
the failure of the Steam Generators tubes due to overheating and or water side
corrosion.
•
Maintain the Reaction Furnace Boiler 9101-E-07 at its operating pressure of
24.0 barg and the Reaction Furnace condenser 9101-E-01 and 1st Stage Condenser
9101-E-02 at 5.0 barg. Operating the LP steam system pressure higher than
advised will result in viscous sulphur leaving the condensers and high temperatures
in the sulphur pit.
•
Normal Operating Parameters - SRU
Tag. No.
Description
Value
Unit
91-FI-1001
Acid gas flow to Reaction Furnace burner
>10912
Sm3/hr
91-TI-1003
Acid gas from Acid Gas Preheater
temperature
200
°C
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Tag. No.
Description
Value
Unit
91-FIC-1002
Main Combustion Air flow to Reaction
Furnace burner
21124.6
Sm3/hr
91-FIC-1002B
Secondary Air flow to Reaction Furnace
burner
5744.1
Sm3/hr
91-FIC-1003
Trim Air flow to Reaction Furnace burner
2057.59
Sm3/hr
91-TI-1004
Air Temperature from Air Preheater
200
°C
91-TI-1055/
1056
Reaction Furnace temperature
>1250
°C
91-TI-1005
Reaction Furnace Boiler oultlet process
gas temperature
303
°C
91-TI-1006
Reaction Furnace Condenser outlet
process gas temperature
185
°C
91-TICA-1007
1st stage auxiliary burner temperature
230
°C
st
91-FIC-1019
acid gas flow to 1 stage auxiliary burner
282
Sm3/hr
91-FIC-1018
Combustion Air flow to 1st Stage Auxiliary
burner
909
Sm3/hr
91-HIC-1018A
air to fuel gas ratio in 1st stage auxiliary
burner
8.35
91-HIC-1018B
air to acid gas ratio in 1st stage auxiliary
burner
3.23
91-TI-1017
1st Stage Converter outlet process gas
temperature
315
°C
91-TI-1018
1st Stage Condenser outlet process gas
temperature
182
°C
91-TICA-1019
2nd Stage Auxiliary burner temperature
210
°C
nd
91-FIC-1026
acid gas flow to 2
stage auxiliary burner
156
Sm3/hr
91-FIC-1025
combustion air flow to 2nd stage auxiliary
burner
520
Sm3/hr
91-HIC-1025A
air to fuel gas ratio in 2nd stage auxiliary
burner
8.35
91-HIC-1025B
air to acid gas ratio in 2nd stage auxiliary
burner
3.23
91-ARC-1001
H2S/SO2 analyzer ratio at Final Separator
outlet, if TGTU is not in line
2:1
91-ARC-1001
H2S/SO2 analyzer ratio at Final Separator
outlet, if TGTU is in line
4:1
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7.1.3
Tail Gas Treatment Unit
The operation and monitoring of the TGTU includes the following activities:
a. Hydrogenation Reactor 9102-V-11 Operation
To maintain good operation of the Hydrogenation Reactor 9102-V-11 the following
points should be noted:
•
Maintain the RGG outlet temperature at 290⁰C
•
Maintain the RGG process air to fuel gas at a sub-stoichiometric ratio of
approximately 14.0:1.0 (by weight)
•
Maintain the RGG steam to fuel gas at a ratio of approximately 2.0:1.0 (by weight)
•
The chemical conversion of SO2 to H2S in the Hydrogenation Reactor 9102-V-11 is
exothermic. Changes in the H2S and SO2 concentrations in the SRU tail gases will
be seen by a temperature change across the Hydrogenation Reactor 9102-V-11. A
change in the H2 content, normally 2.0-4.0%, in the Tail Gas Amine Absorber
9102-C-12 outlet vent gases will also be seen. An increase in ∆T across the reactor
indicates an increase in SO2 and a decrease in H2S in the SRU tail gases, whilst an
increase of H2S and decrease of SO2 in the SRU tail gases will results in a decrease
in ∆T across the reactor. When a change in the H2 content of the Tail Gas Amine
Absorber 9102-C-12 vent gases is seen, check the upstream amine unit operation
and the SRU Reaction Furnace 9101-F-01 controllers operation.
•
Observe the Hydrogenation Reactor 9102-V-11 catalyst ∆T 91-TDI-1307; it should
normally be approximately 32°C.
•
Reactor inlet (91-TIC-1307) and outlet (91-TI-1310) temperatures are to be
maintained around 290°C and 322°C respectively, Provided the unit is operated
correctly the reactor catalyst should last for several years.
•
Over long periods of operation a decrease in the activity of the Hydrogenation
Reactor 9101-V-11 catalyst will be seen. In the Hydrogenation Reactor 9101-V-11
deterioration in catalyst activity is seen by the point of reaction temperature
moving down the catalyst bed and/or the ∆T (91-TDI-1307) increase falling below
the 32°C expected across the reactor and possibly by an increase in the
concentration of hydrogen seen by the Hydrogen Analyser 91-AI-1301 in the Tail
Gas Amine Absorber 9102-C-12 outlet vent gas line.
•
If the Hydrogenation Reactor 9102-V-11 catalyst activity has declined then an
increase in reactor inlet temperature may temporarily restore some activity,
however a catalyst regeneration exercise will be eventually be required followed
by sulphiding the catalyst to fully restore catalyst activity.
•
Periodically, e.g. every 3 months, sample the reactor outlet process gas and
analyse for SO2.
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b. De superheater Contact Condenser 9102-C-11 Operation
The following points should be carried out to ensure good operation of the
De superheater Contact Condenser 9102-C-11 tower:
•
Maintain the Desuperheater Contact Condenser 9102-C-11 tower top temperature
(91-TI-1317) at 42°C.
•
Maintain the top (91-FIC-1307), bottom (91-FIC-1314) circulating water flows at
197 m3/hr and 199 m3/hr, respectively.
•
Control the Desuperheater circulating water pH between 9.0 and 10.0 by
monitoring 91-AI-1302. Regularly check pH analyser probe for cleanliness and flow
of sample to ensure it gives accurate readings. Daily samples to check the water
pH using a portable pH meter or litmus paper should be used to verify the pH
analyser accuracy. Failure of the analyser over a period of time could result in low
pH circulation water and corrosion of equipment. Adjust Desuperheater circulating
water pH by small injections, 1 - 2 litres of liquid caustic injection at a time. Over
injection of caustic will result in free caustic in the circulating water with the
potential for caustic deposition and possible fouling of equipment.
•
Note the times that caustic has to be injected. An increase in the frequency of
caustic additon has to be added to the Desuperheater circulating water suggest
that the Hydrogenation Reactor 9102-V-11 catalyst is not fully converting SO2 to
H2S.
•
Regularly check the Desuperheater circulating water for colour. The water colour
will change from brown to dark brown to black over time as it becomes
contaminated by traces of SO2 which pass out of the Hydrogenation Reactor
9102-V-11 into the Desuperheater Contact Condenser 9102-C-11. Should a sudden
breakthrough of SO2 from the Hydrogenation Reactor 9102-V-11 occur then a rapid
change of the circulating water colour will take place, accompanied by a low pH.
Should a sudden breakthrough of SO2 occur due to an upset in the SRU, and if the
upset condition is likely to take some time to correct, then it is advised that the
Desuperheater Contact Condenser 9102-C-11/Tail Gas Amine Absorber 9102-C-12,
i.e. the TGTU wet section, are temporarily taken off line to minimise any low pH
corrosion of the Desuperheater Contact Condenser 9102-C-11 and possible
degradation to the Tail Gas Amine Absorber 9102-C-12 circulating amine.
•
Periodically change out the Desuperheater circulating water by manually bleeding
off to the spent caustic system. Water from the top cooling section of the
Desuperheater Contact Condenser 9102-C-11 automatically replenish the tower’s
bottom Desuperheater section level.
•
Monitor the Desuperheater Contact Condenser 9102-C-11 tower packed sections
differential pressure indicators 91-PDI-1323/1324. An increase in differential
pressure >0.04 barg could indicate packing fouling or flooding whilst a decrease in
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pressure could indicate low circulation water flow and/or poor distribution across
the packing.
c. Tail Gas Amine Absorber 9102-C-12
The absorption of H2S by the Methyl Di Ethanol Amine (MDEA) in the Tail Gas Amine
Absorber 9102-C-12 is a function of the following:
•
The flow and distribution of MDEA falling down the Tail Gas Amine Absorber
9102-C-12 tower through the upward flow of process gases
•
The temperature of the lean MDEA entering the Tail Gas Amine Absorber
9102-C-12
•
The concentration and condition of the lean MDEA entering the Tail Gas Amine
Absorber 9102-C-12
Monitoring of the amine unit will include the following:
•
Regularly check the following Tail Gas Amine Absorber 9102-C-12 level gauges and
compare with DCS indicated levels:
Vessel
Vessel Tag No.
Tail Gas Amine Absorber
•
9102-C-12
Level Gauge Tag No.
9102-LG-1304A
9102-LG-1304B
9102-LG-1304C
9102-LG-1304D
Regularly check the function of the following level transmitters and alarms as
given below to confirm correct operation:
Vessel
Vessel Tag No.
Tail Gas Amine Absorber
9102-C-12
Level Transmitter Tag No.
9102-LT-1308
9102-LT-1301
9102-LT-1310
•
Maintain lean amine flow (91-FIC-1301) to the amine absorber at the correct flow
for efficient absorption of H2S in the towers.
•
Maintain amine and gas temperatures as given below.
Flow
Pressure,
bar(a)
Temp. °C
Amine flow to Tail Gas Amine Absorber 9102-C-12
4.69
45
Process gas flow to Acid Gas Amine Absorber
9102-C-12
1.19
41
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TITLE: OPERATION AND MAINTENANCE MANUAL
•
Regularly test the concentration of the lean amine. Add fresh amine if the
strength is <50%.
•
Regularly check the healthiness of the H2S/H2 analyser 91-AI-1301 for normal
operation.
•
Monitor the Tail Gas Amine Absorber 9102-C-12 differential pressure indicator
9102-PDI-1327. A gradual increase in pressure differential in a tower over a period
of time will indicate fouling, whilst an increase in pressure differential over a
short period will indicate foaming or flooding of the tower. In this case antifoam
should be injected into an injection point and the amine circulation flow should be
temporarily reduced to reduce the liquid/vapour loadings across the towers
packed sections.
•
Normal Operating Parameters - TGTU
Tag. No.
Description
Value
Unit
Sm3/hr
91-FIC-1311
Fuel gas to RGG flow
263.7
91-HIC-1304
Fuel gas to air flow ratio
0.12
91-HIC-1311
LP steam to fuel gas flow ratio
1.52
91-FIC-1310
LP steam flow to RGG
400
Kg/hr
91-FIC-1304
Combustion air flow to RGG
2371.6
Sm3/hr
91-TIC-1307
Hydrogenation reactor inlet temperature
290
°C
91-TI-1310
Hydrogenation reactor outlet
temperature
327
°C
91-TI-1311
Reactor Effluent Cooler outlet
temperature
177
°C
91-FIC-1314
Circulating water flow to Desuperheater
199
m3/hr
91-AI-1302
Desuperheater circulating water pH
9-10
91-TI-1314
Desuperheater circulating water
temperature
80
°C
91-FIC-1307
Circulating water from Contact
Condenser Trim Cooler
197
m3/hr
91-TI-1312
Circulating water to Cooling Water
Circulation Pump temperature
71
°C
91-TIC-1301
Cooling water temperature at Contact
Condenser Trim Cooler outlet
47
°C
91-TI-1317
Tail gas to Tail Gas Amine Absorber
temperature
42
°C
91-FI-1531
Lean Amine flow to Tail Gas Amine
Absorber
135
m3/hr
91-FIC-1325
Rich Amine flow from Tail Gas Amine
Absorber to Acid Gas Amine Absorber
136
m3/hr
91-TI-1316
Tail gas from Tail Gas Amine Absorber
top temperature
46
°C
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TITLE: OPERATION AND MAINTENANCE MANUAL
Tag. No.
Description
Value
Unit
91-PG-1301
Tail gas from Tail Gas Amine Absorber
top pressure
0.06
barg
91-AE-1301
Tail gas from Tail Gas Amine Absorber
top H2S content
300
ppm
91-TI-1302
Rich amine from absorber temperature
55.2
°C
Alarm and trip values for the Combustion Air Blower 9102-K-11A/B to be
monitored are tabulated below:
•
Sl.
#
Tag No.
Service
Unit
Limit Values
H
L
HH
LL
1
91-VT-1457
Blower-A radial
vibration(X)
microns
23
NA
28
NA
2
91-VT-1458
Blower-A radial
vibration(Y)
microns
23
NA
28
NA
3
91-ZT-1451A/B
Blower-A axial
vibration
microns
61
NA
152
NA
4
91-VT-1451
Motor-A DE, brg.
vibration
microns
4.5
NA
7.1
NA
5
91-VT-1456
Motor-A NDE, brg.
vibration
microns
4.5
NA
7.1
NA
6
91-TE-1471
Motor-A DE brg.
temperature
°C
95
NA
105
NA
7
91-TE-1472
Motor-A NDE brg.
temperature
°C
95
NA
105
NA
8
91-TE-1451
Blower-A brg.
temperature
°C
115
NA
120
NA
9
91-TI-1452A/B
Blower-A bull brg.
temperature
°C
105
NA
115
NA
10
91-TE-1457
Blower-A thrust
brg. temperature
°C
115
NA
120
NA
11
91-TI-1460
Blower-A Oil return
temperature
°C
115
NA
120
NA
12
91-PT-1460
Blower-A Seal air
pressure
bar(g)
NA
NA
NA
0.3
13
91-TT-1453
Blower-A Discharge
air temp
°C
NA
NA
170
NA
14
91-PT-1459
Blower-A Lube oil
pressure
bar(g)
NA
NA
NA
1.49
15
91-TT-1473
Blower-A Reservoir
temperature
°C
NA
NA
90
NA
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TITLE: OPERATION AND MAINTENANCE MANUAL
Sl.
#
Tag No.
16
91-TT-1459
Blower-A lube oil
temperature
17
91-PDT1461
Blower-A inlet air
DP
18
91-VT-1717
19
Service
Unit
Limit Values
H
L
HH
LL
°C
NA
NA
71
NA
mbar
NA
NA
110
NA
Blower-B radial
vibration(X)
microns
23
NA
28
NA
91-VT-1718
Blower-B radial
vibration(Y)
microns
23
NA
28
NA
20
91-ZT-1711A/B
Blower-B axial
vibration
microns
61
NA
152
NA
21
91-VT-1711
Motor-BDE, bearing
vibration
microns
4.5
NA
7.1
NA
22
91-VT-1716
Motor-B NDE, brg
vibration
microns
4.5
NA
7.1
NA
23
91-TE-1731
Motor-B DE brg
temperature
°C
95
NA
105
NA
24
91-TE-1732
Motor-B NDE brg
temperature
°C
95
NA
105
NA
25
91-TE-1711
Blower-B plain brg
temperature
°C
115
NA
120
NA
26
91-TE-1712A/B
Blower-B bull brg
temperature
°C
105
NA
115
NA
27
91-TE-1717
Blower-B thrust brg
temperature
°C
115
NA
120
NA
28
91-TT-1720
Blower-B oil return
temperature
°C
115
NA
120
NA
29
91-PT-1720
Blower-B seal air
pressure
bar(g)
NA
NA
NA
0.35
30
91-TT-1713
Blower-B discharge
air temp
°C
NA
NA
170
NA
31
91-PT-1719
Blower-B Lube oil
pressure
bar(g)
NA
NA
NA
1.49
32
91-TT-1733
Blower-B Reservoir
temperature
°C
NA
NA
90
NA
33
91-TT-1719
Blower-B lube oil
temperature
°C
NA
NA
71
NA
34
91-PDT1721
Blower-B inlet air
DP
mbar
NA
NA
110
NA
35
91-FT-1309
Comb air flow to
RGG
Sm3/hr
NA
NA
NA
1900
36
91-PT-1303
Fuel gas pressure
to RGG
bar(g)
NA
NA
0.7
NA
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TITLE: OPERATION AND MAINTENANCE MANUAL
Sl.
#
Service
Unit
Limit Values
H
L
HH
LL
37
91-PT-1305
Fuel gas pressure
to RGG
bar(g)
NA
NA
NA
0.267
38
91-TT-1305
RGG process O/L
temperature
°C
NA
NA
300
NA
39
91-PT-1341
Comb air pressure
to RGG
bar(g)
NA
NA
0.7
NA
%
NA
NA
NA
76
40
7.1.4
Tag No.
91-LT-1309
Reactor effluent
cooler level
Instrumentation
The following actions should be carried out to ensure that all instrumentation is
operating satisfactorily:
•
The SRU Reaction Furnace 9101-F-01 burner instruments and peep sight nozzles
are purged by instrument air during normal operation and by nitrogen at times of
unit shutdown. In all cases it is important to ensure the purge flows are in
operation to ensure the process tapping points do not block with corrosion
products and/or sulphur deposits. A daily check should be made to ensure that
these purges are taking place, failure or an incorrect purge flow to an instrument
or peep sight nozzle will result in the blockage of the tapping point or nozzle with
sulphur vapours.
•
Set up a preventative maintenance programme to regularly check critical
instrumentation. It is advised that all instrumentation which initiates a unit
shutdown should be checked every three months. Monitoring instruments such as
Tail Gas Analysers, H2/H2S and pH analysers should be checked weekly.
7.1.5
Process On-Stream Analysis and Testing
The good operation of the AGEU, SRU and TGTU can be maintained by close
observation of a number of analysers. The SRU tail gas H2S/SO2 analyser and the TGTU
Tail Gas Amine Absorber vent gas H2/H2S analysers. The information seen on these
analysers will inform the operator of the condition of the SRU and TGTU processes as
follows:
•
The SRU tail gas analyser is the most important analyser within the SRU/TGTU.
Failure of this analyser to control the correct volume of trim air to the SRU
Reaction Furnace burner will result, in the event that there is a change in
composition of the acid feed gas, in an abnormal ratio of H2S and SO2 passing from
the SRU and into the TGTU. The consequences of high H2S concentrations in the
SRU tail gases will result in a reduction in the reactions taking place in the TGTU
Hydrogenation Reactor (reduced delta temperature across reactor) and potential
overloading of the tail gas amine absorber amine solution ability to absorb the
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higher than normal loading of H2S gases from the process gases. This will result in
H2S slippage in the Tail Gas Amine Absorbers vent gases to the Incinerator and
possibly an increase of SO2 to atmosphere via the Incinerator stack. The
consequences of high SO2 concentrations in the SRU tail gas will result in higher
than normal temperatures in the TGTU Hydrogenation Reactor (increased delta
temperature across reactor) and the possible breakthrough of SO2 to the DCC
tower and Tail Gas Amine Absorber. Severe SO2 breakthrough will result in
excessive corrosion of the DCC and Tail Gas Amine Absorber and degradation of
the circulating amine solution
•
The Tail Gas Amine Absorber process vent gas outlet H2/H2S analyser may be used
as a guide to the operation of the SRU Reaction Furnace burner stoichiometry. A
reduction in the H2 and H2S contents of the Tail Gas Amine Absorber vent gases
will indicate that the SRU Reaction Furnace is off ratio producing a higher than
normal concentration of SO2 in its tail gases; i.e. too much process air. This
process change may be confirmed by an increase in the delta temperature across
the Hydrogenation Reactor catalyst bed. If the H2 and H2S contents of the Tail Gas
Amine Absorber outlet vent gas should increase then the SRU is off ratio producing
too much H2S in its tail gas; i.e. too little process air. This process change may be
confirmed by a decrease in the delta temperature across the Hydrogenation
Reactor’s catalyst bed. In both cases an increase of SO2 to atmosphere via the
Incinerator stack will occur
•
The pH analyser employed in the DCC Desuperheater circulating water stream will
indicate a low pH when any SO2 breakthrough occurs from the upstream
Hydrogenation Reactor. To avoid corrosion of the equipment the desuperheating
circulating water pH must always be alkaline, ideally in the 9.0 – 10.0 range. In
the event of a sudden reduction of the contact condenser’s desuperheating
circulating water pH, due to a breakthrough of SO2 from the Hydrogenation
Reactor, the process gas flow from the Reactor Effluent Cooler to the contact
condenser should be temporarily redirected to the Incinerator until the process
upset has been corrected
•
Regular testing of the lean amine solution must be carried out to determine
solution strength and H2S loading. If the solution strength is <40% then add fresh
amine to the system via the amine surge tank fill connection. If the lean amine
arriving at the Acid Gas Amine Absorber and the Tail Gas Amine Absorber is only
semi lean, i.e. part loaded with H2S, then it is not being fully regenerated in the
Amine Regenerator and operating corrections are required at the Regenerator
The following is a suggested program for the analysis of the AGEU, SRU and TGTU gas
and liquid streams. This program may be modified following operating experience of
the units:
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Daily:
DCC Desuperheater section water for pH and colour
Twice Weekly:
•
Steam Generators waters for TDS and treating chemicals
•
Lean amine for strength and H2S loading
Weekly:
•
SRU tail gas for H2S and SO2
•
Acid gas amine absorber vent gas for H2S
•
TGTU Tail Gas Amine Absorber vent gas for H2S
Monthly:
•
DCC top cooling water for pH
•
TGTU Hydrogenation Reactor outlet for SO2
•
Incinerator stack gas for O2 and SO2
Three Monthly:
•
SRU feed acid gas for H2S and hydrocarbons
•
Incinerator stack gas for H2S and NOX
7.1.6
Tail Gas Incinerator
•
For normal operation of the Incinerator the following parameters has to be
monitored
•
The normal operation of Incinerator is controlled by stack temperature controller
91-TIC-1155, set at 817°C.
•
It can be adjusted by adjusting the air fuel gas ratio via 91-HIC-1155A, which in
turn adjusts the fuel and combustion air control valves.
•
Ensure the Air/fuel gas ratio set point provided by the operator in the Incinerator
is 19.85 (Range: 14-24).
•
Monitor the performance of Incinerator Air Blowers 9101-K-12A/B frequently
•
Maintain the fuel gas flow (91-FIC-1155) to the Incinerator at 2256.9 Sm3/hr
•
Maintain the combustion
46938.7 Sm3/hr
•
All the process variables are controlled by monitoring Oxygen and SOX/NOX
contents in the flue gas from stack. The excess Oxygen, SOX and NOX are
continuously monitored by 91-AT-1051, 91-AT-1052 and 91-AT-1053, respectively.
air
flow
(91-FIC-1156)
to
the
Incinerator
at
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TITLE: OPERATION AND MAINTENANCE MANUAL
•
Following are the main parameters in the Incinerator which are to be monitored
for normal operation of Incinerator:
Normal Operating Parameters – Tail Gas Incinerator
Tag No.
Description
Value
Unit
800
°C
91-TI-1155
Incinerator stack temp
91-FI-1155
Incinerator Fuel gas flow
2256.9
Sm3/hr
91-FI-1156
Incinerator combustion air flow
46938.7
Sm3/hr
91-AI-1051
Stack O2
3.7
% Vol. dry
91-AI-1052
Stack SOX
≤ 996
mg/Nm3
91-AI-1053
Stack NOX
≤ 55
mg/Nm3
Alarm values to be monitored
Tag No.
Description
Unit
Alarm Values
LL
L
H
HH
91-PT-1156
Fuel Gas Pressure
bar(g)
0
NA
NA
4
91-PT-1158
Fuel Gas Pressure
bar(g)
NA
NA
2.5
NA
91-PT-1155
Fuel Gas Supply Pressure
bar(g)
2.75
NA
NA
NA
91-PT-1157
Fuel Gas Supply Pressure
bar(g)
NA
5
NA
NA
91-PT-1159
Pilot Fuel Gas Supply
Pressure
bar(g)
NA
0.5
NA
NA
91-TT-1161
Incinerator Shell
Temperature
°C
NA
350
600
NA
91-TT-1162
Incinerator Shell
Temperature
°C
NA
350
600
NA
91-TT-1156
Incinerator Temperature
°C
817
NA
NA
NA
91-TT-1160
Incinerator Temperature
°C
NA
NA
NA
900
91-TT-1163
Stack Inlet Flue Gas
Temperature
°C
NA
350
600
NA
91-TT-1164
Stack Inlet Flue Gas
Temperature
°C
NA
350
600
NA
91-TT-1159
Stack Bottom
Temperature
°C
NA
NA
850
NA
91-TT-1158
Stack Middle
Temperature
°C
NA
NA
850
NA
91-TT-1157
Stack Top Temperature
°C
NA
NA
850
NA
91-AT-1051
Stack Flue Gas Oxygen
Content
Mol%
NA
2.75
3.5
NA
91-AT-1052
Stack Flue Gas SOX
Content
Mg/Nm3
NA
NA
850
NA
91-AT-1053
Stack Flue Gas NOX
Content
Mg/Nm3
NA
NA
250
NA
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TITLE: OPERATION AND MAINTENANCE MANUAL
7.2
UTILITIES
7.2.1
Instrument Air & Plant Air
The following are the important parameters to be monitored for steady operation of
Instrument Air System:
1.
Maintain the instrument Air pressure (68-PIC-1310) at Instrument Air header
around 7.8 barg and (68-PI-1311) at instrument air receiver around 7.85 barg.
2.
Monitoring of Lube Oil circuit
3.
•
Maintain Lube Oil Tank level at normal operating condition (more then 50%) by
monitoring 68-LG-1401
•
Check lube oil temperature (68-TI-1402) and ensure the temperature is not
greater than 65°C
•
Check discharge pressure (68-PI-1402) of lube oil pump and ensure the
pressure is not less than 1.5 barg
•
Ensure that the differential pressure (68-PDI-1403) across Lube Oil Filter is not
more than 0.5 barg
Monitoring of Compressor
•
Monitor and ensure the compressor outlet pressure (68-PT-1406) is maintained
around 8.0 barg
•
Monitor and ensure the compressor outlet temperature (68-TI-1405) is
maintained around 55°C
•
Monitor compressor air intake pressure (68-PDI-1401) and ensure the pressure
is under limit
•
Monitor Compressor 1st Stage and 2nd stage outlet temperatures (68-TI-1401
and 68-TI-1404) and ensure it is maintained below 250°C
•
Monitor Main Motor winding temperatures and ensure the temperatures are
below 125°C
•
Monitor Main motor bearing temperatures (68-TI-1410 & 68-TI-1411) are below
100°C
•
Monitor inter cooler & after cooler air fans are running normal
•
Ensure loading and unloading of compressor is functioning normal
•
Ensure changeover of compressor after every 24 hrs
•
Ensure proper working of water level indicators in inter and after cooler
separators and ensure the proper working of automatic drain valves
•
Monitor Compressor motor amperes at regular intervals in LCP
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TITLE: OPERATION AND MAINTENANCE MANUAL
•
Normal operating parameters:
Tag No.
68-LI-1401
68-PI-1402
68-TI-1402
68-PDI-1403
68-TI-1401
68-TI-1403
68-TI-1404
68-TI-1405
68-PI-1406
68-PIC-1310
68-PI-1311
Description
Lube oil sump level
Compressor Lube oil pressure
Lube oil temperature
DP across lube oil filter
LP stage outlet transmitter
HP stage inlet temperature transmitter
HP stage outlet temperature
transmitter
Compressor outlet temperature
transmitter
Compressor outlet pressure transmitter
Instrument air at header pressure
Plant air flow to plant air distribution
System
Required
Value
Unit
60
%
1.5
barg
65
°C
1.5
barg
250
°C
65
°C
250
°C
55°C
°C
8
7.8
barg
barg
7.85
barg
Alarm and trip values of main parameters in Instrument air compressor are tabulated
below:
Tag No.
Description
Unit
68-PDI-1401
Compressor air inlet pressure
68-PI-1406
Alarm
LL
L
H
HH
bar(g)
-0.065
-0.070
NA
NA
Compressor outlet pressure
bar(g)
NA
NA
14
16
68-PI-1402
Compressor Oil pressure
bar(g)
1
1.2
NA
NA
68-PDI-1403
Compressor Oil filter DP
bar(g)
NA
NA
0.9
1.0
68-TI-1401
LP stage outlet temperature
°C
NA
NA
255
260
68-TI-1402
Compressor oil temperature
°C
NA
NA
70
75
68-TI-1403
HP stage inlet temperature
°C
NA
NA
70
80
68-TI-1404
HP stage outlet temperature
°C
NA
NA
255
260
68-TI-1405
Compressor outlet temp.
°C
NA
NA
70
80
68-TI-1406
Main motor winding temp.
°C
NA
NA
NA
155
68-TI-1407
Main motor winding temp.
°C
NA
NA
NA
155
68-TI-1408
Main motor winding temp.
°C
NA
NA
NA
155
68-TI-1410
Main motor DE bearing temp.
°C
NA
NA
NA
115
68-TI-1411
Main motor NDE bearing
temp.
°C
NA
NA
NA
115
68-TI-1412
Main motor winding temp.
°C
NA
NA
NA
155
68-TI-1413
Main motor winding temp.
°C
NA
NA
NA
155
68-TI-1414
Main motor winding temp.
°C
NA
NA
NA
155
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TITLE: OPERATION AND MAINTENANCE MANUAL
4. Monitoring of Dryer
•
Monitor Dryer Inlet filter differential pressure 68-PDI-1407and ensure that it is
<0.3 bar
•
Monitor Dryer outlet filter differential pressure 68-PDI-1410and ensure that it
is <0.3 bar
•
Monitor Dryer outlet Dew point analyzer 68-AI-1401 reading and ensure that it
is< (-) 40°C
•
Monitor Dryer outlet pressure in 68-PG-1412
•
Monitor drying and regeneration sequence are working properly
Details of alarm values of main parameters in the dryer system are tabulated below:
Unit
Low
Alarm
High
Alarm
Inlet filter Diff. pressure
bar
NA
0.36
68-PDI-1410
Outlet filter Diff. pressure
bar
NA
0.36
3.
68-PI-1408
Vessel A pressure
bar
3.5
0.7
4.
68-PI-1409
Vessel B pressure
bar
3.5
0.7
5.
68-AI-1401
Dew point
°C
NA
-40
6.
68-TI-1409
Inlet temperature
°C
1°C
60
Sl. #
Tag No.
1.
68-PDI-1407
2.
Description
Note: 68-PI-1408/68-PI-1409 low alarm is active only during the drying cycle and 68-PI1408/68-PI-1409 high alarm is active only during regeneration cycle.
7.2.2
Effluent & Waste Water Treatment
The following are the important parameters to be monitored for steady operation of
Effluent & Waste Water Treatment System:
•
Regularly check the level being maintained in the Waste Water Degasser 6922-V-07
by comparing the indicated level 69-LT-1301 with the level gauge 69-LG-1302
•
Routinely check the smooth running of the Waste Water Degasser Pumps
6922-P-08A/B.
•
Check the differential pressure 69-PDI-1320 across the Sour Water Filter
6922-S-06. If it reaches 1.0 barg, then the filter elements are to be cleaned.
•
Regularly check the Sour Water Stripper 6922-C-01 pressure is maintained at
1.0 barg through 69-PT-1315
•
Regularly check the Sour Water Stripper 6922-C-01 top trays differential pressure
69-PDI-1321
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TITLE: OPERATION AND MAINTENANCE MANUAL
•
Regularly check the Sour Water Stripper 6922-C-01 bottom trays differential
pressure 69-PDI-1322
•
Check the Sour Water Stripper 6922-C-01 top temperature is maintained at 82ºC
through 69-TI-1322
•
Check the bottom temperature of the Sour Water Stripper 6922-C-01 is maintained
at 126ºC through 69-TI-1313
•
The Sour Water Stripper 6922-C-01 bottom level has to be maintained around 50%.
Check the level through 69-LI-1306 and compare with the level gauge 69-LG-1306.
•
Regularly check the smooth running of the Stripped Water Pumps 6922-P-10A/B.
•
Routinely check the smooth running of the Stripper Overheads Circulation Pumps
6922-P-11A/B.
•
Check the temperature of the LP steam is being maintained at 148ºC through
69-TI-1327
•
Regularly check the temperature of the Sour Water Stripper Reboiler outlet vapour
temperature is being maintained at 126ºC through 69-TI-1314
•
Check the level of the Reboiler Condensate Drum is maintained at around 50%
through 69-LI-1327
•
Normal operating parameters:
Tag No.
Description
69-LIC-1301
69-PIC-1307
69-FIC-1314
69-PDI-1320
69-PIC-1315
69-PDI-1321
69-PDI-1322
69-TI-1322
69-TI-1313
69-LIC-1306
69-TIC-1327
Waste Water Degasser 6922-V-07 level
Waste Water Degasser 6922-V-07 pressure
Sour water to sour water stripper flow
DP across Sour Water Filter 6922-S-06
Sour Water Stripper 6922-C-01
Sour Water Stripper 6922-C-01 tray top DP
Sour Water Stripper 6922-C-01 tray bottom DP
Sour Water Stripper 6922-C-01 top temperature
Sour Water Stripper 6922-C-01 bottom temperature
Sour Water Stripper 6922-C-01 bottom level
Temperature of the LP steam
Sour Water Stripper Re-boiler outlet vapour
temperature
Re-boiler Condensate Drum level
Sour Water Stripper top level
CW to Stripper Overhead Cooler
LP steam flow to the Stripper Re-boiler
Stripper overheads cooler to sour water
Stripped Water Cooler outlet flow
69-TI-1314
69-LI-1327
69-LIC-1325
69-FIC-1316
69-FIC-1315
69-TIC-1315
69-FIC-1317
Required
Unit
Value
%
60
barg
1
m3/hr
8.72
barg
1
barg
1
barg
<0.15
barg
<0.15
°C
82
°C
126
%
50
°C
148
126
°C
50
50
13.6
2154
55
8
°C
%
m3/hr
Kg/hr
°C
m3/hr
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TITLE: OPERATION AND MAINTENANCE MANUAL
7.2.3
Fuel gas system
Surveillance of the Fuel Gas System includes the following:
•
Regularly check the Fuel Gas KOD 6236-V-05 level gauge 62-LG-1301 and compare
with DCS indicated level 62-LI-1301.
•
Fuel Gas KOD 6236-V-05 level in 62-LG-1301 and 62-LI-1301is to be maintained
below 50%
•
Routine checks to be made in the Fuel gas system to identify any leaks with the
portable gas detectors and to be recorded
•
Fuel Gas KOD 6236-V-05 is to be checked for condensate collection and to be
drained free of condensate
•
Routine sampling of the Fuel gas to be done and the quality has to be cross
checked with the Laboratory
•
Consumption of fuel gas has to be monitored and mass balance study has to be
carried out to find any abnormal loss
•
Differential pressure 62-PDI-1305 is maintained below 0.02 barg
•
Check the Fuel Gas KOD 6236-V-05 pressure controllers 62-PIC-1301, 62-PIC-1302
and 62-PIC-1303 are in AUTO mode and is steady with a set value of 7 barg.
•
Normal operating parameters:
Tag No.
Description
Required
Value
Unit
62-PIC-1301
Fuel Gas KOD 6236-V-05 pressure
7
barg
62-PIC-1302
Fuel Gas KOD 6236-V-05 pressure
7
barg
62-PIC-1303
Fuel Gas KOD 6236-V-05 pressure
7
barg
62-PDI-1305
Fuel Gas KOD 6236-V-05 DP
0.02
barg
62-LI-1301
Fuel Gas KOD 6236-V-05 level
55
%
7.2.4
Sea Cooling Water System
For normal operation of sea cooling water system following monitoring is required:
•
Sea cooling water common discharge 69-FI-1301 flow is to be maintained around
1500 m3/hr
•
Monitor the flow trend of the 69-FI-1301. In case of any increase or decrease in
consumption, analyse the cause and take the corrective measures
•
Ensure the sea cooling water pumps (6932-P04A/B)
(69-PI-1301/69-PI-1303) is maintained around 5 barg
discharge
pressure
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•
Periodic checking of the discharge headers has to be carried out for any leak
•
Ensure the vibrations 69-VI-1301/69-VI-1302 of sea cooling water pumps
(6932-P04A/B) are below 12 mm/s
•
Ensure the thrust bearing temperatures 69-TI-1331A/69-TI-1338A of Sea Cooling
Water Pump (6932-P04A/B) bearings are below 85ºC
•
Ensure the motor winding temperatures of Sea Cooling Water Pump (6932-P04A/B)
are below 135ºC
•
Ensure the pump DE/NDE bearing temperatures of Sea Cooling Water Pump
(6932-P04A/B) are below 110ºC
•
Sea Cooling Water system normal operating parameters with values is tabulated
below:
Tag No.
7.2.5
Description
Required
Value
Unit
69-FI-1301
Sea Cooling Water Pumps common discharge
1500
m3/hr
69-PI-1301
Sea Cooling Water Pump-A discharge pressure
5
barg
69-PI-1303
Sea Cooling Water Pump-B discharge pressure
5
barg
69-VI-1301
Sea Cooling Water Pump-A vibration
<12
mm/s
69-VI-1302
Sea Cooling Water Pump-B vibration
<12
mm/s
69-TI-1331A
Sea Cooling Water Pump-A thrust bearing
temperature
<85
°C
69-TI-1338A
Sea Cooling Water Pump-B thrust bearing
temperature
<85
°C
Electro Chlorination Package
The following parameters are monitored during normal operation:
•
Maintain the sea water pressure to the electrolyser around 4barg by monitoring
the pressure gauge 69-PG-1451.
•
Ensure the sea water flow to electrolyser is maintained around 10 m3/hr by
monitoring the flow transmitters 69-FI-1451 (6932-G01A) and 69-FI-1452
(6932-G01B)
•
Ensure the differential pressure across the auto back wash filters is maintained
below 0.3 barg by monitoring the differential pressure transmitter indications
69-PDI-1452 (6932-S-03A) and 69-PDI-1453 (6932-S-03B)
•
Ensure the filter Outlet pressure 69-PI-1463 is maintained around 3.5 barg
•
Maintain the Electrolyser outlet temperatures are below 42°C by monitoring the
temperature indications 69-TI-1452 (6932-G01A) and 69-TI-1453 (6932-G01B)
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•
Ensure the dilution blower (6932-K-01A/K-01B) pressure is maintained around
150 mmwc by monitoring 69-PI-1464
•
Ensure the dosing pump (6932-P-05A/P05B) discharge flow (69-FI-1453) is
maintained around 11m3/hr.
General checks:
1.
Check/monitor the electrolyser duty/standby switching over.
2.
Check/monitor the auto back wash filter changeover.
3.
Check the duty blower for noise, vibration and excessive temperatures.
4.
Check the general integrity of the package for any leakages and loose connections.
5.
Check the security of all supports, brackets and clips
Details of alarm values of main parameters in the ECP are tabulated below:
Sl.
#
Tag No.
Service
Unit
Limit Values
High
Low
1.
69-PDI-1452
Diff pressure across 6932-S-03A
barg
0.3
NA
2.
69-PDI-1453
Diff pressure across 6932-S-03B
barg
0.3
NA
3.
69-PI-1463
Filter O/L pressure
barg
4.0
3.0
4.
69-TI-1451
Electrolyser inlet temperature
°C
40.0
NA
5.
69-FI-1451
Inlet flow to electrolyser
6932-G01A
m3/hr
13.0
9.0
6.
69-FI-1452
Inlet flow to electrolyser
6932-G01B
m3/hr
13.0
9.0
7.
69-TI-1452
Electrolyser outlet
temperature
°C
42.0
NA
8.
69-TI-1453
Electrolyser outlet
temperature
°C
42.0
NA
9.
69-PDI-1465
Degassing tank vent air flow
mmwc
170.0
140.0
10.
69-PI-1464
Dilution blower pressure
mmwc
170.0
140.0
11.
69-LI-1452
Degassing tank level
mm
2900
924
m /hr
13.0
1.8
mm
1621
520
µS/cm
75000
NA
12.
69-FI-1453
Dosing pump discharge
13.
69-LI-1454
Acid tank level
14.
69-AI-1451
Conductivity of acid wash
solution
3
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TITLE: OPERATION AND MAINTENANCE MANUAL
7.2.6
DM Water Package
Surveillance of the DM Water System includes the following:
•
Confirm that the new Drinking Water Feed Pumps 6834-P-23A/B are operating
satisfactory with sufficient level in Potable Water Storage Tank 6834-T-01 A/B and
providing potable water to De-mineralized Water Package 6834-A-07.
•
Confirm that the following pumps are operating satisfactory. Periodically run each
spare pump to prove its operation.
Sl. #
Pump
Pump Tag No.
1.
DM Water Transfer Pumps
6834-P-23A/B
2.
Neutralization Pumps
6834-P-38A/B
3.
HCI Dosing Pumps
6834-P-35A/B/C
4.
NaOH Dosing Pumps
6834-P-34A/B/C
5.
Recycling pumps
6834-P-37A/B
6.
Regeneration pumps
6834-P-36A/B
•
Check for the inventories of the chemicals like sulphuric acid & NaOH regularly
and arrange for the specified quantity of chemicals storage drums to avoid
shortage of chemicals at any time.
•
Monitor the differential pressure across the Cationic Exchangers Bed 6834-S-21A/B
by reading the 68-PDI-1826/68-PDI-1829 and ensure that it is less than XX barg.
•
Monitor the differential pressure across the Anionic Exchangers Bed 6834-S-22A/B
by reading the 68-PDI-1827/68-PDI-1831 and ensure that it is less than XX barg.
•
Routine sampling of HCI Storage Tank 6834-T-16 to be carried out to check the
concentration (33%) using the sampler 68-SC-1840.
•
Close co-ordination between the units is to be maintained for monitoring the
levels in the HCI Storage Tank during transfer of acid. Initial and final tank levels
have to be recorded for tank and loss of acid if any during transfer. Investigation
has to be done in case of abnormal values and the root cause has to be identified
and attended.
•
Check and monitor the HCI Storage Tank 6834-T-16 level in 68-LG-1825 and
68-LI-1825.
•
Close co-ordination between the units is to be maintained for monitoring the
levels in the NaOH Storage Tank 6834-T-15 during transfer of NaOH. Initial and
final tank levels have to be recorded for tank and loss of NaOH if any during
transfer. Investigation has to be done in case of abnormal values and the root
cause has to be identified and attended.
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TITLE: OPERATION AND MAINTENANCE MANUAL
•
Routine sampling of NaOH Storage Tank 6834-T-15 to be carried out to check the
concentration (25%) using the sampler 68-SC-1841.
•
Check and monitor the NaOH Storage Tank 6834-T-15 level in 68-LG-1826 and
68-LI-1826.
•
Check and monitor the following normal operating parameters:
•
•
•
a.
DM Water Storage Tank 6834-T-08 level 68-LIC-1305 (5200 mm)
b.
DM water flow 68-FIC-1828(7 m3/hr) to DM Water Storage Tank 6834-T-08
c.
SiO2 content in the DM water from anionic exchanger 6834-S-22A/B to DM
Water Storage Tank 6834-T-08 is monitored by 68-AI-1830 and ensure that it is
< xxx ppm wt
d.
Conductivity in the DM water from anionic exchanger 6834-S-22A/B to DM
Water Storage Tank 6834-T-08 is monitored by 68-AI-1829 and ensure that it is
< xxx µs
e.
Regeneration waste water from DM Water Package 6834-A-07 has to be
neutralised in Neutralisation Pit 6834-A-01-T17 prior to disposal.
f.
Neutralisation water to open drain pH is monitored by 68-AI-1831 is
maintained around XXX.
On daily basis check the following:
a.
Visual inspection of the entire package to detect any possible defects (leaking
flanges, loose fixtures etc.)
b.
Check that no resin is flowing over into the drain header trench as a result of
incorrect action when a train is started up.
c.
Make sure that good demineralization is accomplished. If the produced water
quality is not satisfactory check the reagent (HCI/NaOH) dosage.
On weekly basis check the following:
a.
If there are any leaks, tighten the flanges concerned, if that does not stop the
leak; make arrangements to stop the installation for repair
b.
Whenever working on the chemical system H2SO4 & NaOH make sure that
appropriate protective equipment is used
On monthly basis check the following:
a.
Detailed inspection of the entire DM Water Treatment Plant should be made
to detect any malfunctions and to lubricate HCI/NaOH Dosing pumps, motors
and all other lubrication points
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TITLE: OPERATION AND MAINTENANCE MANUAL
b.
Check the level of resin bed in the Cationic/Anionic Beds, if necessary, make
up the difference. Do remember that resin swells, and that after regeneration
both cation and anionic resins are at their maximum expansion
Alarm and trip values main parameters in DM Water Package are tabulated below:
Tag No.
Service
Unit
Limit Values
L
H
LL
HH
68-LI-1825
Acid storage tank level
%
NA
NA
XX
NA
68-LI-1826
Acid storage tank level
%
XX
XX
NA
NA
68-LI-1827
Caustic storage tank level
%
NA
NA
XX
NA
68-LI-1828
Caustic storage tank level
%
XX
XX
NA
NA
68-LI-1830
Neutralisation Pit level
%
NA
NA
XX
NA
68-LI-1831
Neutralising Pit level
%
XX
XX
NA
NA
68-LI-1305
DMW storage Tank level
%
XX
XX
NA
NA
68-AI-1829
Outlet DMW conductivity
µs
NA
NA
NA
XX
68-AI-1830
Outlet DM Water silica
Sio2
NA
NA
NA
XX
68-AI-1826
Train-A Anionic Exchangers
outlet conductivity
µs
NA
XX
NA
NA
68-AI-1828
Train-B Anionic Exchangers
outlet conductivity
µs
NA
XX
NA
NA
68-FI-1826
Train-A Recycle pump flow
m3/hr
68-FI-1837
68-FI-1829
68-FI-1838
Train-A Recycle pump flow
Train B Recycle pump Flow
Train-B Recycle pump flow
XX
XX
NA
NA
3
NA
NA
XX
NA
3
XX
XX
NA
NA
3
NA
NA
XX
NA
3
m /hr
m /hr
m /hr
68-FI-1830
DM water package outlet
flow
m /hr
NA
NA
XX
NA
68-FI-1828
DM water package outlet
flow
m3/hr
XX
XX
NA
NA
68-FI-1825
Train-A Cationic exchanger
inlet flow
m3/hr
XX
XX
NA
NA
68-FI-1827
Train-B Cationic exchangers
inlet flow
m3/hr
XX
XX
NA
NA
68-PDI-1825 Train-A Cationic exchangers
bed differential pressure
barg
NA
XX
NA
NA
68-PDI-1826 Train-A Resin trap
differential pressure
barg
NA
XX
NA
NA
68-PDI-1828 Train-A Anionic exchangers
Bed differential pressure
barg
NA
XX
NA
NA
68-PDI-1827 Train-A Anionic exchanger
Resin trap differential
pressure
barg
NA
XX
NA
NA
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TITLE: OPERATION AND MAINTENANCE MANUAL
Tag No.
Service
Unit
Limit Values
L
H
LL
HH
68-PDI-1830 Train-B Cationic exchangers
differential pressure
barg
NA
XX
NA
NA
68-PDI-1829 Train-B Resin Trap
differential pressure
barg
NA
XX
NA
NA
68-PDI-1832 Train-B Anionic exchangers
differential pressure
barg
NA
XX
NA
NA
68-PI-1825
6834-P-35A diaphragm
failure
barg
NA
XX
NA
NA
68-PI-1826
6834-P-35B diaphragm
failure
barg
NA
XX
NA
NA
68-PI-1827
6834-P-35C diaphragm
failure
barg
NA
XX
NA
NA
68-PI-1828
6834-P-34A diaphragm
failure
barg
NA
XX
NA
NA
68-PI-1829
6834-P-34B diaphragm
failure
barg
NA
XX
NA
NA
68-PI-1830
6834-P-34C diaphragm
failure
barg
NA
XX
NA
NA
68-AI-1831
Neutralisation pump
discharge pH
pH
XX
XX
NA
NA
68-FI-1831
Neutralisation pump
discharge flow
m3/hr
XX
XX
NA
NA
68-FI-1835
Static Mixer inlet DM Water
flow
m3/hr
XX
XX
NA
NA
68-AI-1832
Static Mixer-A outlet
conductivity
µs
XX
XX
NA
NA
68-AI-1833
Static Mixer-B outlet
conductivity
µs
XX
XX
NA
NA
68-FI-1836
Static Mixer inlet DM Water
flow
m3/hr
XX
XX
NA
NA
68-AI-1833
Static mixer outlet
conductivity
µs
XX
XX
NA
NA
7.2.7
Boiler feed water system
Surveillance of the Boiler feed water System includes the following:
•
Ensure the Steam Condensate Flash Drum pressure is maintained around 0.1 barg
by monitoring the 68-PG-1308.
•
Ensure the Steam Condensate Flash Drum level is maintained around 50 % by
monitoring the level through 68-LI-1301.
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TITLE: OPERATION AND MAINTENANCE MANUAL
•
Ensure De-aerator Feed Pumps 6834-P-20A/B is running normal by monitoring
discharge flow (68-FIC-1301) maintained at 83 m3/hr
•
Ensure the Steam Condensate Cooler Fans are running normal
•
Monitor the De-aerator top pressure 68-PIC-1304 at 0.2 barg.
•
Ensure the De-aerator level is maintained at 50%.
•
Ensure the LP saturated steam flow 68-FI-1309 to De-aerator is maintained around
180 Kg/hr.
•
Ensure the BFW pumps 6834-P-22A/B/C are running normal with discharge
pressure (68-PI-1307) of 20.8 barg
•
Routine analysis of Boiler Feed Water from De-aerator Vessel 6834-A-08 should be
carried out and confirm that the Oxygen content is <0.007 ppm wt.
•
Check the inventories of the chemicals like Oxygen Scavenger and complex
product regularly and arrange for the road Tankers to avoid shortage of chemicals
at any time.
•
Normal operating parameters values are tabulated below:
Tag No.
68-PG-1308
68-LI-1301
68-FIC-1301
68-PIC-1304
68-LIC-1302
68-FI-1309
68-PI-1307
68-TIC-1301
•
•
Steam condensate flash drum pressure
Steam condensate flash drum level
De-aerator feed pumps 6834-P-20A/B
flow
De-aerator top pressure
De-aerator level
LP saturated steam flow
BFW pumps 6834-P-22A/B/C pressure
Steam Condensate Flash Drum
temperature
Required
Value
Unit
0.1
barg
50
%
83
m3/hr
0.2
50
180
20.8
Barg
%
Kg/hr
barg
102
°C
On daily basis check the following:
•
Visual inspection of the entire plant to detect any possible defects (leaking
flanges, loose fixtures, etc.)
•
Make sure that good de-aeration process is accomplished. If the Boiler Feed
Water quality is not satisfactory, check the chemical injection flow rate.
On Weekly basis check the following:
•
•
Description
If there are any leakages, tighten the flanges concerned, if that does not stop
the leakage; make arrangements to stop the installation for repair.
On monthly basis check the following:
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TITLE: OPERATION AND MAINTENANCE MANUAL
•
Detailed inspection of the entire plant should be made to detect any
malfunctions of Boiler Feed Water pumps and Chemical Injection pumps.
Monitor the pressure and flow trend of the Boiler Feed Water system through 68-PI1307 and 68-FIC-1305. In case of any increase or decrease in consumption, take the
corrective action.
7.2.8
Steam Generation
During normal operation of the boiler, attention should be paid to the proper
operation of all the ancillaries and equipment in service.
Safe and reliable operation of the steam generator depends on routine monitoring of
the control and safety systems.
Controls and checks must be done continuously, also if the system is operated
automatically.
Any variation in the operating parameters indicates a change in boiler performances
and proper actions should be taken in order to restore the previous conditions.
In fact variations in the selected and settled parameters can result in worsening of the
auxiliary power consumption and/or boiler efficiency, or sometimes can indicate a risk
of possible damage.
For example, the increasing of the boiler flue gas exit temperature can indicate
possible carbon fouling deposition on tube surfaces or improper flame position or missadjustment of the air-fuel ratio.
In particular the following parameters shall be controlled carefully.
a.
Boiler Water Level
Water level variations in the boiler take place in case of rapid increase or decrease in
steam output, so the proper water level in the steam drum must be maintained.
Boiler water level is maintained by the level controller 91-LIC-1522 (set at 50%).
Monitor the Boiler water level by the level gauges 91-LG-1522 & 91-LG-1523 during
normal operation.
Regularly cross check the DCS indicated level with level gauge.
b.
Boiler Feed Water
The Boiler Feed Water should be carefully treated and monitored during boiler
operation as it is essential to assure boiler integrity. It is important that plant
operators always maintain the quality of Boiler feed Water as given below.
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Feed Water quality (Limit Values)
Parameters
Units of
Measurements
Appearance
-
Clear, colourless,
no suspended
solids
Direct Conductivity @ 25°C
µS/cm
< 10
Acid Conductivity @ 25°C
µS/cm
< 0.2
-
> 9.2
Total Hardness (Ca + Mg)
mg/l
Nil
Sodium and Potassium (Na + K)
mg/l
< 0.010
Iron (Fe)
mg/l
< 0.020
Copper (Cu)
mg/l
< 0.003
Silica (SiO2)
mg/l
< 0.020
Oxygen (O2)
mg/l
< 0.02
Oil/Grease
mg/l
< 0.1
Organic Compounds (as TOC)
mg/l
< 0.2
pH @ 25°C
Boiler Feed Water Quality (Limit Values)
Parameters
Units of
Measurements
-
Clear, colourless,
no foam
Direct Conductivity @ 25°C
µS/cm
< 100
Acid Conductivity @ 25°C
µS/cm
< 50
pH @ 25°C
-
9.5-10.5
Alkalinity
mmol/l
0.05-0.3
Silica (SiO2)
mg/l
< 70
Phosphate (PO4)
mg/l
<6
Appearance
The Steam Generator is provided with one sampling system, that allows to analyse the
quality of the Boiler Feed Water.
The Boiler Feed Water Conductivity is maintained by acting on the CBD control valve,
whose position determines the conductivity of the Boiler Feed Water.
In order to get quality Boiler Feed Water, the following actions to be taken:
•
Establish a strict control of Feed Water and Boiler Water parameters through a
routine sampling and subsequent chemical analysis of the samples at least one for
each working shift (8 hours) or more frequently. Record each analysis result to
easily check all data comparing them with boiler load and injection amounts of
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chemical additives. This database allows also to check immediately any possible
data variation and consequently to take the necessary remedial actions.
•
Feed water quality: Maintain Feed Water quality continuously by acting on
Continuous Blow Down. Generally the CBD flow rate, during a good and regular
boiler operation, should be about 1% of boiler MCR (the most economic and best
operation should be based on a target of 0.5%). However, in case of need, the CBD
flow rate can be temporarily increased by 2-3%.
•
Operation at high CBD flow rates clearly indicates that boiler water quality is not
under control and that necessary remedial action must be taken.
•
Chemicals dosing injection: Operator must check that chemical dosing system is
available and that all chemicals are injected at the required rate and
concentration in the Feed Water and in Boiler Feed Water.
Attention: For water chemical conditioning, it’s absolutely forbidden to use strong
alkali compounds, with particular reference to those containing caustic soda (Sodium
Hydroxide) and caustic potash (Potassium Hydroxide). It’s allowed to use volatile alkali
compounds, adequately dosed and in the recommended quantity and phosphate
treatment.
c.
Blow down, Water Column and Glass Indicators
The CBD flow rate is automatically adjusted by the system according to the measured
value of boiler water conductivity.
The sampling system dedicated to steam generator is provided also with manual
sampling line for each sample that can be used to perform a complete analysis of the
feed/boiler water.
Typically the facilities of a qualified water treatment laboratory should be employed
to establish the feed/boiler water chemical characteristics and the chemical reactants
to be injected, their frequency and quantity.
Note: As chemical corrosion attack or salt deposition on internal surfaces generally
grows slowly on boiler internal pressure parts, BE recommends to sample and analyse
periodically the feed water and boiler water and to record the chemical analysis
results (as conductivity, pH, alkalinity, TDS and all the others) in a dedicated book. So
during steam generator life, all variations can be immediately monitored and possible
immediate corrective actions (if and when necessary) can be activated.
Note: When the boiler is in normal operation and in any cases when the boiler
water/steam pressure is higher than atmospheric pressure, no manual boiler pressure
part drain valves shall be opened.
The boiler water column and level glass indicator shall be periodically and very
carefully purged at least one time a week, so to limit sludge or sediment accumulation
in these devices.
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In fact all this kind of accumulated deposits could cause an erroneous indication of the
water level.
d.
Flame Pattern
It is important to assure a good flame pattern in order to get a stable and safe
combustion, limiting possible impingement on furnace wall tubes or on burner throat
refractory and limiting also any possible flame pulsation.
A good combustion will allow achieving the expected boiler performance, both in
terms of steam production and flue gas emissions.
On the contrary improper flame pattern could result in carbon build-up on the external
tube surfaces that could reduce the thermal heat transfer, and consequently could
increase the flue gas temperatures at the stack, so creating an efficiency reduction.
Flame instability can cause some dangerous vibration phenomena and possible
unburned fuel zone accumulation into the furnace. This dangerous situation must be
absolutely avoided: in such case all the combustion system parameters must be
controlled again till to eliminate this disturbance.
Steam Generation unit normal operating parameters with values are tabulated below:
Tag No.
68-LIC-1522
Description
Boiler drum level
Required
Value
50
Unit
%
3
68-FIC-1522
Boiler Feed Water flow
XXX
m /hr
68-TIC-1522
SH steam temperature
163
°C
68-TIC-1820
LP Steam header temperature
XX
°C
68-PIC-1523A
Boiler drum pressure
16.4
barg
68-FIC-1525
Fuel gas flow to boiler
XXX
Kg/hr
68-FIC-1526
Combustion air flow to boiler
XXX
Kg/hr
68-AIC-1522
Oxygen analyzer controller
XXX
%
68-ZIC-1524
Flue gas damper position controller
XXX
%
68-PIC-1523B
Steam pressure vent
17.4
barg
68-PIC-1306
LP steam header pressure
5
barg
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SECTION VIII
START-UP AFTER EMERGENCY SHUTDOWN
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8.1
GENERAL
Restart after Emergency Shutdown is discussed for the following units:
8.2
•
Tail Gas Incinerator
•
Acid Gas Enrichment Unit
•
SRU
•
TGTU
TAIL GAS INCINERATOR RESTART
After the Tail Gas Incinerator ESD shutdown is activated, the unit is restarted as
follows:
8.3
•
Confirm the root cause of the Incinerator shutdown and rectify the same
problem. Reset the ESD by pressing 65-HS-4001R for ESD-0, 65-HS-001R for
ESD-1 and 65-HS-1192 for ESD-2/3/4
•
Check and confirm the availability of utilities for operation.
•
Start Incinerator as per procedure described in section 6.3.1
ACID GAS ENRICHMENT UNIT RESTART
After an emergency shutdown of AGEU, the unit is still with liquid levels in Acid Gas
Amine Absorber column bottoms, Amine Surge Tank, Amine Regenerator and Amine
Regenerator Reflux Drum.
•
Confirm the root cause of the Acid Gas Enrichment Unit shutdown and rectify the
same problem. Reset the ESD by pressing 65-HS-4001R for ESD-0, 65-HS-001R for
ESD-1 and 65-HS-1192 for ESD-2/3/4
•
Confirm that all the utility services are available and all rotating equipments are
ready for operation
•
Confirm that the downstream units are ready to receive the acid gas
•
All instrumentation is confirmed as reading correctly on the DCS, against local
instrumentation and local gauges
•
All shut-down devices have been tested
•
Confirm Tail Gas Incinerator is in line
•
Acid gas feed to AGEU is isolated from upstream units
•
Acid gas from Regenerator Reflux Drum to Sulphur Recovery Unit is isolated and LP
Acid Gas flare is lined up
•
Start AGEU as per the procedure described in section 6.3.2
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8.4
SULPHUR RECOVERY UNIT RESTART
After an emergency shutdown of SRU, the unit is still with liquid levels in Reaction
Furnace Boiler 9101-E-07, Reaction Furnace Condenser 9101-E-01, 1st Stage Condenser
9101-E-02 and Last Condenser 9101-E-04.
•
Confirm the root cause of the SRU shutdown and rectify the same problem.
Reset the ESD by pressing 65-HS-4001R for ESD-0, 65-HS-001R for ESD-1 and
65-HS-1192 for ESD-2/3/4
•
Confirm that all the utility services are available and all rotating equipments
are ready for operation
•
Confirm that the downstream units are ready to receive the tail gas
•
All instrumentation is confirmed as reading correctly on the DCS, against local
instrumentation and local gauges
•
All shut-down devices have been tested
The restart is done considering that SRU converters 1st Stage Converter 9101-V-01 & 2nd
Stage Converter 9101-V-02 contain sulphur compounds. To ensure that during this
start-up, there is no ignition of any Sulphur compounds within the unit, the Reaction
furnace burner is operated at slightly sub-stoichiometric firing condition.
• Start SRU as per the procedure described in section 6.3.3.
8.5
TGTU RESTART
After the TGTU unit ESD is activated, the unit is still with liquid levels in Reactor
Effluent Cooler 9102-E-11 and Desuperheater/Contact Condenser 9102-C-11 top and
bottom sections.
•
Confirm the root cause of the TGTU shutdown and rectify the same problem.
Reset the ESD by pressing 65-HS-4001R for ESD-0, 65-HS-001R for ESD-1 and
65-HS-1192 for ESD-2/3/4.
•
Confirm that all the utility services are available and all rotating equipments
are ready for operation
•
Confirm that the downstream units are ready to receive the tail gas
•
All instrumentation is confirmed as reading correctly on the DCS, against local
instrumentation and local gauges
•
All shut-down devices have been tested
The Hydrogenation Reactor catalyst is in sulphided state so sulphiding of the catalyst is
not required. The start-up is carried out considering that unit contains Sulphur
compounds and ensure that during this start-up there is no ignition of any Sulphur
compounds within the unit; the RGG burner is operated at slightly sub-stoichiometric
firing conditions from the start of ignition in the RGG.
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•
Close XV-1332 on tail gas line from Reactor Effluent Cooler to
Desuperheater/Contact Condenser and open XV-1331 on tail gas line from Reactor
Effluent Cooler to Tail Gas Incinerator.
•
Start TGTU as per the procedure described in section 6.3.4.
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SECTION IX
TROUBLE SHOOTING OPERATIONS
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9.1
PROCESS
9.1.1
Incinerator
Sl. #
Problem
1.
High SO2 content
in stack gas
2.
Diagnosis
Control Action
SOX Analyser
91-AI-1052
indicates high
alarm 91-AAH1052
Claus sulphur
recovery unit
Sulphur recovery is
low
Ensure all process
parameters in Claus
sulphur recovery
unit are at normal
operating condition
High Oxygen
content in stack
gas
O2 Analyzer, 91-AI1051 indicates
high O2 alarm
91-AAH-1051
Excess Oxygen
reacts with SO2 and
form SO3, which
makes high corrosion
Reduce air flow to
Incinerator through
91-HIC-1155A
3.
Low Oxygen
content in stack
gas
O2 Analyzer 91-AI1051 Indicates
low O2 alarm
91-AAL-1051
Low Oxygen content
indicates unburnt
sulphur compound
to environment
Increase Air flow to
Incinerator through
91-HIC-1155A
4.
Reduction in
Incinerator
temperature
Combustion air
flow low alarm
91-FAL-1156C
1. Incinerator Air
Blower 9101-K-12
A/B mechanical
problem
Check/rectify
Incinerator Air
Blower 9101-K12A/B
2. Incinerator Air
Blower 9101-K-12
A/B VFD
malfunction
Check/rectify the
Incinerator Air
Blower 9101-K12A/B VFD parts
Malfunction of fuel
gas control valve
91-FV-1155
Check/rectify
malfunction of fuel
gas flow control
valve 91-FV-1155
5.
9.1.2
Drop in
Incinerator
temperature
Indication
Fuel gas pressure
low alarm 91PAL-1157
Acid Gas Enrichment Unit
Sl. #
Problem
Indications
Diagnosis
Control Action
1.
Acid gas feed to
Acid Gas Amine
Absorber 9103-C11 temperature
is high
Temperature
indicator is
provided 91-TI-1503
showing high
temperature and
initiation of high
temperature alarm
91-TAH-1503
H2S content in
treated gas will
increase due to low
absorption rate
Check sea cooling
water flow to the
Acid Gas Coolers
9103-E-101A/B
2.
Lean amine feed
to Acid Gas
Amine Absorber
9103-C-11
temperature is
high
Temperature gauge
91-TG-1505 is
provided showing
high temperature
H2S content in
treated gas will
increase due to low
absorption rate
Check Lean Amine
Cooler 9103-E-14
fans are running
and sea cooling
water flow for the
Lean Amine Trim
Cooler 9103-E-15
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Sl. #
Problem
Indications
Diagnosis
Control Action
3.
Less Amine
concentration in
MDEA solution
Lab Sample analysis
shows less amine
concentration
Absorption rate low
Add fresh MDEA
solution to reach
the required
concentration
4.
High H2S content
in treated acid
gas from
absorber to
Incinerator
H2S analyser
indicator is
provided 91-AI-1501
showing high H2S
content and
initiation of high
H2S content alarm
91-AAH-1501
Absorption rate low
Increase lean
amine circulation
rate
5.
High pressure
difference across
the tray in
absorber column
Differential
pressure indicator
91-PDI-1522 is
provided showing
high differential
pressure and
initiation of high
differential
pressure alarm
91-PDAH-1522
Absorption rate
low, due to foaming
Start Antifoam
Injection to
Absorber column
6.
High pressure
difference across
the tray in
Regenerator
column
Differential
Pressure indicator
is provided 91-PDI1523 showing high
pressure difference
and initiation of
high pressure
difference alarm
91-PDAH-1523
Regeneration rate
low due to foaming
Start Antifoam
Injection to
Regenerator
column
7.
Regenerator
Reboiler steam
flow low
Ratio controller
91-HIC-1503 is
provided for rich
amine to
Regenerator and
steam to Reboiler.
91-FIC-1503
showing low steam
flow and initiating
low flow alarm
91-FAL-1503
Regeneration rate
will decrease
Increase LP steam
flow to
Regenerator
Reboiler
8.
Suspended solids
in lean amine
solution
Amine solution is
not clear, it has
suspended solids
Lean amine quality
will reduce
Isolate amine
filters and check
filters condition
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9.1.3
Sl. #
1
Sulphur Recovery Unit
Problem
Acid gas flow
is low
Indications
Flow transmitter 91FT-1140 is provided.
On low low flow 91FALL-1140 shutdown is
initiated
Diagnosis
Feed gas to
Reaction
Furnace is low
Control Action
Maintain the
Reaction furnace
temperature at
normal operating
temperature with
help of fuel gas
Divert tail gas to
Incinerator from
Tail gas treating
unit
2
Purge air to
Reaction
furnace
purging nozzle
low pressure
Pressure Indicator
91-PI-1002 is provided
Sulphur
condensation
occurs in purge
nozzle point
Nitrogen purging
to Reaction
furnace
instrument nozzle
opens when
incase of blower
shutdown
3
Acid gas
temperature is
low due to MS
steam failure
Temperature indicator
91-TI-1003 is provided
Reaction
Furnace
temperature is
reduced
Start fuel gas feed
to Reaction
furnace
4
Air
temperature is
low due to MS
steam failure
Temperature indicator
91-TI-1004 is provided
Reaction
furnace
temperature is
reduced
Start fuel gas
firing to Reaction
furnace for
maintaining
temperature at
normal operating
condition
5
1st Stage
Converter
inlet and
outlet
temperature
difference is
low
Manually calculate
temperature
difference between
inlet temperature
(91-TIC-1007) and
outlet temperature
(91-TI-1017)
Conversion of
H2S to Sulphur is
less
Start catalyst
regeneration
6
2nd Stage
Converter
inlet and
outlet
temperature
difference is
low
Manually calculate
temperature
difference between
inlet temperature
indicator 91-TIC-1019
and outlet
temperature indicator
Conversion of
H2S to Sulphur is
less
Start catalyst
regeneration
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Sl. #
Problem
7
High H2S
content in
liquid sulphur
from
degassing pit
to storage
compartment
9.1.4
Indications
Lab sample analysis
shows high H2S
concentration, it is
carried out as per
sampling schedules
Diagnosis
Control Action
High H2S
content in
sulphur make
poly sulphite
formation
Increase catalyst
injection rate
Tail Gas Treating Unit
Sl. #
Problem
Indications
Diagnosis
Control Action
1.
Hydrogenation
Reactor inlet
and outlet
temperature
difference is
low
Calculated
temperature
difference between
inlet 91-TIC-1307 and
outlet temperature
91-TI-1310 is indicated
by 91-TDI-1307
Conversion of
sulphur to H2S is
less
Increase Reactor
inlet temperature
2.
3.
4.
Low pH in
wash water
High pressure
difference
across the
Desuperheater
packing
Wash water
filter 9102-S15 differential
pressure high
Analyser (pH) is
provided 91-AI-1302
showing low pH and
initiation of low pH
alarm 91-AAL-1302
Pressure difference
indicator is provided
91-PDI-1324 showing
high pressure
difference and
initiation of high
pressure difference
alarm 91-PDAH-1324
Differential pressure
indicator is provided.
91-PDI-1329 showing
high pressure and
initiation of high
pressure difference
alarm 91-PDAH-1329
High corrosion
will occur due
to acid gas SO2
content high
More
recirculation
rate
Deposition of
impurities on
surface of filter
element
Start caustic
injection to
Desuperheater
Circulation Pumps
9102-P-11A/B
suction
Divert final
sulphur condenser
tail gas to
Incinerator
Decrease
recirculation
water flow to
Desuperheater
Open filter bypass
valve and run the
plant for short
duration and
clean the filter
element
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Sl. #
Problem
Indications
5.
Tail gas to Tail
Gas Amine
Absorber
temperature is
high
Temperature indicator
is provided 91-TI-1317
showing high
temperature and
initiation of high
temperature alarm
91-TAH-1317
H2S absorption
rate will
decrease
Increase
circulating cooling
water to
Desuperheater/Co
ntact Condenser
6.
Amine
concentration
is less in MDEA
solution
Lab sample analysis
shows less amine
concentration
Absorption rate
will be reduced
Add fresh MDEA
solution to the
required
concentration
7.
High H2S/H2
ratio content
in treated acid
gas from Tail
Gas Amine
Absorber to
Incinerator
H2S/H2 analyser
indicator is provided
91-AI-1301 showing
high H2S/H2 content
and initiation of high
H2S/H2 content alarm
91-AAH-1301
Less absorption
rate
Increase lean
amine feed rate
Diagnosis
Control Action
9.2
Diagnosis
Control Action
UTILITIES
9.2.1
Instrument air package
a.
Air Compressor
Sl. #
1.
2.
3.
4.
Problem
Indications
High
Abnormal sound
temperature in
in compressor
DE/NDE bearing.
Indicated by
Low lube oil
68-PI-1402
discharge
Low level in lube
pressure
oil sump Low
Abnormal sound High
in inter and
temperature in
after cooler Air DE/NDE bearings
Fans
and Gear box
Compressor
starts running,
but does not
load after a 20
sec delay time
Compressor
loaded lamp
68-XL-1409
indication in
Bearing is worn
out
Check and replace if
required
Choke in lube oil
filter
Clean the filter
Actual level low
Top-up lube oil
Bearing are worn
out
Check and replace if
required
Net air pressure
68-PT-1311/
68-PT-1406 is
above the loading
set point
LCP Malfunction of
Loading solenoid
valve
Compressor will load
when pressure in air
net drops to pre-set
loading pressure
Check and replace if
required
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Sl. #
5.
6.
7.
Problem
Water
separators
condensate
level increase
Indications
High high level
indication
(68-XA-1402/
1406)in UCP
Diagnosis
Malfunction of
level indicators
Malfunction of
automatic drain
valves
High
differential
68-PDI-1403 high
Filter choke
pressure across alarm
lube oil filter
Consumption
Exceeds air
delivery of
Low discharge
compressor
Low pressure
pressure of
indication at
Instrument air
68-PI-1406
Choked air filters
Compressor
Air leakage
b.
Control Action
Check and replace if
required
Check and replace if
required
Clean the filter
Check equipment
connected/vents/
drains
Remove filter
assembly, clean and
check/Replace filters
Check and arrest
leaks
Air Dryer
Sl. #
Problem
Indications
Diagnosis
Free water in
compressed air
inlet
1.
High dew point
High dew point alarm (68-AI1401/1451)
2.
Dryer outlet
flow/pressure
is low
Low flow alarm
68-FI-1302/
68-PI-1302
3.
Dryer fails to
shift
Dryer fault
alarm
Temperature of
compressed air
too high
Poor desiccant
performance/
Desiccant has
become over
saturated for a
longer period
Control Action
Check the condensate
separators and drains
upstream of the dryer
if they are operative
Check the compressor
after-cooler fan is
operative
Replace desiccant.
Check the
maintenance schedule
for normal
replacement periods
Check inlet filters of
compressor and check
the outlet pressure of
Poor performance
the compressor and
of IA Compressor
compare this with the
inlet pressure of the
dryer
Check Instrument Air
Instrument air
Filter. Clean if
pressure low
necessary
Check the valve,
Failure on the
actuator and the pilot
inlet valves
air pressure to the
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Sl. #
Problem
Indications
Diagnosis
Leak in
Instrument air
tubes
Leak in valve
actuator
4.
9.2.2
Dryer fault
alarm
Replace tube
Service or replace
actuator
Check instrument air
Instrument air
filter. Clean if
pressure low
necessary
Check the valve,
actuator and the
Failure of the
instrument air
valve
pressure to the
actuator
Solenoid does not Check and replace
open
defective parts
Effluent & Waste Water Treatment Unit
Sl. #
1.
2.
9.2.3
Regeneration
valve fails to
open
Control Action
actuator
Problem
Indications
Diagnosis
Control Action
Stripper
Reboiler
steam
failure
Low steam flow
alarm 69-FAL1315
Isolate sour water
Stripping rate of feed to Sour Water
H2S will decrease Stripper and divert to
the Observation sump
High H2S
content in
stripped
water
Lab sample
analysis shows
high H2S
concentration, it
is carried out as
per sampling
schedules
High H2S content
to Observation
sump
Increase steam flow
to Sour Water Stripper
Reboiler
Electro Chlorination Package
Sl. #
Problem
Indications
Diagnosis
Loss of sea water
supply
1.
Electrolyser
inlet flow low
69-FI-1451/ 1452
Isolating valves
low alarm
partially closed
Control Action
Check for sea water
supply pressure
Check and adjust the
manual position of
valves
Blockage in the cell Rectify the blockage
2.
Degassing Tank 69-LI-1451 high
overflows
high alarm
Tank outlet
restricted
Check manual outlet
valves are opened
Check the 69-FIExcessive flow in to
1451/1452 set at
the tank
10 m3/hr
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TITLE: OPERATION AND MAINTENANCE MANUAL
Sl. #
Problem
Indications
No level in
69-LI-1451 low
3.
degassing tank level alarm
Duty Hydrogen
Dilution
4.
Blower not
working
Running
indication and
ampere
indication
Diagnosis
Control Action
Tank drain valve
open
Check and rectify
Tank or associated
piping leak
Check and arrest the
leaks
Mechanical defect
in blower
Check and rectify as
required
Electrical fault
Check blower power
supply and associated
protective devices
Check the blower
motor
Do blower
Duty blower
changeover and
performance is very
check the
poor
abnormality
5.
Dilution air
pressure low
69-PT-1464 low
alarm
Phase failure
Transformer
6. rectifier not
working
Thyristor fuse
failure
9.2.4
Blocked suction
filter on duty
blower
Remove and clean
the filter
Transmitter
malfunction
Check the impulse
lines for any block
and check the
electronics
Loss of phase on
incoming supply
Check incoming
supply and fuses
Monitoring defect
inside the
Transformer/
Rectifier
Check and replace
the phase failure
relay
Earth with in T/R
Trace and identify
Rectifier failed
Check and replace
the Rectifier
Chemical Injection Packages
a.
Complex Product Injection Package
Sl. #
Problem
1
Low level in
Complex
Product
Storage Tank
6834-T-18
Indication
Low level
alarm
68-LAL-1317
Diagnosis
Corrective action
Complex product is
consumed during
injection
Make up with the
Complex Product
solution
Malfunction of level
transmitter
68-LT-1317
Verify with level
gauge 68-LG-1307.
Isolate the level
transmitter and
rectify
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TITLE: OPERATION AND MAINTENANCE MANUAL
Sl. #
Problem
Indication
Diagnosis
Corrective action
2
High level in
Complex
Product
Storage Tank
6834-T-18
High level
alarm
68-LAH-1317
Continuous filling of
Complex product
from the
drum/dilution
Stop unloading from
the drum
Malfunction of level
transmitter
68-LT-1317
Verify with level
gauge 68-LG-1307.
Isolate the level
transmitter and
rectify.
High
diaphragm
pressure of
Complex
Product
Pump 6834-P41A/B
High pressure
alarm
68-PAH-1326/
68-PAH-1327
Diaphragm rupture
Rectify the problem
in diaphragm
Malfunction of
pressure transmitter
68-PT-1326/
68-PT-1327
Rectify the problem
in pressure
transmitter
Low flow at
injection
point
Low injection
rate
Operating at low
stroke
Increase the stroke
length
Choke/obstruction in
suction line
Check and rectify
NRV got struck in the
discharge line
Check and rectify
Pump not developing
pressure
Check the Pump and
rectify
3
4
b.
Oxygen Scavenger Injection Package
Sl. #
1
2
Problem
Indication
Diagnosis
Corrective action
Low level in
Oxygen
Scavenger
Storage Tank
6834-T-17
Low level
alarm
68-LAL-1315
Oxygen Scavenger is
consumed during
injection
Make up with the
Oxygen Scavenger
Solution
Malfunction of level
transmitter
68-LT-1315
Verify with level
gauge 68-LG-1306.
Isolate the level
transmitter and
rectify
High level in
Oxygen
Scavenger
Storage Tank
6834-T-17
High level
alarm
68-LAH-1315
Continuous filling of
Oxygen Scavenger
from the drum/
dilution
Stop unloading from
the drum
Malfunction of level
transmitter
68-LT-1315
Verify with level
gauge 68-LG-1306.
Isolate the level
transmitter and
rectify.
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TITLE: OPERATION AND MAINTENANCE MANUAL
Sl. #
3
4
c.
Problem
Indication
Diagnosis
Corrective action
High
diaphragm
pressure of
Oxygen
Scavenger
Injection
Pump 6834-P39A/B
High
pressure
alarm
68-PAH1324/
68-PAH-1325
Diaphragm rupture
Rectify the problem
in diaphragm
Malfunction of
pressure transmitter
68-PT-1324/
68-PT-1325
Rectify the problem
in pressure
transmitter
Low flow at
injection point
Low
injection
rate
Operating at low
stroke
Increase the stroke
length
Choke/obstruction in
suction line
Check and rectify
NRV got struck in the
discharge line
Check and rectify
Pump not developing
pressure
Check the Pump
and rectify
Biocide Injection Package
Sl. #
Problem
Indication
Diagnosis
1
Low level in
Biocide
Storage tank
6932-T-04
Low level
alarm
69-LAL-1328
Biocide is consumed
during injection
Make up with
Biocide solution
Malfunction of level
transmitter
69-LT-1328
Verify with level
gauge 69-LG-1309.
Isolate the level
transmitter and
rectify
High level in
Biocide
Storage Tank
6932-T-04
High level
alarm
69-LAH-1328
Continuous filling of
Biocide from the
drum/dilution
Stop unloading
from the drum
Malfunction of level
transmitter
69-LT-1328
Verify with level
gauge 69-LG-1309.
Isolate the level
transmitter and
rectify.
High
diaphragm
pressure of
Biocide
Injection
Pump 6932-P07A/B
High pressure Diaphragm rupture
alarm
69-PAH-1344/ Malfunction of
1346/1328/
pressure transmitters
1345/1347/
1329
Low flow at
injection
point
Low
injection
rate
2
3
4
Corrective action
Rectify the problem
in diaphragm
Rectify the problem
in pressure
transmitter
Operating at low
stroke
Increase the stroke
length
Choke/obstruction in
suction line
Check and rectify
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TITLE: OPERATION AND MAINTENANCE MANUAL
Sl. #
d.
Problem
Indication
Diagnosis
Corrective action
NRV got struck in the
discharge line
Check and rectify
Pump not developing
pressure
Check the Pump
and rectify
Scale Inhibitor Injection Package
Sl. #
1
2
3
4
Problem
Indication
Low level in
Scale Inhibitor
Storage Tank
6932-T-05
Low level
alarm
69-LAL-1330
High level in
Scale Inhibitor
Storage Tank
6932-T-05
High level
alarm
69-LAH-1330
High
diaphragm
pressure of
Scale Inhibitor
Injection
Pump 6932-P09A/B
High
pressure
alarm 69PAH-1338/
1348/1350/
1339/1349/
1351
Low flow at
injection
point
Low
injection
rate
Diagnosis
Corrective action
scale inhibitor is
consumed during
injection
Make up with the
Scale Inhibitor
solution
Malfunction of level
transmitter 69-LT1330
Verify with level
gauge 98-LG-1310.
Isolate the level
transmitter and
rectify
Continuous filling of
Scale Inhibitor from
the drum/dilution
Stop unloading
from the drum
Malfunction of level
transmitter 69-LT1330
Verify with level
gauge 69-LG-1310.
Isolate the level
transmitter and
rectify.
Diaphragm rupture
Rectify the problem
in diaphragm
Malfunction of
pressure transmitters
Rectify the problem
in pressure
transmitter
Operating at low
stroke
Increase the stroke
length
Choke/obstruction in
suction line
Check and rectify
NRV got struck in the
discharge line
Check and rectify
Pump not developing
pressure
Check the Pump
and rectify
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TITLE: OPERATION AND MAINTENANCE MANUAL
e.
Catalyst Injection Package
Sl. #
Problem
1
Low level in
Catalyst
Storage Tank
9101-T-01
Low level
alarm 91-LAL1127
High level in
Catalyst
Storage Tank
9101-T-01
High level
alarm
91-LAH-1127
High
diaphragm
pressure of
catalyst
injection
Pump 9101-P11A/B
High pressure Diaphragm rupture
alarm 91PAH-1128/
Malfunction of
91-PAH-1129
pressure transmitter
91-PT-1128/91-PT1129
Low flow at
injection
point
Low injection
rate
2
3
4
f.
Indication
Diagnosis
Corrective action
Catalyst solution is
consumed during
injection
Make up with the
catalyst solution
Malfunction of level
transmitter 91-LT1127
Verify with level
gauge 91-LG-1127.
Isolate the level
transmitter and
rectify
Continuous filling of
Catalyst from the
drum/dilution
Stop unloading
from the drum
Malfunction of level
transmitter 91-LT1127
Verify with level
gauge 91-LG-1127.
Isolate the level
transmitter and
rectify.
Rectify the problem
in diaphragm
Rectify the problem
in pressure
transmitter
Operating at low
stroke
Increase the stroke
length
Choke/obstruction in
suction line
Check and rectify
NRV got struck in the
discharge line
Check and rectify
Pump not developing
pressure
Check the Pump
and rectify
Antifoam Injection Package
Sl. #
1
Problem
Low level in
Antifoam
Storage Tank
9103-T-12
Indication
Low level
alarm 91-LAL1521
Diagnosis
Corrective action
Antifoam is
consumed during
injection
Make up with
Antifoam solution
Malfunction of level
transmitter 91-LT1521
Verify with level
gauge 91-LG-1510.
Isolate the level
transmitter and
rectify
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TITLE: OPERATION AND MAINTENANCE MANUAL
Sl. #
2
3
4
g.
Problem
Indication
High level in
Antifoam
Storage Tank
9103-T-12
High level
alarm 91LAH-1521
High
diaphragm
pressure of
Antifoam
Injection
Pump 9103-P16A/B
Low flow at
injection
point
Diagnosis
Corrective action
Continuous filling of
Antifoam from the
drum/dilution
Stop unloading
from the drum
Malfunction of level
transmitter 91-LT1521
Verify with level
gauge 91-LG-1510.
Isolate the level
transmitter and
rectify.
High pressure
alarm 91PAH-1565/91PAH-1566
Diaphragm rupture
Rectify the problem
in diaphragm
Malfunction of
pressure transmitter
91-PT-1565/91-PT1566
Rectify the problem
in pressure
transmitter
Low injection
rate
Operating at low
stroke
Increase the stroke
length
Choke/obstruction in
suction line
Check and rectify
NRV got struck in the
discharge line
Check and rectify
Pump not developing
pressure
Check the Pump
and rectify
Corrosion Inhibitor Injection Package
Sl. #
Problem
Indication
Diagnosis
1
Low level in
Corrosion
Inhibitor
Storage Tank
9103-T-13
Low level
alarm 91-LAL1523
Corrosion Inhibitor is
consumed during
injection
Make up with
Corrosion Inhibitor
solution
Malfunction of level
transmitter 91-LT1523
Verify with level
gauge 91-LG-1511.
Isolate the level
transmitter and
rectify
High level in
Corrosion
Inhibitor
Storage tank
9103-T-13
High level
alarm 91LAH-1523
Continuous filling of
Corrosion Inhibitor
from the drum/
dilution
Stop unloading
from the drum
Malfunction of level
transmitter 91-LT1523
Verify with level
gauge 91-LG-1511.
Isolate the level
transmitter and
rectify.
2
Corrective action
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TITLE: OPERATION AND MAINTENANCE MANUAL
Sl. #
Problem
Indication
3
High
diaphragm
pressure of
corrosion
inhibitor
injection
Pump 9103-P101A/B
High pressure
alarm 91PAH-1567/
91-PAH-1568
Diaphragm rupture
Rectify the problem
in diaphragm
Malfunction of
pressure transmitter
91-PT-1567/91-PT1568
Rectify the problem
in pressure
transmitter
Low flow at
injection
point
Low injection
rate
Operating at low
stroke
Increase the stroke
length
Choke/obstruction in
suction line
Check and rectify
NRV got struck in the
discharge line
Check and rectify
Pump not developing
pressure
Check the Pump
and rectify
4
h.
Sl. #
1
2
3
Diagnosis
Corrective action
Caustic Injection Package
Problem
Indication
Low level in
Caustic
Storage Tank
9103-T-14
Low level
alarm 91-LAL1525
High level in
caustic
storage tank
9103-T-14
High level
alarm
91-LAH-1525
High
diaphragm
pressure of
Caustic
Injection
Pump 9103-P103A/B
High pressure
alarm 91PAH-1569/
91-PAH-1570
Diagnosis
Corrective action
Caustic product is
consumed during
injection
Make up with
caustic solution
Malfunction of level
transmitter 91-LT1525
Verify with level
gauge 91-LG-1512.
Isolate the level
transmitter and
rectify
Continuous filling of
Caustic product from
the drum
Stop unloading
from the drum
Malfunction of level
transmitter 91-LT1525
Verify with level
gauge 91-LG-1512.
Isolate the level
transmitter and
rectify.
Diaphragm rupture
Rectify the problem
in diaphragm
Malfunction of
pressure transmitter
91-PT-1569/91-PT1570
Rectify the problem
in pressure
transmitter
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TITLE: OPERATION AND MAINTENANCE MANUAL
Sl. #
4
9.2.5
Problem
Low flow at
injection
point
Indication
Low injection
rate
Diagnosis
Operating at low
stroke
Choke/obstruction in
suction line
NRV got struck in the
discharge line
Pump not developing
pressure
Corrective action
Increase the stroke
length
Check and rectify
Check and rectify
Check the Pump
and rectify
DM Water Package
Sl. #
Problem
1 High Pressure
drop across the
cationic bed
2
High Pressure
drop across the
cationic bed
3
High silica
content in DM
water
9.2.6
Indications
High
differential
pressure alarm
68-PDAH-1825/
68-PDAH-1830
across the bed
Diagnosis
Too many fines and
broken resins
High
differential
pressure alarm
68-PDAH-1828/
68-PDAH-1832
across the bed
Silica content
high alarm in
DM water,
68-AAH-1830
Too many fines and
broken resins
Organic matter in
fresh water feed
Control Action
Adjust flow rates for
backwash the resins
to remove fines and
broken resins
Inform Water
Treatment unit to
check
Adjust flow rates for
backwash the resins
to remove fines and
broken resins
Less caustic strength
during regeneration
Increase Caustic
strength during
regeneration
Diagnosis
Failure of Supply of
DM Water or
Condensate to steam
condensate flash
drum
Fluctuation in Steam
Flow to De-aerator,
De-aerator Level and
De-aerator Pressure.
Control Action
Check the DM water
unit and LP
Condensate system
header and
normalize the system
Tune the controller
and maintain the
steady Pressure,
Level and
Temperature as per
the design conditions
Diagnose and attend
the problem of
Oxygen Scavenger
Injection
Boiler Feed Water System
Sl. #
Problem
1 Boiler Feed
Water level low
in De-aerator
6834-A-08
2
Indications
Level low
indication in
68-LI-1302
Boiler Feed
Lab Result
Water quality is
not meeting with
design
specification
Problem in Oxygen
Scavenger Injection
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TITLE: OPERATION AND MAINTENANCE MANUAL
Sl. #
3
9.2.7
Problem
BFW header
pressure low
Indications
Pressure low
indication in
68- PI-1307
Diagnosis
Control Action
Tripping of running
Boiler Feed Water
pump
Start the standby
pump (if not started
on Auto) and line-up
as per the normal
start-up procedure.
Analyze the reason
for trip and rectify
before starting back
the pump which is
tripped.
Low level in the De
aerator.
Refer Problem No
#1.
Steam Generation Package
Sl. #
1
Problem
Leakage/Tube
rupture
Indications
Presence of
Steam at
stack outlet.
Diagnosis
High furnace
pressure 68-PI-1528
Flue gas
Temperature low
68-TI-1523
Control Action
Shutdown and
Inspect the Boiler.
Tube substitution/
Repair
Feed water flow
68-FIC-1522 and
Main steam flow
68-FI-1524
variations.
Drum level low
68-LI-1523
2
Improper
Combustion
Black smoke
appears at
stack outlet
Insufficient
Combustion Air
68-FIC-1526
Adjust the airflow
rate.
Adjust the Burner
air register, if
required.
Check the FD fan is
functioning
correctly.
3
Pulsated/
Spontaneous
Combustion
1. Flame is
not stable
2. Vibrations
in furnace
area and
Burner floor
area.
Insufficient
combustion air flow
68-FIC-1526
Adjust the airflow
rate. Adjust the
Burner air register,
if required. Check
that the FD fan is
functioning
correctly.
Insufficient draft
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TITLE: OPERATION AND MAINTENANCE MANUAL
Sl. #
4
Problem
Drum Water
Level-too high
or Low
Indications
Diagnosis
Control Action
1. Drum level
68-LI-1523
Fluctuations.
2. Feed water
flow 68-FIC1522
fluctuations
Malfunction of feed
water control loop
Check and rectify the
feed water flow and
steam flow controls.
Malfunction of feed
water system
Check and rectify the
feed water system
Leakage from piping
Check and attend
the leakages
5
Main steam flow
low
SH main
Steam flow
alarm 68-FSL1524
Main SH steam stop
valve failed in close
position or any
other struck-up.
Trip the Boiler
immediately.
Check and rectify
the problem.
6
Outlet main
steam SH steam
low
temperature
Low
temperature
alarm
68-TAH-1820
Problem in
Desuperheater feed
water control valve
68-TV-1522
Check and set the
DSH control valve in
manual mode to
close the valve if
opened fully.
Faulty Instrument
Check and rectify the
faulty Instruments
SH temperature
control failure
Check and rectify
the Instrument
control loops.
Problem in
Desuperheater feed
water control valve
68-TV-1522
Check and set the
DSH control valve in
manual mode to
open the valve if
closed
Faulty Instrument
Check and rectify
the faulty
Instruments
SH temperature
control failure
Check and rectify
the Instrument
control loops.
7
Outlet main
steam SH steam
high
temperature
High
temperature
alarm in
68-TAH-1820
8
High flue gas
temperature
High temp.
alarm
68-TAH-1523
Too much excess air
- Oxygen analyser
68-AIC-1522
Reduce the excess
air.
9
Combustion Air
Duct vibration
Vibrations/Ab
normal noises
Expansion Joint
failure
Check the expansion
joint, stop the fan
and rectify the joint
Support
damaged/failure
Check and Rectify
the support
FD fan surge
Stop the FD fan,
inspect the wind
box and refer to the
FD fan manual,
check and rectify
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TITLE: OPERATION AND MAINTENANCE MANUAL
Sl. #
10
Problem
Pipe vibration/
Water
hammering
Indications
Diagnosis
Control Action
Vibrations/ab
normal noises
Two phase flow in
pipeline.
Pipeline not
supported properly.
Open the drain
valve and drain the
water/condensate,
warm up/charge the
pipeline slowly.
Check the pipeline
supports and rectify
the problem.
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TITLE: OPERATION AND MAINTENANCE MANUAL
SECTION X
PLANNED SHUTDOWN
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TITLE: OPERATION AND MAINTENANCE MANUAL
10.1
Planned Shutdown - Process
The shutdown of the AGEU, SRU, TGTU and the Incinerator is explained below. The
shutdown of the Incinerator will only take place following the shutdown of the AGEU,
SRU and the TGTU.
The planned shutdown of the process units take place in the following sequence:
10.1.1
•
TGTU
•
SRU
•
AGEU
•
Incinerator
TGTU Shutdown
Shutdown of the TGTU will proceed as follows:
TGTU Wet Section Shutdown
The shutdown of the TGTU wet section, the DCC and Tail Gas Amine Absorber tower,
may take place before or after acid feed gases are removed and replaced with fuel gas
in the SRU Reaction Furnace burner.
It is advised to stop the flow of SRU tail gas to the TGTU wet section before acid feed
gas is removed from the SRU Reaction Furnace burner, rather than after the burner is
operating on fuel gas; this action will minimise the possibility of an upset condition
during the acid gas to fuel gas change over in the SRU Reaction Furnace burner, that
could result in high concentrations of SO2 in the process gas causing corrosion of
equipment in the TGTU wet section and degradation of the amine solution in the Tail
Gas Amine Absorber.
Shutdown of the TGTU DCC and absorber tower will proceed as follows:
•
Open Reactor Effluent Cooler process outlet gas valve 91-XV-1331 to route
Hydrogenation section process gases to the Incinerator
•
Close Reactor Effluent Cooler process outlet gas valve 91-XV-1332 to the DCC
tower
•
Continue DCC Desuperheater and cooling waters circulations until column has
cooled to near ambient temperatures, then stop pumps
•
Continue circulation of lean amine to the Tail Gas Amine Absorber for a period of
time, e.g. 30 minutes, to ensure all rich amine solution has been removed to the
Amine Regenerator for regeneration, then stop lean amine flow to the Tail Gas
Amine Absorber and stop the Tail Gas Rich Amine Pump
•
If the DCC is to be opened for inspection then:
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•
Before stopping the DCC tower top section cooling water pump, pump all possible
water from the top chimney tray to the Effluent Water Treatment
•
Pump out the bottom Desuperheater section of the DCC to the spent caustic
system
•
Through the condensate line to the cooling water pumps suction line, introduce
condensate to establish a level in the contact condenser tower top chimney tray
cooling section
•
Start a Cooling Water Recirculation Pump 9102-P-12A/B to establish water
circulation through the Contact Condenser Cooler to the top of the DCC tower
•
Open the DCC bottom level control valve 91-LV-1307 to transfer condensate from
the top cooling water system to establish a condensate level in the bottom of the
tower. Continue adding condensate via the Cooling Water Recirculation Pumps
suction line to maintain a water level in the top chimney tray
•
When a water level is established in the bottom of the DCC, start a Desuperheater
Circulation Pump 9102-P-11A/B and start circulation around the bottom of the
tower
•
Again pump out the bottom Desuperheater section to the spent caustic system
•
Sample the water whilst it is being pumped out to the spent caustic system, if the
pH of the water is near to the pH of condensate, then the Desuperheater section
has been flushed clean. Repeat filling and circulating the Desuperheater section if
further flushing is required
•
When flushed clean, drain any remaining water in the top cooling water and
bottom Desuperheating sections of the DCC tower to the drains system
•
After water washing, final cleaning and gas freeing of the DCC tower should be
carried out by steaming. The DCC process gas outlet valve to the Tail Gas Amine
Absorber is first closed and LP steam is introduced into the tower via its utility
connection.
•
The DCC tower is initially steamed to flare, via the towers PSV open bypass line,
and then to atmosphere before the steam is stopped, and air allowed to enter the
equipment. Steam out of the tower should be for a minimum of 4 hours to flare
followed by a minimum of 4 hours to atmosphere.
•
If the Tail Gas Amine Absorber is to be opened for inspection then:
•
Restart a Tail Gas Rich Amine Pump 9102-P-16A/B and pump out all amine from
the bottom of the Tail Gas Amine Absorber to the Acid Gas Amine Absorber
•
After water washing, final cleaning and gas freeing of the Tail Gas Amine Absorber
should be carried out by steaming. LP steam is introduced into the tower via its
utility connection and steamed to the Incinerator for a minimum of 8 hours
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Note: The Incinerator must be in operation when steam out of the Tail Gas Amine
Absorber is taking place.
TGTU BSR Section Shutdown
•
Stop the Sour gas from Effluent and Waste Water Treatment Unit by closing 69-PV1315A and open 69-PV-1315B to LP Acid Gas Flare.
•
Open SRU tail gas outlet valve 91-XV-1097 to route tail gas directly to the
Incinerator
•
Close SRU tail gas outlet valve 91-XV-1098 to the TGTU
•
Simultaneously while the SRU tail gas valve to the TGTU is being closed; shutdown
the RGG burner via the RGG manual shutdown switch 91-HS-1403.
•
Confirm that the action of the shutdown switch has closed or opened the following
RGG shutdown valves:
•
Nitrogen valve 91-XV-1307 to the RGG process air line is opened (valve will
remain open for ~15 minutes)
•
Nitrogen valve 91-XV-1301 to the RGG instrument nozzles is opened (valve will
remain open for ~15 minutes)
•
Instrument air valve 91-XV-1302 to the RGG instrument nozzles is closed
•
Process air valve 91-XV-1306 is closed
•
Fuel gas shutoff valves 91-XV-1303 and 91-XV-1304 is closed and vent valve
91-XV-1308 is opened
•
LP steam ON/OFF valve 91-XV-1305 is closed
•
After a set time of 15 minutes, confirm that the nitrogen purge valves to the RGG
process air line 91-XV-1307 and to the RGG instrument nozzles 91-XV-1301 have
closed.
•
Close manual valves in the RGG process air, instrument air, fuel gas and LP steam
lines to the RGG.
•
The TGTU BSR section and hydrogenation reactor may then be left to cool
naturally until a re-start is required.
•
Observe the Reactor Effluent Cooler steam side pressure after unit shutdown and
open the vessel’s steam side vent valve when steam side pressure falls to
<1.0 barg to avoid a vacuum being formed in the vessel.
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10.1.2
SRU Shutdown
Shutdown of the SRU will proceed as follows:
•
If time permits, prior to reducing acid feed gas to the SRU it is advised that the
SRU converters catalyst beds undergo a rejuvenation exercise, refer to Section
12.4.5.
•
Reduce acid gas feed to the SRU Reaction Furnace to the unit minimum design
flow of 6628 kg/hr, (2169 am3/hr)
When acid gas feed flows to the SRU reaction furnace burner are at the unit’s
minimum:
•
Open SRU tail gas line valve 91-XV-1097 to the Incinerator
•
Close SRU tail gas line valve 91-XV-1098 to the TGTU
•
Confirm process air and acid gas controllers are in automatic operating mode
•
Switch acid gas to the Reaction Furnace Control valve 91-PV-1503B to manual
operating mode and slowly reduce acid gas to the SRU Reaction Furnace
•
Switch trim air controller 91-FIC-1003 to manual mode and close trim air control
valve.
•
Confirm the stoichiometric air requirements for the fuel gas
•
Confirming the fuel gas shutdown valves are open, in manual operating mode,
slowly open fuel gas control valve 91-FV-1009 to introduce fuel gas to the SRU
Reaction Furnace burner to replace the acid gas.
•
Observe adjustment of the process air flow as fuel gas flow to the Reaction
Furnace burner increases.
•
Simultaneously whilst increasing fuel gas flow 91-FT-1009, decrease acid gas flow
91-FI-1001 to the reaction furnace burner to ensure the fuel gas is being burned at
slightly substoichiometric firing conditions.
•
Simultaneously switch 1st Stage Auxiliary Burner and 2nd Stage Auxiliary Burner
from acid gas to fuel gas
•
When acid gas flow has stopped close manual valve in acid gas line to Reaction
Furnace burner.
•
Close MS steam to the Acid Gas Pre-heater
•
Observe adjustment of the process air as fuel gas flow to the Reaction Furnace
burner increases and acid gas flow decreases.
•
Introduce LP steam to the fuel gas line through 91-XV-1079 to prevent soot being
formed at sub-stoichiometric firing conditions. Set steam controller to control the
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steam flow at a ratio to natural gas of 1:1 (by wt). Before opening steam valves
ensure steam lines are fully drained of condensate.
•
Introduce LP steam to the burner process air line through 91-XV-1078 to moderate
the furnace temperature and prevent overheating of the furnace refractory. Note
that the furnace temperature will dictate the amount of steam used, too much
steam could result in interference of the burners flame detectors sensing the
flame resulting in a burner trip. Before opening steam valves ensure steam lines
are fully drained of condensate.
•
Continue operating the SRU Reaction Furnace burner in slightly sub-stoichiometric
firing conditions to produce a hot inert flow of combustion gas through the unit to
sweep all possible sulphur from the SRU converters catalyst beds. Continue this
operation until the flow of sulphur is seen to have stopped from all sulphur
condenser seals.
•
When all possible sulphur has been removed from the SRU converters, if the intent
is not to open the SRU to carry out maintenance, then shutdown the unit via its
emergency stop switch.
If the SRU is not to be opened for a maintenance overhaul then a catalyst sulphur
stripping exercise is not required and the shutdown of the unit can proceed as follows:
•
Close MS steam to the process air pre-heater
•
Through the SRU shutdown switch 91-HS-1213 from LCP, shutdown the unit
•
Confirm that action of the shutdown switch has closed or opened the following
shutdown valves to the reaction furnace burner:
•
Acid gas valve 91-XV-1102 to reaction furnace is closed
•
Fuel gas shutoff valves 91-XV-1099 & 91-XV-1048 are closed and vent valve
91-XV-1100 is opened.
•
Combustion air to reaction furnace valve 91-XV-1101 is closed
•
Nitrogen valve 91-XV-1127 to the process air line, open (valve will remain open
for ~15 minutes)
•
Nitrogen valve 91-XV-1110 to burner instrument nozzles, open (valve will
remain open for ~15 minutes)
•
Purge air to burner instrument nozzles, closed
•
LP steam valve 91-XV-1078 is closed
•
After a set time of 15 minutes, confirm that the nitrogen purge valves to the
Reaction Furnace process air line and to the Reaction Furnace burner instrument
nozzles have closed
•
SRU may then be left to cool naturally until a re-start is required
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•
Close manual valves in the process air, instrument air, fuel gas, acid gas and LP
steam lines to the reaction furnace
•
Observe all steam generators steam side pressures after unit shutdown. When
pressures have decayed to <1.0 barg on the steam side of the WHB, condensers
and reactor effluent cooler, open atmospheric vents to prevent a vacuum being
formed in the vessels
•
The SRU may then be left to cool naturally until a re-start is required
•
If the intent is to open the unit to carry out an internal inspection and
maintenance then a sulphur stripping/regeneration exercise will first have to be
carried out to remove all hazardous sulphur compounds from the unit, refer to
Section 12.4.6
10.1.3
Acid Gas Enrichment Unit Shutdown
The unit shutdown is performed as detailed below:
•
Inform NGL-1, 2 & 3 to slowly reduce the acid gas feed to AGEU to the unit
turndown flow of 12241 kg/hr
When the acid gas feed is at the turndown flow:
•
Close acid gas to Acid Gas KO Drum by closing 91-PV-1503B manually
•
Open 91-PV-1503A and send the acid gas to LP Acid Gas Flare
•
Inform NGL-1, 2 & 3 to fully stop the acid gas feed to AGEU
•
Close the acid gas feed to amine absorber by closing the inlet block valve
•
Close the treated gas outlet from Acid Gas Amine Absorber 9103-C-11 to
Incinerator pressure control valve 91-PV-1502 and the upstream and downstream
isolation valves.
•
The amine solution is to be circulated until the solution is completely
regenerated. Take samples from Amine Regenerator bottom and confirm.
•
When the solution is completely regenerated, slowly close the LP Steam to
Regenerator Reboiler 9103-E-13 by closing the inlet flow control valve 91-FV-1503.
•
Close the condensate outlet from Regenerator Reboiler Condensate Pot 9103-V-13
and open the pot vent to avoid pulling vacuum when the pressure is reduced.
•
Stop the Regenerator Reflux drum pumps 9103-P-11A/B when the level in the
Regenerator Reflux Drum 9103-V-12 reaches low and close the discharge isolation
valves.
•
Open 91-PV-1539 to supply nitrogen to the Amine Regenerator.
•
Continue MDEA circulation till the solution is cooled down.
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•
Slowly reduce the amine circulation rate and stop the Lean Amine Pumps 9103-P13A/B.
•
Stop Rich Amine Pumps 9103-P-12A/B and Hot Lean Amine Pumps 9103-P-17A/B
after transferring the solution to the Amine Surge Tank 9103-T-11.
•
Stop Regenerator Condenser Cooler 9103-E-12 fans and Lean Amine Cooler 9103-E14 fans.
•
Drain the MDEA solution from Acid Gas Amine Absorber 9103-C-11 through the Acid
Gas Rich Amine Pumps casing drain to the Amine Sump 9103-V-10 and transfer the
solution from the Amine Sump to the Amine Surge Tank 9103-T-11
•
Drain the Lean/Rich Amine Exchanger 9103-E-11A/B by opening the drains on the
Lean and Rich amine side to the Amine Sump 9103-V-10 and transfer the solution
from the Amine Sump to the Amine Surge Tank 9103-T-11
•
Drain the Amine Regenerator 9103-C-12 through the Hot Lean Amine Pumps 9103P-17A/B casing drain to the Amine Sump 9103-V-10 and transfer the solution from
the Amine Sump to the Amine Surge Tank 9103-T-11
•
Drain the solution from the Regenerator Condenser Cooler 9103-E-12 and
Regenerator Condenser Trim Cooler 9103-E-16 by draining through the upstream
and downstream drain valves of 91-TV-1502 to the Amine Sump 9103-V-10 and
transfer the solution from the Amine Sump to the Amine Surge Tank 9103-T-11
•
Drain the Regenerator Reboiler through the vessel drains to the Amine Sump
9103-V-10 and transfer the solution from the Amine Sump to the Amine Surge Tank
9103-T-11
•
Drain the Lean Amine Cooler and Lean Amine Trim Cooler through the drains to
the Amine Sump 9103-V-10 and transfer the solution from the Amine Sump to the
Amine Surge Tank 9103-T-11
•
Drain the Lean Amine Filters through the drains to the Amine Sump 9103-V-10 and
transfer the solution from the Amine Sump to the Amine Surge Tank 9103-T-11
•
Depressurise the system by opening the vents to flare
•
Steam out of the unit has to be carried out for vessel entry
10.1.4
Incinerator Shutdown
The Incinerator will only be shutdown following the shutdown of the TGTU, SRU and
AGEU. The shutdown of the unit may proceed as follows:
Confirm that all process gases from the upstream AGEU, SRU and TGTU have stopped
and that the following process gas valves to the incinerator are isolated:
•
Treated vent gas line from the Acid Gas Amine Absorber is blind isolated
•
Treated vent gas line from the Tail Gas Amine Absorber is blind isolated
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•
SRU tail gas line valve 91-XV-1097
•
TGTU Reactor Effluent Cooler outlet process gas valve 91-XV-1331
•
TGTU wet section start-up vent gas valve
•
Sulphur Degassing Pit ejector vent gases
If the incinerator is not to be opened for inspection, then:
•
Press the Incinerator emergency shutdown switch 91-HS-1167 in LCP to shutdown
the unit.
•
An emergency shutdown will cause all valves to revert to their fail safe positions.
The valve positions are as follows:
•
Fuel gas control valve 91-FV-1155 at low fire position
•
Fuel gas upstream block valve 91-XV-1155 in close position
•
Fuel gas vent valve 91-XV-1156 in open position
•
Fuel gas downstream block valve 91-XV-1157 in close position
•
Pilot gas upstream block valve 91-XV-1158 in close position
•
Pilot gas vent valve 91-XV-1159 in open position
•
Fuel gas downstream block valve 91-XV-1160 in close position
•
After 15 minutes air supply valve 91-XV-1161 is closed
Note: Local ESD pushbutton 91-HS-1167 and remote ESD signal shutdown the blower’s
9101-K-12A/B directly.
If the Incinerator is to be opened for inspection, then it should be slowly cooled to
protect its refractory from shock cooling as follows:
•
Place the temperature controller 91-TIC-1155 to “Manual mode”
•
slowly reduce, at an advised rate (e.g. 50°C/hr), the Incinerator combustion
chamber temperature by reducing fuel gas flow to the burner until the burner is at
its minimum turndown and the combustion chamber is at as low a temperature as
possible before stopping fuel gas to the burner
•
At 250°C, stop the combustion by pressing Normal stop pushbutton “91-HS-1166”
on LCP
•
Following are the sequence of action when stop pushbutton is activated:
•
A 5 minute timer is started
•
Fuel gas control valve 91-FV-1155 at low fire position
•
Fuel gas upstream block valve 91-XV-1155 in close position
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10.2
•
Fuel gas vent valve 91-XV-1156 in open position
•
Fuel gas downstream block valve 91-XV-1157 in close position
•
Pilot gas upstream block valve 91-XV-1158 in close position
•
Pilot gas vent valve 91-XV-1159 in open position
•
Fuel gas downstream block valve 91-XV-1160 in close position
•
Continue operating the Incinerator Air Blower to cool the unit by combustion air
until as near to ambient temperatures as possible are seen in the combustion
chamber and stack; after 5 minutes, pilot and purge air supply valve 91-XV-1161 is
closed and then stop the Incinerator Air Blower 9101-K-12A/B manually
•
Blind isolate the unit for in readiness for opening and inspection
UTILITIES
10.2.1
Steam Generation Package Shutdown
The shutdown sequence of the boiler 6848-A-02A is as follows:
•
Before stopping the boiler increase the blow down rate to remove as much
sediments as possible
•
Reduce the boiler load to 75%
•
Reduce the firing rate gradually to its minimum
•
Reduce the boiler load to 20%, by taking all boiler controls in manual
•
Start to open the start-up vent valve 68-PV-1523 until the steam drum pressure
begins to decrease
•
Close the 68-MOV-1522 to stop the steam supply to the header
•
Stop the burner by pressing the normal stop push button 68-HSC-1527 in local
boiler panel
Following are the sequence in BMS when burner stop pushbutton is pressed:
•
Pilot burner vent valve 68-XV-1533 opens
•
Pilot burner shutoff valves 68-XV-1531 and 68-XV-1532 closes
•
Main burner vent valve 68-XV-1530 opens
•
Main burner shutoff valves 68-XV-1528 and 68-XV-1529 closes
•
Close the start-up vent valve 68-PV-1523
Following is the post purge sequence executed by BMS in boiler:
•
BMS sets the air purge request and post purge in progress signal
•
Combustion air flow damper (68-FV-1526) will be opened to threshold limit
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•
Ensure the presence of 68-FZSO-1526 limit switch
•
After 1 minute delay if the flue gases recirculation controller is enabled then BMS
will set flue gas purge request and BCS will open the recirculation damper (68-FV1524)
•
After receiving the 68-FV-1524 open feedback BMS sets flue gas purge in progress
signal
•
After 30 seconds BMS resets post-purge in progress, air purge request signal, air
purge in progress and flue gas purge request and flue gas purge in progress signal
•
BMS sets the flue gas purge end and air purge end signal
•
Stop the Forced Draft Fan 6848-K-02A and Flue Gas Recirculation Fan 6848-K-03A
•
Allow the boiler to cool down and monitor the drum pressure via 68-PI-1523
•
When Drum Pressure reaches 1.5- 2.0 barg, open the saturated steam vent valves
•
Cool down the unit naturally until the ambient temperature is reached
•
Close the Boiler feed water control valve 68-LV-1522
•
Drain the Boiler with the drum vent valves in open position
•
Isolate the other utility pipelines
Follow the same sequence for stopping of another running boiler.
10.2.2
Boiler Feed Water System Shutdown
During Planned Shutdown of Boiler Feed Water system, the scheduled maintenance
activity on Deaerator, Boiler Feed Water Pumps, chemical Injection Pumps and the
auxiliary equipment can be carried out as per company maintenance schedule. Other
maintenance activity that may be carried out includes checking of PSV and calibration
of instruments, etc.
Jobs like Deaerator Internal work, equipment overhauls will be planned in long
Shutdown. But in case if the Deaerator internal work is not planned during long
Shutdowns, preservation procedures as per the company procedure has to be followed.
Get clearance from all process units before taking the shutdown of the Boiler Feed
Water System.
Ensure steam generation units are stopped, before taking shutdown of boiler feed
Water system.
Following steps are to be followed for shutdown of Boiler Feed Water System:
•
Stop Oxygen Scavenger injection to Deaerator package 6834-A-08
•
Stop the boiler feed water Pumps 6834-P-22 A/B/C and close the pump suction &
discharge valves.
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10.2.3
•
Stop the Deaerator Feed Pumps 6834-P-20A/B
•
Isolate the LP saturated steam to Deaerator vessel by taking 68-PIC-1304 in
manual and close the control valve 68-PV-1304
•
Isolate the DM Water supply to Steam Condensate Flash Drum 6834-V-05.
•
Isolate the LP Condensate supply to Steam Condensate Flash Drum 6834-V-05
•
Isolate the steam condensate from Steam Condensate Coolers 6834-E-02 by taking
68-TIC-1301 in manual and close the control valve 68-TV-1301
•
Ensure Deaerator Feed Pumps recirculation flow controller 68-FIC-1301 is in
manual and the steam condensate to flash drum minimum flow control valve
68-FV-1301 is fully closed.
•
Stop all the running Steam Condensate Cooler Fans 6834-E-02.
DM water package Shutdown
During Planned Shutdown of DM Water system, the scheduled maintenance activity on
anionic, cationic Exchanger and the auxiliary equipment can be carried out as per
company maintenance schedule. Other maintenance activity that may be carried out
includes checking of PSV, calibration of instruments, cleaning of filters and
replacement of resin, etc.
Jobs like Resin replacement, Equipment overhauls will be planned in this Long
Shutdown. But in case if the resin replacement is not planned during Long Shutdowns,
Preservation procedures as per the vendor has to be followed. For details of these
preservation procedures refer the Vendor Operation and Maintenance Manual.
To stop the DM water train, place the respective AUTO/MAN/OFF selector in OFF
position.
When OFF mode is selected, all valves involved in the respective sequence is closed,
phase duration timers are stopped at the current status, and the sequence is ‘freeze’
in the current phase, with all outputs inhibited.
The procedure for normal shutdown of DM Water Package unit is given below:
1. Get clearance from all process units before taking the shutdown of the DM Water
System.
2. Isolate the fresh Water supply to both the trains.
3. If the regeneration is in progress in one of the train continue regeneration and stop
the train after the completion of regeneration by placing the respective AUTO/
MAN/OFF selector in OFF position.
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4. Select the train which is in online to manual, use the step advance button to start
the regeneration and after completion of regeneration, stop the train by placing
the respective AUTO/MAN/OFF selector in OFF position.
5. Isolate the product DM Water to DM Water Storage Tank.
6. If the Resins are to be preserved for a long time, follow the Preservation
procedures as given in the Vendors Manual.
7. Based on the requirement, isolate and hand over the equipments as per the
equipment hand over procedure.
10.2.4
Chemical Injection System Shutdown
a.
Antifoam Injection Package 9103-A-11
Antifoam Injection System shutdown is carried out as described below:
•
Stop the Antifoam Injection Pumps 9103-P-16A/B from LCP
•
Stop the Antifoam Tank Agitator in the Antifoam Storage Tank
•
Close the isolation valve at the Antifoam Storage Tank outlet to the suction of the
pumps
•
Close the suction and discharge isolation valves of the Antifoam Injection Pumps
•
Close the Antifoam injection line isolation valve at the injection point
•
Drain the Antifoam from the lines and the pumps to the drain pit and flush the
lines with water and deenergise the pumps if required for any maintenance.
•
If the Antifoam Storage Tank has to be handed over for maintenance, then the
tank level has to be reduced to the level possible before stopping the Injection
pumps. The tank has to be drained fully to the drain pit and washed thoroughly
with water.
b.
Caustic Injection Package 9103-A-13
Caustic Injection System shutdown is carried out as described below:
•
Stop the Caustic Injection Pumps 9103-P-103A/B from LCP
•
Stop the Caustic Tank Agitator in the Caustic Storage Tank
•
Close the isolation valve at the Caustic Storage Tank outlet to the suction of the
pumps
•
Close the suction and discharge isolation valves of the Caustic Injection Pumps
•
Close the Caustic injection line isolation valve at the injection point
•
Drain the Caustic from the lines and the pumps to the drain pit and flush the lines
with water and deenergise the pumps if required for any maintenance.
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•
c.
If the Caustic Storage Tank has to be handed over for maintenance, then the tank
level has to be reduced to the level possible before stopping the Injection pumps.
The tank has to be drained fully to the drain pit and washed thoroughly with
water.
Corrosion Inhibitor Injection Package 9103-A-12
Corrosion Inhibitor Injection System shutdown is carried out as described below:
•
Stop the Corrosion Inhibitor Injection Pumps 9103-P-101A/B from LCP
•
Stop the Corrosion Inhibitor Tank Agitator in the Corrosion Inhibitor Storage Tank
•
Close the isolation valve at the Corrosion Inhibitor Storage Tank outlet to the
suction of the pumps
•
Close the suction and discharge isolation valves of the Corrosion Inhibitor Injection
Pumps
•
Close the Corrosion Inhibitor injection line isolation valve at the injection point
•
Drain the Corrosion Inhibitor from the lines and the pumps to the drain pit and
flush the lines with water and deenergise the pumps if required for any
maintenance.
•
If the Corrosion Inhibitor Storage Tank has to be handed over for maintenance,
then the tank level has to be reduced to the level possible before stopping the
Injection pumps. The tank has to be drained fully to the drain pit and washed
thoroughly with water.
d.
Complex Product Injection Package 6834-A-09
Complex Product Injection System shutdown is carried out as described below:
•
Stop the Complex Product Injection Pumps 6834-P-41A/B from LCP
•
Stop the Complex Product Tank Agitator in the Complex Product Storage Tank
•
Close the isolation valve at the Complex Product Storage Tank outlet to the
suction of the pumps
•
Close the suction and discharge isolation valves of the Complex Product Injection
Pumps
•
Close the Complex Product injection line isolation valve at the injection point
•
Drain the Complex Product from the lines and the pumps to the drain pit and flush
the lines with water and deenergise the pumps if required for any maintenance.
•
If the Complex Product Storage Tank has to be handed over for maintenance, then
the tank level has to be reduced to the level possible before stopping the Injection
pumps. The tank has to be drained fully to the drain pit and washed thoroughly
with water.
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e.
Oxygen Scavenger Injection Package 6834-A-09
Oxygen Scavenger Injection System shutdown is carried out as described below:
•
Stop the Oxygen Scavenger Injection Pumps 6834-P-39A/B from LCP
•
Stop the Oxygen Scavenger Tank Agitator in the Oxygen Scavenger Storage Tank
•
Close the isolation valve at the Oxygen Scavenger Storage Tank outlet to the
suction of the pumps
•
Close the suction and discharge isolation valves of the Oxygen Scavenger Injection
Pumps
•
Close the Oxygen Scavenger injection line isolation valve at the injection point
•
Drain the Oxygen Scavenger from the lines and the pumps to the drain pit and
flush the lines with water and deenergise the pumps if required for any
maintenance.
•
If the Oxygen Scavenger Storage Tank has to be handed over for maintenance,
then the tank level has to be reduced to the level possible before stopping the
Injection pumps. The tank has to be drained fully to the drain pit and washed
thoroughly with water.
f.
Biocide Injection Package 6932-A-06
Biocide Injection System shutdown is carried out as described below:
•
Stop the Biocide Injection Pumps 6932-P-07A/B from LCP
•
Close the isolation valve at the Biocide Storage Tank outlet to the suction of the
pumps
•
Close the suction and discharge isolation valves of the Biocide Injection Pumps
•
Close the Biocide injection line isolation valve at the injection point
•
Drain the Biocide from the lines and the pumps to the drain pit and flush the lines
with water and deenergise the pumps if required for any maintenance.
•
If the Biocide Storage Tank has to be handed over for maintenance, then the tank
level has to be reduced to the level possible before stopping the Injection pumps.
The tank has to be drained fully to the drain pit and washed thoroughly with
water.
g.
Scale Inhibitor Injection Package 6932-A-07
Scale Inhibitor Injection System shutdown is carried out as described below:
•
Stop the Scale Inhibitor Injection Pumps 6932-P-09A/B from LCP
•
Close the isolation valve at the Scale Inhibitor Storage Tank outlet to the suction
of the pumps
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•
Close the suction and discharge isolation valves of the Scale Inhibitor Injection
Pumps
•
Close the Scale Inhibitor injection line isolation valve at the injection point
•
Drain the Scale Inhibitor from the lines and the pumps to the drain pit and flush
the lines with water and deenergise the pumps if required for any maintenance.
•
If the Scale Inhibitor Storage Tank has to be handed over for maintenance, then
the tank level has to be reduced to the level possible before stopping the Injection
pumps. The tank has to be drained fully to the drain pit and washed thoroughly
with water.
h.
Catalyst Injection Package 9101-A-01
Catalyst Injection System shutdown is carried out as described below:
•
Stop the Catalyst Injection Pumps 9101-P-11A/B from LCP
•
Close the isolation valve at the Catalyst Storage Tank outlet to the suction of the
pumps
•
Close the suction and discharge isolation valves of the Catalyst Injection Pumps
•
Close the Catalyst injection line isolation valve at the injection point
•
Drain the Catalyst from the lines and the pumps to the drain pit and flush the lines
with water and de-energise the pumps if required for any maintenance.
•
If the Catalyst Storage Tank has to be handed over for maintenance, then the tank
level has to be reduced to the level possible before stopping the Injection pumps.
The tank has to be drained fully to the drain pit and washed thoroughly with
water.
10.2.5
Electro Chlorination Package Shutdown
•
The plant is stopped in a controlled manner by operating the system stop
pushbutton on the HMI.
•
If the plant is in remote control mode then a stop signal from the DCS will initiate
the controlled shutdown.
•
Following are the sequence events in controlled shutdown:
•
Give stop command
•
System shutdown sequence flag shown
•
Duty transformer/Rectifiers 6932-RC-101A/B are de-energised to 0 amps.
•
After a 1 minute delay:
•
The duty Sea Cooling Water Pump 6932-P-04 A/B is stopped
•
The Auto Back Wash Filter 6932-S-03A cycle operation completes the backwash
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10.2.6
•
After 5 minutes of time delay duty Hydrogen Dilution Blower 6932-K-01A/B is
stopped
•
The duty Continuous Chlorination Pump/Shock Chlorination Pump 6932-P05A/B is stopped
•
All actuated valves will close
•
The system Stop is indicated
Sea cooling water Shutdown
The shutdown of the Sea Cooling Water Pumps 6932-P-04A/B will proceed as follows:
•
Ensure that the Electro Chlorination Package is already stopped
•
Close the outlet valve and ensure that the pump runs in this condition for no more
than a few seconds
•
Stop the Sea Cooling Water Pumps 6932-P-04A/B
•
Close the flushing/cooling fluid supply at a time appropriate to the process
•
For prolonged shutdowns and especially when ambient temperatures are likely to
drop below freezing point, the pump and the cooling and flushing arrangements to
be drained.
10.2.7
Fuel Gas system Shutdown
Shutdown of the fuel gas system is carried out as described below:
•
Ensure that there is no requirement for fuel gas from the New Steam Boiler
Package 6848-A-02A/B/C
•
Ensure that the Boiler Package 6848-A-02A/B/C fuel gas inlet XVs 68-XV-1302,
68-XV-1303 & 68-XV-1304 and the isolation valves are closed
•
Isolate the backup fuel gas supply from 6103-K-01A/B by closing the isolation
valves of 62-PV-1301B
•
Isolate the backup fuel gas supply from 30” existing line by closing the isolation
valves of 62-PV-1302
•
Close the fuel gas supply from first stage Booster Compressor 6701-K-10/20/30 by
closing the isolation valves of 62-PV-1301A
•
Open 62-PV-1303 to LP Flare Header and depressurise the system
•
Open the drain valves of the LP Fuel gas KO Drum and drain the liquids to the LP
Flare Header
•
Purge the Fuel gas system with nitrogen to reduce the HC content to 0% LEL and
depressurise the system
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•
Reverse to close the spectacle blinds on the fuel gas lines from Booster
Compressor 6701-K-10/20/30 upstream of 62-XV-1301, spectacle blind on the back
up fuel gas supply from 6103-K-01A/B upstream of 62-XV-1302 and spectacle blind
on the back up fuel gas supply from 30” existing line upstream of 62-XV-1303
•
Reverse to close the spectacle blinds on the fuel gas lines to the New Steam Boiler
Package 6848-A-02A/B/C upstream of XV-1302/XV-1303/XV-1304
•
The fuel gas system is to be preserved under nitrogen till maintenance activities
are taken up.
10.2.8
Effluent & Waste Water Unit Shutdown
The Effluent & Waste Water Unit shutdown is carried out in the following steps:
•
Slowly reduce the waste water feed to the Waste Water Degasser 6922-V-07 and
stop the flow from the upstream units
•
Close 69-PV-1315A and open 69-PV-1315B and send the sour gas from Sour Water
Stripper to LP Acid Gas Flare Header
•
Gradually reduce the level in the Waste Water Degasser 6922-V-07 by pumping the
waste water to the Sour Water Stripper.
•
Stop Waste Water Degasser Pumps 6922-08A/B
•
Stop the Stripper Overheads Circulation Pump 6922-P-11A/B
•
Reduce the steam flow to the Sour Water Stripper Reboiler and fully close 69-FV1315
•
Close the Reboiler Condensate Drum 6922-V-09 level control valve 69-LV-1327 and
open vent in the drum when the pressure reaches 1.0 barg
•
Reduce the level in the Sour Water Stripper 6922-C-01 and stop the Stripped Water
Pump 6922-P-10 A/B when the level is low
•
Stop the Stripper Overheads Cooler 6922-E-03 fans and the Stripped Water Cooler
6922-E-02 fans
•
Close 69-PV-1307 and stop the nitrogen supply to the Waste Water Degasser
6922-V-07
•
Drain the Waste Water Degasser 6922-V-07 to the waste water distribution header
through the Waste Water Degasser Pumps 6922-P-08A/B casing drains
•
Drain the Sour Water Filter 6922-S-06 to the waste water distribution header
•
Drain the Sour/Stripped Water Exchanger 6922-E-01 to the waste water
distribution header
•
Drain the Sour Water Stripper 6922-C-01 to the waste water distribution header
through the bottom drain
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10.2.9
•
Drain the Stripped Water Pumps 6922-P-10A/B to the waste water distribution
header through the casing drain
•
Drain the Stripper Overhead Circulation Pumps 6922-P-11A/B to the waste water
distribution header through the casing drain
•
Drain the Sour Water Stripper Reboiler 6922-E-04A/B to the waste water
distribution header through the low point drain
•
Drain the Stripper Overheads Cooler 6922-E-03 and Stripped Water Cooler 6922-E02 to the waste water distribution header through the low point drain
•
Depressurise the system to LP Acid Gas Flare Header
•
Steam out of the system is necessary to carry out maintenance activities.
Instrument air Shutdown
10.2.9.1 Shutdown of Instrument Air Compressor
The Instrument Air Compressor is normally kept in ‘Remote-Auto’ mode during normal
operation. Hence, depending on the demand of instrument air, the Compressor will get
stopped automatically.
Auto Stop
In Remote mode, if the Compressor runs unloaded for a period of time (maximum 20
minutes idling delay), the Compressor gets stopped. The Compressor will restart only
when the air is required.
Compressor Manual stop
A compressor can be taken for planned shutdown after ensuring the healthiness of
Stand-by Compressor
In remote mode compressor can be stopped by the operator from ICSS/UCP. In local
mode Compressor can be stopped by pressing the ‘STOP’ pushbutton in Local Control
Panel.
The following steps to be followed for stopping the Compressor 6837-K-02A from LCP:
1. Turn the selector switch 68-HS-1403 to Local position in LCP.
2. Initiate the stop command (68-HSCA-1415) from LCP.
3. Confirm the Compressor 6837-K-02A gets unloaded by de-energizing both SOV’s.
4. After 10 seconds main motor and the fan cooler motors will be stopped.
Note: Follow the above steps for shutdown of Instrument Air Compressor 6837-K-02B.
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10.2.9.2 Planned Shutdown of Dryer Package
The Dryer Package can be taken planned shutdown for carrying out the scheduled
maintenance activities like cleaning of Filters, replacement of desiccant, calibration of
instruments, servicing of ON-OFF valves may be carried out as per QP maintenance
schedule.
The following steps are to be followed for shutdown of the Instrument Air Dryer
Package (Train – A) and release for maintenance:
•
Initiate ‘STOP’ command 68-HSCA-1408 from DCS/UCP after completion of drying
cycle
Note: The dryer will stop after completion of the present cycle. The command
de-energises the purge solenoids to close the purge valves 68-XV-1416 & 68-XV-1417.
•
Ensure that inlet 68-XV-1418 & 68-XV-1419 is closed
•
Close the manual isolation valves 68-BV-2236 & 68-BV-2238 at the upstream of
Pre-Filters 6837-S07A/B
•
Close the manual isolation valves 68-BV-2249 & 68-BV-2251 at the outlet of After
Filter 6837-S08A/B
•
Open the condensate drain valves of Pre-Filters 6837-S-07A/B
•
Depressurise the system by opening the vent valves
Note: Follow the above procedure for shutdown of Instrument Air Dryer Package
(Train-B).
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TITLE: OPERATION AND MAINTENANCE MANUAL
SECTION XI
EMERGENCY SHUTDOWN
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11.1
GENERAL
In general, Emergency Shutdowns (ESD) causes the affected equipment to be blocked
in and isolated from other systems, or process areas, where upset conditions have not
occurred. ESD system is designed to implement safe and dependable emergency
shutdown of the process and utility systems, and their associated equipment in order
to prevent the development of a hazardous condition, which may be caused by a
process upset or by an external event. The operator can manually initiate emergency
shutdown when required or in response to external events such as fire and gas
detection.
The ESD System is designed to achieve the following objectives listed in order of
priority:
•
Protection of personnel (highest priority)
•
Protection of equipment
•
Protection of the environment
•
Continuity of production (by minimizing spurious shutdowns)
The ESD system in SRU Upgrade is divided into five shutdown levels:
1.
ESD Level 0 Shutdown- Total Plant Shutdown with depressurization.
2.
ESD Level 1 Shutdown - Shutdown with Depressurization to safe level.
3.
ESD Level 2 Shutdown - Shutdown without depressurization (manual depressurization
is allowed).
4.
ESD level 3-Process system/subsystem shutdown without depressurization.
5.
ESD level 4-Individual equipment system shutdown without depressurization.
Emergency shutdown, which can occur in the unit, must be recognized and acted upon
immediately.
In case of activation of any one unit ESD, the activated ESD performs the other unit
shutdown, according to the sequence given in Cause & Effect Matrix & P&ID.
ESD Level 0 Shutdown
ESD level-0 shutdown is a total plant shutdown which includes a number of related
level 3 unit/sub unit/zones which can also be shutdown on an individual basis with
depressurization.
ESD Level 1 Shutdown
ESD level-1 shutdown includes a number of related level 3 unit/sub-unit/zones which
can also be shutdown on an individual basis with depressurization to safe level.
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ESD Level 2 Shutdown
ESD level-2 shutdown includes a number of related level 3 unit/sub-unit/zones which
can also be shutdown on an individual basis without depressurization, but permissive
for manual depressurization is available.
ESD Level 3 Shutdown
This level of shutdown is without depressurization, which normally protects a
complete process unit. A system or subsystem shutdown typically comprise of a
process system, such as TGTU or a RGG package.
ESD Level 4 Shutdown
This is the lowest level of shutdown, without depressurization and involves shutdown
of an individual piece of equipment or a zone, which is immediately affected by an
upset condition, but not affecting other equipment or zones.
ESD Zones
The SRU safeguarding based on ESD Zone is defined as below:
Process:
•
Acid Gas Enrichment Unit
•
Sulphur Recovery Unit
•
TGTU
•
Incinerator
Utilities:
•
Steam Generation System
•
Boiler Feed Water System
•
DM Water System
•
Chemical Injection System
•
Electro Chlorination System
•
Sea Cooling Water System
•
Fuel Gas System
•
Effluent and Waste Water System
•
Instrument Air Compressor
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11.2
PROCESS
11.2.1
Acid Gas Enrichment Unit
Equipments in this ESD Zone are as follows:
•
Acid Gas Coolers (9103-E-101A/B)
•
Lean Acid Gas KO Drum (9103-V-14)
•
Acid Gas Amine Absorber (9103-C-11)
•
Acid Gas KO Drum Return Pumps (9103-P-14 A/B)
•
Acid Gas Rich Amine Pumps (9103-P-12A/B)
•
Lean/Rich Amine Exchanger (9103-E-11A/B)
•
Amine Regenerator (9103-C-12)
•
Hot Lean Amine Pumps (9103-P-17A/B)
•
Regenerator Condenser Coolers (9103-E-12)
•
Regenerator Condenser Trim Cooler (9103-E-16)
•
Regenerator Reflux Drum (9103-V-12)
•
Regenerator Reflux Drum Pumps (9103-P-11A/B)
•
Regenerator Re-Boiler Condensate Pot 9103-V-13)
•
Regenerator Re-Boiler (9103-E-13)
•
Lean Amine Cooler (9103-E-14)
•
Lean Amine Trim Cooler (9103-E-15)
•
Amine Surge Tank (9103-T-11)
•
Lean Amine Pumps (9103-P-13A/B)
•
Lean Amine Filter (9103-S-11)
•
Activated Carbon Filter (9103-S-12)
•
Fines Filter (9103-S-13)
•
Amine Sump (9103-V-10)
•
Amine Sump Pump (9103-P-15)
•
Amine Sump Filter (9103-S-14)
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11.2.1.1 ESD Level-0 Shutdown in Acid Gas Enrichment Unit
ESD Level-0 is activated only by pressing emergency pushbutton 65-HS-4001 in CCR.
Following are the effects of ESD Level-0 Shutdowns in AGEU:
•
Acid gas ON/OFF valve 91-XV-1502 to flare opens
•
Acid gas ON/OFF valve 91-XV-1501 to 9103-E-101 closes
•
Acid Gas KO Drum Return Pumps 9103-P-14A/B trips
•
Liquid from Acid Gas KO Drum Return Pump ON/OFF valve 91-XV-1503 closes
•
Acid Gas Rich Amine Pump 9103-P-12A/B trips
•
Lean amine valve 91-XV-1504 to acid gas amine absorber closes
•
Hot Lean Amine Pumps 9103-P-17A/B trips
•
Hot lean amine valve 91-XV-1507 to Lean/Rich Exchanger closes
•
Regenerator Reflux Drum Pumps 9103-P-11A/B trips
•
DM water valve 91-XV-1517 to Regenerator Reflux Drum closes
•
Acid gas from Regenerator Reflux Drum ON/OFF valve 91-XV-1516 to SRU closes
•
Regenerator Reboiler steam valve 91-XV-1505 closes
•
Tail Gas Rich Amine Pumps 9102-P-16A/B trips
•
Lean amine to Tail Gas Amine Absorber valve 91-XV-1310 closes
•
Tail gas rich amine valve from Tail Gas Rich Amine Pump discharge 91-XV-1309
closes
•
Lean Amine Pumps 9103-P-13A/B trips
•
Amine sump pump 9103-P-15 trips
•
Acid gas drain outlet valve 91-XV-1109 from pipe separator closes.
•
Regenerator condenser cooler fans trip
•
Lean amine cooler fans trip
•
Lean Amine Pumps 9103-P-13A/B trips
11.2.1.2 ESD Level-1 Shutdown in Acid Gas Enrichment Unit
ESD Level-1 shutdown in AGEU is activated on the following causes:
•
Fire detection alarm (91-XS-01-1801) from AGEU/TGTU unit (LER-4)
•
Fire detection alarm (91-XS-02-1801) from Incinerator area (LER-4)
•
Fire detection alarm (68-XS-02-1801) from utility area (LER-6)
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•
Fire detection alarm (68-XS-03-1801) from utility boiler area (LER-6)
•
Fire detection alarm (66-XS-01-1801) from new substation area
•
Fire detection alarm (66-XS-03-1801) from LER-6
•
Flammable gas detection alarm (91-XS-01-1802) from AGEU/TGTU unit (LER-4)
•
Flammable gas detection alarm (91-XS-02-1802) Incinerator area (LER-4)
•
Flammable gas detection alarm (68-XS-02-1802) from utility area (LER-6)
•
Flammable gas detection alarm (68-XS-03-1802) from utility boiler area (LER-6)
•
Flammable gas detection alarm (66-XS-03-1802) from LER-6
•
Flammable gas detection alarm (66-XS-01-1802) from new substation area
•
Activation of ESD Level-1 shutdown pushbutton 65-HS-001 in CCR
Following are the effects of ESD Level 1 Shutdowns in AGEU & Amine section:
•
Acid gas ON/OFF valve 91-XV-1502 to flare opens
•
Acid gas ON/OFF valve 91-XV-1501 to 9103-E-101 closes
•
Acid Gas KO Drum Return Pumps 9103-P-14A/B trips
•
Liquid from Acid Gas KO Drum Return Pump ON/OFF valve 91-XV-1503 closes
•
Acid Gas Rich Amine Pump 9103-P-12A/B trips
•
Lean amine valve 91-XV-1504 to acid gas amine absorber closes
•
Hot Lean Amine Pumps 9103-P-17A/B trips
•
Hot lean amine valve 91-XV-1507 to Lean/Rich Exchanger closes
•
Regenerator Reflux Drum Pumps 9103-P-11A/B trips
•
DM water valve 91-XV-1517 to Regenerator Reflux Drum closes
•
Acid gas from Regenerator Reflux Drum ON/OFF valve 91-XV-1516 to SRU closes
•
Regenerator Reboiler steam valve 91-XV-1505 closes
•
Tail Gas Rich Amine Pumps 9102-P-16A/B trips
•
Lean amine to Tail Gas Amine Absorber valve 91-XV-1310 closes
•
Tail gas rich amine valve from Tail Gas Rich Amine Pump discharge 91-XV-1309
closes
•
Lean Amine Pumps 9103-P-13A/B trips
•
Amine sump pump 9103-P-15 trips
•
Acid gas drain outlet valve 91-XV-1109 from pipe separator closes.
•
Regenerator condenser cooler fans trip
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•
Lean amine cooler fans trip
•
Lean Amine Pumps 9103-P-13A/B trips
11.2.1.3 ESD Level 2 Shutdown in Acid Gas Enrichment Unit
Following are the causes for ESD level-2 shutdown:
•
Activation of ESD-2 Level-2 shutdown pushbutton 61-HS-006
•
Power failure signal (65-XS-1024) from ESD system at LER-4
•
Instrument air pressure low low (2oo3) alarm 65-PALL-1003 (existing)
•
Instrument air pressure low low (2oo3) alarm 68-PALL-1312 (SRU Upgrade)
•
Steam Generator Package shutdown signal 68-XS-1580/68-XS-1680/68-XS-1780
•
Existing SRU shutdown signal 65-XA-1001 from ESD system at LER-4
•
Incinerator shutdown signal (91-XS-1186) from UCP at LER-4
•
BFW/Steam failure signal 65-XS-1021 from ESD system at LER-4
•
High high level alarm (91-LAHH-1504) in Acid Gas Amine Absorber bottom (9103-C-11)
•
High high level alarm (91-LAHH-1509) in Amine Regenerator bottom (9103-C-12)
•
Low low flow alarm (91-FALL-1515) from Lean Amine Pumps (9103-P-13A/B)
discharge
Following are the effects of ESD Level 2 Shutdowns in AGEU:
•
Operator Permissive is available for operating Acid gas ON/OFF valve 91-XV-1502
to flare
•
Acid gas ON/OFF valve 91-XV-1501 to 9103-E-101 closes
•
Acid Gas KO Drum Return Pumps 9103-P-14A/B trips
•
Liquid from Acid Gas KO Drum Return Pump ON/OFF valve 91-XV-1503 closes
•
Acid Gas Rich Amine Pump 9103-P-12A/B trips
•
Lean amine valve 91-XV-1504 to acid gas amine absorber closes
•
Hot Lean Amine Pumps 9103-P-17A/B trips
•
Hot lean amine valve 91-XV-1507 to Lean/Rich Exchanger closes
•
Regenerator Reflux Drum Pumps 9103-P-11A/B trips
•
DM water valve 91-XV-1517 to Regenerator Reflux Drum closes
•
Acid gas from Regenerator Reflux Drum ON/OFF valve 91-XV-1516 to SRU closes
•
Regenerator Reboiler steam valve 91-XV-1505 closes
•
Tail Gas Rich Amine Pumps 9102-P-16A/B trips
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•
Lean amine to Tail Gas Amine Absorber valve 91-XV-1310 closes
•
Tail gas rich amine valve from Tail Gas Rich Amine Pump discharge 91-XV-1309
closes
•
Lean Amine Pumps 9103-P-13A/B trips
•
Amine sump pump 9103-P-15 trips
•
Acid gas drain outlet valve 91-XV-1109 from pipe separator closes.
•
Regenerator condenser cooler fans trip
•
Lean amine cooler fans trip
•
Lean Amine Pumps 9103-P-13A/B trips
11.2.1.4 ESD Level 3 Shutdown in AGEU
ESD Level-3 is activated in AGEU only by pressing pushbutton 91-HS-1011 in CCR.
Following are the effects of ESD Level 3 Shutdown in AGEU & Amine section:
•
Acid gas ON/OFF valve 91-XV-1501 to 9103-E-101 closes
•
Acid Gas KO Drum Return Pumps 9103-P-14A/B trips
•
Liquid from Acid Gas KO Drum Return Pump ON/OFF valve 91-XV-1503 closes
•
Acid Gas Rich Amine Pump 9103-P-12A/B trips
•
Lean amine valve 91-XV-1504 to Acid Gas Amine Absorber closes
•
Hot Lean Amine Pumps 9103-P-17A/B trips
•
Hot lean amine valve 91-XV-1507 to Lean/Rich Exchanger closes
•
Regenerator Reflux Drum Pumps 9103-P-11A/B trips
•
DM water valve 91-XV-1517 to Regenerator Reflux Drum closes
•
Acid gas from Regenerator Reflux Drum ON/OFF valve 91-XV-1516 to SRU closes
•
Regenerator Re-boiler steam valve 91-XV-1505 closes
•
Tail Gas Rich Amine Pumps 9102-P-16A/B trips
•
Lean amine to Tail Gas Amine Absorber valve 91-XV-1310 closes
•
Tail gas rich amine valve from Tail Gas Rich Amine Pump discharge 91-XV-1309
closes
•
Lean Amine Pumps 9103-P-13A/B trips
•
Amine Sump Pump 9103-P-15 trips
•
Acid gas drain outlet valve 91-XV-1109 from Pipe Separator closes.
•
Regenerator Condenser Cooler Fans trip
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•
Lean Amine Cooler Fans trip
•
Lean Amine Pumps 9103-P-13A/B trips
11.2.1.5 ESD Level 4 Shutdown in Acid Gas Enrichment Unit
Following are the ESD Level 4 Shutdowns (equipment wise) in AGEU & Amine section:
Lean Acid Gas KO Drum (9103-V-14)
•
High high level alarm 91-LAHH-1502 in Lean Acid Gas KO Drum (9103-V-14) closes
the acid gas block valve 91-XV-1501 to Acid Gas Coolers
•
Low low level alarm 91-LALL-1503 in lean acid gas KO drum (9103-V-14) closes the
liquid block valve 91-XV-1503 from lean acid KO drum
Acid Gas Amine Absorber (9103-C-11)
•
Low low level alarm 91-LALL-1516 in Acid Gas Amine Absorber bottom trips the
Acid Gas Rich Amine Pumps 9103-P-12A/B
•
Low low rich amine flow alarm 91-FALL-1510 in Acid Gas Amine Absorber trips the
Acid Gas Rich Amine Pumps 9103-P-12A/B
Amine Regenerator
•
Low low level alarm 91-LALL-1517 in Amine Regenerator bottom trips the Hot Lean
Amine Pumps 9103-P-17A/B and closes the hot lean amine valve 91-XV-1507 to
Lean Rich Exchanger
•
Low low hot lean amine flow alarm 91-FALL-1509 trips the Hot Lean Amine Pumps
9103-P-17A/B and closes the hot lean amine valve 91-XV-1507 to Lean Rich
Exchanger
Regenerator Reflux Drum
•
Low low level alarm 91-LALL-1518 in Regenerator Reflux Drum trips the
regenerator reflux drum pumps 9103-P-11A/B
•
High high level alarm (91-LAHH-1507) in Regenerator Reflux Drum closes the DM
water block valve 91-XV-1517
•
Low low flow alarm (91-FALL-1506) trips the Regenerator Reflux Pumps 9103-P11A/B
Tail Gas Absorber
•
High high level alarm (91-LAHH-1310) in Tail Gas Absorber bottom closes the lean
amine inlet valve 91-XV-1310 to Tail Gas Amine Absorber
•
Low low level alarm (91-LALL-1301) in Tail Gas Absorber bottom trips the Tail Gas
Absorber Bottom Pumps (9102-P-16A/B) and closes the Tail Gas Rich Amine
On/OFF valve 91-XV-1309
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•
Low low flow alarm (91-FALL-1305) in Tail Gas Rich Amine Pump discharge trips
the Tail Gas Absorber Bottom Pumps (9102-P-16A/B) and closes the tail gas rich
amine On/OFF valve 91-XV-1309
Amine Surge Tank
•
Low low level alarm (91-LALL-1511) in Amine Surge Tank trips the lean amine
pump (9103-P-13A/B)
•
Low low level alarm (91-LALL-1513) in Amine Sump trips the amine sump pump
(9103-P-15)
Pipe Separator
Low low level alarm (91-LALL-1054) closes the acid gas outlet valve 91-XV-1109 in the
Pipe Separator
Regenerator Condenser Coolers
Regenerator Condenser Coolers 9103-E-12AA to 9103-E-12DC trips, due to high high
vibration alarms sensed by their respective cooler fan vibration probes.
Detail list of coolers and vibration alarms are as listed below:
Vibration Tag No.
Cooler Tag No.
91-VAHH-1537
9103-EM-12AA
91-VAHH-1538
9103-EM-12AB
91-VAHH-1539
9103-EM-12AC
91-VAHH-1540
9103-EM-12BA
91-VAHH-1541
9103-EM-12BB
91-VAHH-1542
9103-EM-12BC
91-VAHH-1543
9103-EM-12CA
91-VAHH-1544
9103-EM-12CB
91-VAHH-1545
9103-EM-12CC
91-VAHH-1546
9103-EM-12DA
91-VAHH-1547
9103-EM-12DB
91-VAHH-1548
9103-EM-12DC
Lean Amine Coolers
Lean amine coolers 9103-E-14AA to 9103-E-14JC trips due to high high vibration alarms
sensed by their respective cooler fan vibration probes.
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Detail list of coolers and vibration alarms are as listed below:
Vibration Tag No.
Cooler Tag No.
91-VAHH-1501
9103-EM-14AA
91-VAHH-1502
9103-EM-14AB
91-VAHH-1503
9103-EM-14AC
91-VAHH-1504
9103-EM-14BA
91-VAHH-1505
9103-EM-14BB
91-VAHH-1506
9103-EM-14BC
91-VAHH-1507
9103-EM-14CA
91-VAHH-1508
9103-EM-14CB
91-VAHH-1509
9103-EM-14CC
91-VAHH-1510
9103-EM-14DA
91-VAHH-1511
9103-EM-14DB
91-VAHH-1512
9103-EM-14DC
91-VAHH-1513
9103-EM-14EA
91-VAHH-1514
9103-EM-14EB
91-VAHH-1515
9103-EM-14EC
91-VAHH-1516
9103-EM-14FA
91-VAHH-1517
9103-EM-14FB
91-VAHH-1518
9103-EM-14FC
91-VAHH-1519
9103-EM-14GA
91-VAHH-1520
9103-EM-14GB
91-VAHH-1521
9103-EM-14GC
91-VAHH-1522
9103-EM-14HA
91-VAHH-1523
9103-EM-14HB
91-VAHH-1524
9103-EM-14HC
91-VAHH-1525
9103-EM-14IA
91-VAHH-1526
9103-EM-14IB
91-VAHH-1527
9103-EM-14IC
91-VAHH-1528
9103-EM-14JA
91-VAHH-1529
9103-EM-14JB
91-VAHH-1530
9103-EM-14JC
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Lean Amine Pumps
Lean Amine Pump 9103-P-13A trips due to the following causes:
Tag No.
Description
91-TAHH-1569
High high temperature alarm in lean amine motor NDE bearing
91-VAHH-1591
High high radial vibration alarm in lean amine pump motor DE end
91-VAHH-1592
High high radial vibration alarm in lean amine pump motor NDE end
91-VAHH-1593
High high radial vibration alarm in lean amine pump DE side
91-VAHH-1594
High high radial vibration alarm in lean amine pump NDE side
91-VAHH-1595
High high axial vibration alarm in lean amine pump NDE side
91-VAHH-1596
High high axial vibration alarm in lean amine pump NDE side
Lean Amine Pump 9103-P-13B trips due to the following causes:
Tag No.
Description
91-TAHH-1579
High high temperature alarm in lean amine motor NDE bearing
91-VAHH-1599
High high radial vibration alarm in lean amine pump motor DE end
91-VAHH-1600
High high radial vibration alarm in lean amine pump motor NDE end
91-VAHH-1601
High high radial vibration alarm in lean amine pump DE side
91-VAHH-1602
High high radial vibration alarm in lean amine pump NDE side
91-VAHH-1603
High high axial vibration alarm in lean amine pump NDE side
91-VAHH-1604
High high axial vibration alarm in lean amine pump NDE side
•
High high temperature alarm (91-TAHH-1589) in Acid Gas Rich Amine Pump motor
drive NDE bearing, trips the acid gas rich amine pump 9103-P-12A.
•
High high temperature alarm (91-TAHH-1593) in Acid Gas Rich Amine Pump motor
drive NDE bearing, trips the acid gas rich amine pump 9103-P-12B.
•
High high temperature alarm (91-TAHH-1597) in Hot Lean Amine Pump motor drive
NDE bearing, trips the acid gas rich amine pump 9103-P-17A.
•
High high temperature alarm (91-TAHH-1601) in Hot Lean Amine Pump motor drive
NDE bearing, trips the acid gas rich amine pump 9103-P-17B.
11.2.2
Sulphur Recovery Unit
Equipment in this ESD Zone is as follows:
•
Acid Gas KO drums (9101-V-04)
•
Process Air Blowers (9101-K-01A/B)
•
Process Air Pre-heater (9101-E-05)
•
Reaction Furnace (9101-F-01)
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•
Steam Drum (9101-V-07)
•
Reaction Furnace Condenser (9101-E-01)
•
1st Stage Condenser (9101-E-02)
•
1st Stage Converter (9101-V-01)
•
Last Condenser (9101-E-04)
•
Boiler Feed Water Heater (9101-E-08)
•
Acid Water Pumps (9101-P-01A/B)
•
Acid Gas Pre-Heater (9101-E-06)
•
HP Condensate Drums (9101-V-06).
•
Reaction Furnace Boiler (9101-E-07)
•
Boiler Blow Down Pit (9101-T-04)
•
1st Stage Auxiliary Burner (9101-F-02)
•
2nd Stage Auxiliary Burner (9101-F-03)
•
2nd Stage Converter (9101-V-02)
•
Final Separator (9101-V-05)
•
New Catalyst Tank (9101-T-09)
•
New Sulphur Degassing Pumps (9101-P-09A/B)
•
New Sulphur Degassing Pit (9101-T-01B)
•
Existing Catalyst Tank (9101-T-03)
•
Existing Sulphur Degassing Pumps (9101-P-03A/B)
•
Existing Sulphur Degassing Pit (9101-T-01)
•
Sulphur Storage Tank (9101-T-02)
•
Steam Ejector (9101-X-02)
•
New Steam Ejector (9101-X-03)
•
New Catalyst Metering Pumps (9101-P-11A/B)
•
New Sulphur Product Pumps (9101-P-10A/B)
•
Catalyst Metering Pumps (9101-p-02A/B)
•
Existing Sulphur Product Pumps (9101-P-04A/B)
•
Sulphur Tank Pumps (9101-P-15A/B)
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11.2.2.1 ESD –Level 1 Shutdown in Existing SRU
Following are the causes which initiates ESD level-1 shutdown in existing SRU:
•
General plant shutdown activation by pushbutton 65-HS-001
•
Total power shutdown signal 65-XS-1024
•
Instrument air pressure low low alarm 65-PALL-1003A/B/C
•
BFW steam failure signal 68-XS-1015
•
Unit -91 general shutdown activation by pushbutton 91-HS-1011
Above mentioned ESD level-1 shutdown causes closes the following valves in existing
SRU:
•
Acid gas inlet valve 91-XV-1001 to acid gas KO drum 9101-V-04
•
Acid water outlet valve 91-XV-1022 to MEDA storage tank
•
Combustion air discharge valve 91-XV-1046 to pre-heater 9101-E-05
•
Fuel gas to Reaction Furnace valve 91-XV-1099
•
Fuel gas to Reaction Furnace valve 91-XV-1048
•
Acid gas to Reaction Furnace valve 91-XV-1102
•
Combustion air to Reaction Furnace valve 91-XV-1101
•
Combustion air to Reaction Furnace valve 91-FV-1002
•
Secondary air to Reaction Furnace valve 91-FV-1002B
•
Trim air to Reaction Furnace valve 91-FV-1003
•
Fuel gas to 1st Stage Auxiliary Burner valve 91-XV-1028
•
Fuel gas to 1st Stage Auxiliary Burner valve 91-XV-1131
•
Fuel gas to 1st Stage Auxiliary Burner valve 91-FV-1020
•
Combustion air to 1st Stage Auxiliary Burner valve 91-FV-1018
•
Acid gas to 1st Stage Auxiliary Burner valve 91-FV-1019
•
Fuel gas to 2nd Stage Auxiliary Burner valve 91-XV-1031
•
Fuel gas to 2nd Stage Auxiliary Burner valve 91-XV-1133
•
Fuel gas to 2nd Stage Auxiliary Burner valve 91-FV-1027
•
Combustion air to 2nd Stage Auxiliary Burner valve 91-FV-1025
•
Acid gas to 2nd Stage Auxiliary Burner valve 91-FV-1026
•
Tail gas valve 91-XV-1098 to RGG
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Above mentioned ESD level-1 shutdown causes opens the following valves in existing
SRU:
•
Fuel gas to atmosphere from 1st Stage Auxiliary Burner valve 91-XV-1132
•
Fuel gas to atmosphere from 2nd Stage Auxiliary Burner valve 91-XV-1134
•
Fuel gas to atmosphere from Reaction Furnace valve 91-XV-1100
•
Nitrogen valve 91-XV-1127 to Reaction Furnace instruments
•
LP steam in air valve 91-XV-1076 to Acid Gas Burner
•
LP steam valve 91-XV-1079 to acid gas gun open
•
Tail gas valve 91-XV-1097 to Incinerator
Above mentioned ESD level-1 shutdown causes trips the following in existing SRU:
Equipment Tag No.
Description
Trip Signal
9101-K-01A/B
Process Air Blower
91-XS-1004/91-XS-1005
9101-P-01A/B
Acid Water Pump
91-XS-1002/91-XS-1003
9101-P-02A/B
Catalyst Metering Pumps
91-XS-1034/91-XS-1035
9101-P-03A/B
Sulphur Degassing Pumps
91-XS-1036/91-XS-1037
9101-P-11A/B
Catalyst Metering Pumps
91-XS-1129/91-XS-1130
9101-P-09A/B
Sulphur Degassing Pumps
91-XS-1138/91-XS-1139
9101-P-04A/B
Sulphur Product Pumps
91-XS-1038/91-XS-1039
9101-P-10A/B
Sulphur Product Pumps
91-XS-1140/91-XS-1141
9101-P-15A/B
Sulphur Tank Pumps
91-XS-1051/91-XS-1052
Note:
1. Steam supply valve 91-XV-1045 to Ejector 9101-X-02 and Steam supply valve 91-XV1092 to Ejector 9101-X-03 is closed only on the following ESD level-1 causes:
•
BFW steam failure signal 68-XS-1015
•
Unit-91 general shutdown activation by pushbutton 91-HS-1011
2. Incinerator is tripped only due to following ESD level-1 causes:
•
General plant shutdown activation by pushbutton 65-HS-001
•
Total power shutdown signal 65-XS-1024
•
Instrument air pressure low low alarm 65-PALL-1003A/B/C
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11.2.2.2 ESD–Level 2 Shutdown in Existing SRU
Following is the only cause which initiates ESD level-2 shutdowns in existing SRU:
Confirmed gas detection alarm (91-GF-1001/1029) 91-XS-1901 in existing SRU.
Above mentioned ESD level-2 shutdown cause closes the following valves in existing
SRU:
•
Acid gas inlet valve 91-XV-1001 to Acid Gas KO Drum 9101-V-04
•
Acid water outlet valve 91-XV-1022 to MDEA storage tank
•
Combustion air discharge valve 91-XV-1046 to Pre-Heater 9101-E-05
•
Fuel gas to Reaction Furnace valve 91-XV-1099
•
Fuel gas to Reaction Furnace valve 91-XV-1048
•
Acid gas to Reaction Furnace valve 91-XV-1102
•
Combustion air to Reaction Furnace valve 91-XV-1101
•
Combustion air to Reaction Furnace valve 91-FV-1002
•
Secondary air to Reaction Furnace valve 91-FV-1002B
•
Trim air to Reaction Furnace valve 91-FV-1003
•
Fuel gas to 1st Stage Auxiliary Burner valve 91-XV-1028
•
Fuel gas to 1st Stage Auxiliary Burner valve 91-XV-1131
•
Fuel gas to 1st Stage Auxiliary Burner valve 91-FV-1020
•
Combustion air to 1st stage auxiliary burner valve 91-FV-1018
•
Acid gas to 1st Stage Auxiliary Burner valve 91-FV-1019
•
Fuel gas to 2nd Stage Auxiliary Burner valve 91-XV-1031
•
Fuel gas to 2nd Stage Auxiliary Burner valve 91-XV-1133
•
Fuel gas to 2nd Stage Auxiliary Burner valve 91-FV-1027
•
Combustion air to 2nd Stage Auxiliary Burner valve 91-FV-1025
•
Acid gas to 2nd Stage Auxiliary Burner valve 91-FV-1026
•
Tail gas valve 91-XV-1098 to RGG
•
Steam supply valve 91-XV-1045 to Ejector 9101-X-02
•
Steam supply valve 91-XV-1092 to Ejector 9101-X-03
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Above mentioned ESD level -2 shutdown cause opens the following valves in existing
SRU:
•
Fuel gas to atmosphere from 1st Stage Auxiliary Burner valve 91-XV-1132
•
Fuel gas to atmosphere from 2nd Stage Auxiliary Burner valve 91-XV-1134
•
Fuel gas to atmosphere from reaction furnace valve 91-XV-1100 Nitrogen valve
91-XV-1127 to Reaction Furnace instruments
•
LP steam in air valve 91-XV-1076 to acid gas burner
•
LP steam ON/OFF valve 91-XV-1079 to acid gas gun
•
Tail gas valve 91-XV-1097 to Incinerator
Above mentioned ESD level -2 shutdown causes trips the following in existing SRU:
Equipment Tag No.
Description
Trip Signal
9101-K-01A/B
Process air blower
91-XS-1004/91-XS-1005
9101-P-01A/B
Acid water pump
91-XS-1002/91-XS-1003
9101-P-02A/B
Catalyst metering pumps
91-XS-1034/91-XS-1035
9101-P-03A/B
Sulphur degassing pumps
91-XS-1036/91-XS-1037
9101-P-11A/B
Catalyst metering pumps
91-XS-1129/91-XS-1130
9101-P-09A/B
Sulphur degassing pumps
91-XS-1138/91-XS-1139
9101-P-04A/B
Sulphur product pumps
91-XS-1038/91-XS-1039
9101-P-10A/B
Sulphur product pumps
91-XS-1140/91-XS-1141
9101-P-15A/B
Sulphur tank pumps
91-XS-1051/91-XS-1052
Note: Incinerator is tripped through the signal 91-XS-1169.
11.2.2.3 ESD–Level 3 Shutdown in Existing SRU
Following are the causes which initiates ESD level-3 shutdowns in existing SRU:
•
Fuel gas low low pressure alarm 65-XS-1020
•
AGR S/D (2 trains) 65-XS-1008
•
Process air blowers flow low low alarm 91-FALL-1006
•
Steam Drum 9101-V-07 level low low alarm 91-LALL-1006
•
Reaction Furnace Condenser level low low alarm 91-LALL-1009
•
1st Stage Condenser level low low alarm 91-LALL-1012
•
Acid gas inlet pressure low low alarm 91-PALL-1025
•
Process Air Blower 9101-K-01A/B shutdown signals 91-XS-1063 and 91-XS-1064
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•
Air for acid gas burner pressure high high alarm 91-PAHH-1054A/B/C
•
Acid gas to reaction furnace flow low low alarm 91-FALL-1140
•
Combustion air to acid gas burner flow low low alarm 91-FALL-1129
•
Fuel gas to reaction furnace flow low low alarm 91-FALL-1130
•
Reaction Furnace shutdown pushbutton 91-HS-1012A from CCR
•
Reaction Furnace shutdown pushbutton 91-HS-1213 from LCP
•
Reaction furnace flame failure alarm 91-BALL-1055A/B
•
Rupture pin failure alarm 91-TAHH-1050
Above mentioned ESD level-3 shutdown causes closes the following valves in existing SRU:
•
Acid gas inlet valve 91-XV-1001 to Acid Gas KO Drum 9101-V-04
•
Acid water outlet valve 91-XV-1022 to MDEA storage tank
•
Combustion air discharge valve 91-XV-1046 to Air Pre-Heater 9101-E-05
•
Fuel gas to Reaction Furnace valve 91-XV-1099
•
Fuel gas to Reaction Furnace valve 91-XV-1048
•
Acid gas to Reaction Furnace valve 91-XV-1102
•
Combustion air to Reaction Furnace valve 91-XV-1101
•
Combustion air to Reaction Furnace valve 91-FV-1002
•
Secondary air to Reaction Furnace valve 91-FV-1002B
•
Trim air to Reaction Furnace valve 91-FV-1003
•
Fuel gas to 1st Stage Auxiliary Burner valve 91-XV-1028
•
Fuel gas to 1st Stage Auxiliary Burner valve 91-XV-1131
•
Fuel gas to 1st Stage Auxiliary Burner valve 91-FV-1020
•
Combustion air to 1st Stage Auxiliary Burner valve 91-FV-1018
•
Acid gas to 1st Stage Auxiliary Burner valve 91-FV-1019
•
Fuel gas to 2nd Stage Auxiliary Burner valve 91-XV-1031
•
Fuel gas to 2nd Stage Auxiliary Burner valve 91-XV-1133
•
Combustion air to 2nd Stage Auxiliary Burner valve 91-FV-1025
•
Acid gas to 2nd Stage Auxiliary Burner valve 91-FV-1026
•
Fuel gas to 2nd Stage Auxiliary Burner valve 91-FV-1027
•
Tail gas valve 91-XV-1098 to RGG
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Above mentioned ESD level-3 shutdown causes opens the following valves in existing
SRU:
•
Fuel gas to atmosphere from 1st Stage Auxiliary Burner valve 91-XV-1132
•
Fuel gas to atmosphere from 2nd Stage Auxiliary Burner valve 91-XV-1134
•
Fuel gas to atmosphere from Reaction Furnace valve 91-XV-1100
•
Nitrogen valve 91-XV-1127 to Reaction Furnace instruments
•
LP steam in air valve 91-XV-1076 to Acid gas burner
•
LP steam valve 91-XV-1079 to acid gas gun open
•
Tail gas valve 91-XV-1097 to Incinerator
Above mentioned ESD level-3 shutdown causes trips the following in existing SRU:
•
Process air blower’s 9101-K-01A/B
•
Acid Water Pumps 9101-P-01A/B
Note: Incinerator is tripped only on Fuel gas pressure low low alarm 65-XS-1020.
11.2.2.4 ESD–Level 4 Shutdown in Existing SRU
1st Stage Auxiliary Burner
Following are the causes in SRU 1st Stage Auxiliary Burner which initiates ESD Level 4
Shutdown:
•
Activation of 1st Stage Auxiliary Burner stop pushbutton 91-HS-1227 from LCP
•
Combustion air flow to 1st Stage Auxiliary Burner low low alarm 91-FALL-1133
•
Acid gas flow to 1st Stage Auxiliary Burner low low alarm 91-FALL-1134
•
Fuel gas flow to 1st Stage Auxiliary Burner low low alarm 91-FALL-1135
•
Flame failure alarm 91-BALL-1003A/B in 1st Stage Auxiliary Burner
Effects of ESD Level 4 Shutdown in SRU-1st stage auxiliary burner:
•
1st Stage Auxiliary Burner fuel gas valve 91-XV-1028 close
•
1st Stage Auxiliary Burner fuel gas valve 91-XV-1131 close
•
1st Stage Auxiliary Burner combustion air valve 91-FV-1018 close
•
1st Stage Auxiliary Burner acid gas valve 91-FV-1019 close
•
1st Stage Auxiliary Burner fuel gas valve 91-FV-1020 close
•
1st Stage Auxiliary Burner fuel gas to atmosphere valve 91-XV-1132 opens
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2nd Stage Auxiliary Burner
Following are the causes in SRU 2nd Stage Auxiliary Burner which initiates ESD Level 4
Shutdown:
•
Activation of 2nd Stage Auxiliary Burner stop pushbutton 91-HS-1196 from LCP
•
Combustion air flow to 2nd Stage Auxiliary Burner low low alarm 91-FALL-1136
•
Acid gas flow to 2nd Stage Auxiliary Burner low low alarm 91-FALL-1137
•
Fuel gas flow to 2nd Stage Auxiliary Burner low low alarm 91-FALL-1138
•
Flame failure alarm 91-BALL-1004A/B in 2nd Stage Auxiliary Burner
Effects of ESD Level 4 Shutdown in SRU 2nd stage auxiliary burner:
•
2nd Stage Auxiliary Burner fuel gas valve 91-XV-1031 close
•
2nd Stage Auxiliary Burner fuel gas valve 91-XV-1133 close
•
Combustion air to 2nd Stage Auxiliary Burner valve 91-FV-1025 close
•
2nd Stage Auxiliary Burner acid gas valve 91-FV-1026 close
•
2nd Stage Auxiliary Burner fuel gas valve 91-FV-1027 close
•
2nd Stage Auxiliary Burner fuel gas to atmosphere valve 91-XV-1134 opens
Sulphur Pit
Following are the causes in SRU which initiates ESD Level 4 Shutdown in Sulphur pit
9101-T-01:
•
High high H2S alarm 91-AHA-1002 alarm in 9101-T-01
•
Sweeping air flow low low alarm 91-FALL-1032
Effects of ESD Level 4 Shutdown in SRU - Sulphur pit 9101-T-01:
•
Catalyst Metering Pumps 9101-P02A/B trip
•
Sulphur Degassing Pumps 9101-P03A/B trip
•
Sulphur Product Pumps 9101-P-04A/B trip
New Sulphur Pit
Following are the causes in SRU which initiates ESD Level 4 Shutdown in New Sulphur
Pit 9101-T-01B:
•
High high H2S alarm 91-AHA-1002 alarm in 9101-T-01B
•
Sweeping air flow low low alarm 91-FALL-1056
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Effects of ESD Level 4 Shutdown in SRU – New Sulphur Pit 9101-T-01B area:
•
New Catalyst Metering Pumps 9101-P11A/B trip
•
New Sulphur Degassing Pumps 9101-P09A/B trip
•
New Sulphur Product Pumps (9101-P-10A/B) trip
Acid Gas KO Drum
High high level alarm 91-LAHH-1003 alarm in Acid Gas KO Drum 9101-V-04 closes the
following valves:
•
Acid gas inlet valve 91-XV-1001 to Acid Gas KO Drum 9101-V-04
•
Combustion air discharge valve 91-XV-1046 to Pre-heater 9101-E-05
•
Fuel gas to 1st Stage Auxiliary Burner valve 91-XV-1028
•
Fuel gas to 1st Stage Auxiliary Burner valve 91-XV-1131
•
Combustion air to 1st Stage Auxiliary Burner valve 91-FV-1018
•
Acid gas to 1st Stage Auxiliary Burner valve 91-FV-1019
•
Fuel gas to 1st Stage Auxiliary Burner valve 91-FV-1020
•
Fuel gas to 2nd Stage Auxiliary Burner valve 91-XV-1031
•
Fuel gas to 2nd Stage Auxiliary Burner valve 91-XV-1133
•
Combustion air to 2nd Stage Auxiliary Burner valve 91-FV-1025
•
Acid gas to 2nd Stage Auxiliary Burner valve 91-FV-1026
•
Fuel gas to 2nd Stage Auxiliary Burner valve 91-FV-1027
•
Fuel gas to Reaction Furnace valve 91-XV-1099
•
Fuel gas to Reaction Furnace valve 91-XV-1048
•
Combustion air to Reaction Furnace valve 91-XV-1101
•
Acid gas to Reaction Furnace valve 91-XV-1102
•
Combustion air to Reaction Furnace valve 91-FV-1002
•
Secondary air to Reaction Furnace valve 91-FV-1002B
•
Trim air to Reaction Furnace valve 91-FV-1003
•
Tail gas valve 91-XV-1098 to RGG
High high level alarm 91-LAHH-1003 alarm in Acid Gas KO Drum 9101-V-04 opens the
following valves:
•
Fuel gas to atmosphere from 1st Stage Auxiliary Burner valve 91-XV-1132
•
Fuel gas to atmosphere from 2nd Stage Auxiliary Burner valve 91-XV-1134
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•
Fuel gas to atmosphere valve 91-XV-1100
•
Nitrogen valve 91-XV-1127 to Reaction Furnace instruments
•
LP steam in air valve 91-XV-1076 to Acid Gas Burner
•
LP steam valve 91-XV-1092 to Acid gas gun
•
Tail gas valve 91-XV-1097 to Incinerator
•
High high level alarm 91-LAHH-1003 alarm in Acid Gas KO Drum 9101-V-04 trips the
Process air blower’s 9101-K-01A/B.
•
Low low level alarm 91-LALL-1002 alarm in Acid Gas KO Drum 9101-V-04 activates
the following:
•
Acid Water Pumps 9101-P-01A/B trip
•
Acid water outlet valve 91-XV-1022 to MDEA storage tank closes
Sulphur Degassing Unit
•
Low low level alarm 91-LALL-1015 alarm in Sulphur Degassing Unit 9101-T-01 trips
the following:
•
Sulphur Degassing Pumps 9101-P-03A/B
•
Sulphur Product Pumps 9101-P-04A/B
•
Low low level alarm 91-LALL-1017 alarm in Sulphur Storage Tank 9101-T-02 trips
the Sulphur Tank Pumps 9101-P-15A/B.
•
Low low level alarm 91-LALL-1052 alarm in Sulphur Degassing Unit 9101-T-01B
trips the following:
•
•
Sulphur Degassing Pumps 9101-P-09A/B
•
Sulphur Product Pumps 9101-P-10A/B
High high level alarm 91-LAHH-1017 alarm in Sulphur Storage Tank 9101-T-02 trips
the following:
•
Sulphur Product Pumps 9101-P-10A/B
•
Sulphur Product Pumps 9101-P-04A/B
Sulphur Degassing Pit
•
High high temperature alarm 91-TAHH-1033 in Sulphur Degassing Pit 9101-T-01
closes the steam supply valve 91-XV-1045 to Steam Ejector 9101-X-02.
•
High high temperature alarm 91-TAHH-1104 in Sulphur Degassing Pit 9101-T-01B
closes the steam supply valve 91-XV-1092 to Steam Ejector 9101-X-03 and opens
the LP steam valve 91-XV-1078 to Acid Gas Burner,91-XV-1079 to Acid Gas Gun.
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•
High high pressure alarm 91-PAHH-1055 in Final Separator 9101-V-05 opens the tail
gas valve 91-XV-1097 to Incinerator and closes the tail gas valve 91-XV-1098 to
RGG.
•
Gas detected alarm 91-XS-1902(91-GF-1001 to 91-GF-1003) in air intake of 9101-K01A trips the Combustion Blower 9101-K-01A.
•
Gas detected alarm 91-XS-1903 (91-GF-1004 to 91-GF-1006) in air intake of
9101-K-01B trips the Combustion Blower 9101-K-01B.
Inter trips
RGG shutdown signals 91-XS-1350 to existing SRU unit opens the tail gas valve 91-XV1097 to Incinerator and closes the tail gas valve 91-XV-1098 to RGG
Incinerator shutdown signal 91-XS-1104 initiates the following in SRU:
•
Acid gas inlet valve 91-XV-1001 to Acid Gas KO Drum 9101-V-04 close
•
Combustion air discharge valve 91-XV-1046 to Pre-Heater 9101-E-05 close
•
Fuel gas to 1st Stage Auxiliary Burner valve 91-XV-1028 close
•
Fuel gas to 1st Stage Auxiliary Burner valve 91-XV-1131 close
•
Combustion air to 1st Stage Auxiliary Burner valve 91-FV-1018 close
•
Acid gas to 1st Stage Auxiliary Burner valve 91-FV-1019 close
•
Fuel gas to 1st Stage Auxiliary Burner valve 91-FV-1020 close
•
Fuel gas to 2nd Stage Auxiliary Burner valve 91-XV-1031 close
•
Fuel gas to 2nd Stage Auxiliary Burner valve 91-XV-1133 close
•
Combustion air to 2nd Stage Auxiliary Burner valve 91-FV-1025 close
•
Acid gas to 2nd Stage Auxiliary Burner valve 91-FV-1026 close
•
Fuel gas to 2nd Stage Auxiliary Burner valve 91-FV-1027 close
•
Fuel gas to Reaction Furnace valve 91-XV-1099 close
•
Fuel gas to Reaction Furnace valve 91-XV-1048 close
•
Combustion air to Reaction Furnace valve 91-XV-1101 close
•
Acid gas to Reaction Furnace valve 91-XV-1102 close
•
Combustion air to Reaction Furnace valve 91-FV-1002 close
•
Secondary air to Reaction Furnace valve 91-FV-1002B close
•
Trim air to Reaction Furnace valve 91-FV-1003 close
•
Tail gas valve 91-XV-1098 to RGG close
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11.2.3
•
Steam supply valve 91-XV-1045 to Ejector 9101-X-02 close
•
Steam supply valve 91-XV-1092 to Ejector 9101-X-03 close
•
Fuel gas to atmosphere from 1st Stage Auxiliary Burner valve 91-XV-1132 open
•
Fuel gas to atmosphere from 2nd Stage Auxiliary Burner valve 91-XV-1134 open
•
Fuel gas to atmosphere from reaction furnace valve 91-XV-1100 open
•
Nitrogen valve 91-XV-1127 to Reaction Furnace instruments open
•
LP steam in air valve 91-XV-1076 to Acid Gas Burner open
•
LP steam valve 91-XV-1092 to Acid Gas Gun open
•
Tail gas valve 91-XV-1097 to Incinerator open
•
Combustion Air Blowers 9101-K-01A/B trip
•
Catalyst Metering Pumps 9101-P-02A/B, 9101-P-11A/B trip
•
Sulphur Degassing Pumps 9101-P-03A/B, 9101-P-09A/B trip
•
Sulphur Product Pumps 9101-P-10A/B trip
•
Sulphur Tank Pumps 9101-P-15A/B trip
Tail Gas Treatment Unit
Equipment in this ESD Zone is as follows:
•
RGG (9102-F-11)
•
Hydrogenation Reactor (9102-V-11)
•
Reactor Effluent Cooler (9102-E-11)
•
Start-up Gas Steam Ejector (9102-X-11)
•
De-super Heater/Contact Condenser (9102-C-11)
•
Wash Water Filter (9102-S-15)
•
Contact Condenser Trim Coolers (9102-E-13A/B)
•
Contact Condenser Cooler (9102-E-12)
11.2.3.1 ESD Level 0 Shutdown in TGTU system
ESD level-0 is activated only by pressing emergency pushbutton 65-HS-4001 in CCR.
Following are the effects of ESD Level 0 Shutdowns in TGTU section:
•
Combustion air block valve 91-XV-1306 to RGG closes
•
Fuel gas block valve 91-XV-1303 to RGG closes
•
Fuel gas vent valve 91-XV-1308 to RGG opens
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•
Fuel gas block valve 91-XV-1304 to RGG closes
•
Steam block valve 91-XV-1305 to RGG closes
•
Nitrogen purge block valve 91-XV-1307 to RGG opens
•
Nitrogen purge block valve 91-XV-1301 to RGG opens
•
Instrument air purge block valve 91-XV-1302 to RGG closes
•
De-super Heater Circulation Pump 9102-P-11A/B trip
•
Cooling Water Circulation Pump 9102-P-12A/B trip
•
Combustion Air Blowers 9102-K-11A/B is trip
•
Contact Condenser Cooler Fans trip
•
Tail gas bypass block valve 91-XV-1331 to Incinerator opens
•
Tail gas block valve 91-XV-1332 to Contact Condenser closes
•
Sour Water Stripper 6922-C-01 overhead block valve 69 XV-1313 closes
11.2.3.2 ESD Level 1 Shutdown in TGTU system
Following causes initiates ESD level1 shutdown in TGTU:
•
Fire detection alarm (91-XS-01-1801) from AGEU/TGTU unit (LER-4).
•
Fire detection alarm (91-XS-02-1801) from Incinerator area (LER-4).
•
Fire detection alarm (68-XS-02-1801) from Utility area (LER-6)
•
Fire detection alarm (68-XS-03-1801) from Utility Boiler Area (LER-6)
•
Fire detection alarm (66-XS-01-1801) from New Substation Area
•
Fire detection alarm (66-XS-03-1801) from LER-6
•
Flammable gas detection alarm (91-XS-01-1802) from AGEU/TGTU unit (LER-4)
•
Flammable gas detection alarm (91-XS-02-1802) Incinerator area (LER-4)
•
Flammable gas detection alarm (68-XS-02-1802) from Utility Area (LER-6)
•
Flammable gas detection alarm (68-XS-03-1802) from Utility Boiler area (LER-6)
•
Flammable gas detection alarm (66-XS-03-1802) from LER-6
•
Flammable gas detection alarm (66-XS-01-1802) from New Substation Area
•
Activation of ESD Level-1 shutdown pushbutton 65-HS-001 in CCR
Following are the effects of ESD Level 1 Shutdowns in TGTU section:
•
Combustion air block valve 91-XV-1306 to RGG closes
•
Fuel gas block valve 91-XV-1303 to RGG closes
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•
Fuel gas vent valve 91-XV-1308 to RGG opens
•
Fuel gas block valve 91-XV-1304 to RGG closes
•
Steam block valve 91-XV-1305 to RGG closes
•
Nitrogen purge block valve 91-XV-1307 to RGG opens
•
Nitrogen purge block valve 91-XV-1301 to RGG opens
•
Instrument air purge block valve 91-XV-1302 to RGG closes
•
De-super Heater Circulation Pump 9102-P-11A/B trip
•
Cooling Water Circulation Pump 9102-P-12A/B trip
•
Combustion Air Blowers 9102-K-11A/B is trip
•
Contact Condenser Cooler Fans trip
•
Tail gas bypass block valve 91-XV-1331 to Incinerator opens
•
Tail gas block valve 91-XV-1332 to Contact Condenser closes
•
Sour Water Stripper 6922-C-01 overhead block valve 69 XV-1313 closes
11.2.3.3 ESD Level 2 Shutdown in TGTU system
ESD Level 2 Shutdown is activated by the following causes:
•
High high level alarm (91-LAHH-1504) in Acid Gas Amine Absorber bottom
(9103-C-11)
•
High high level alarm (91-LAHH-1509) in Amine Regenerator bottom (9103-C-12)
•
Low low flow alarm (91-FALL-1515) in Lean Amine Pumps (9103-P-13A/B)
discharge
•
Incinerator shutdown signal (91-XS-1186) from Incinerator UCP
•
Unit-91 (SRU+AGEU+TGTU) shutdown activation by pushbutton 91-HS-1011
•
Total power failure signal (65-XS-1024)
•
Instrument air pressure low low (2oo3) alarm 65-PALL-1003
•
Steam failure signal 65-XS-1021
•
Existing SRU shutdown signal 65-XA-1001
•
Steam generator package shutdown signal 68-XS-1580/68-XS-1680/68-XS-1780
•
Instrument air pressure 2oo3 low low alarm (68-PALL-1312A/B/C)
Following are the effects of ESD Level 2 Shutdowns in TGTU section:
•
Combustion air block valve 91-XV-1306 to RGG closes
•
Fuel gas block valve 91-XV-1303 to RGG closes
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•
Fuel gas vent valve 91-XV-1308 to RGG opens
•
Fuel gas block valve 91-XV-1304 to RGG closes
•
Steam block valve 91-XV-1305 to RGG closes
•
Nitrogen purge block valve 91-XV-1307 to RGG opens
•
Nitrogen purge block valve 91-XV-1301 to RGG opens
•
Instrument air purge block valve 91-XV-1302 to RGG closes
•
De-super heater Circulation Pump 9102-P-11A/B trip
•
Cooling Water Circulation Pump 9102-P-12A/B trip
•
Combustion Air Blowers 9102-K-11A/B is trip
•
Contact Condenser Cooler Fans trip
•
Tail gas bypass block valve 91-XV-1331 to Incinerator opens
•
Tail gas block valve 91-XV-1332 to Contact Condenser closes
•
Sour Water Stripper 6922-C-01 overhead block valve 69 XV 1313 closes
11.2.3.4 ESD–Level 3 Shutdown in TGTU System
Following are the causes which initiates ESD-3 shutdown in TGTU:
•
Activation of RGG burner manual shutdown pushbutton 91-HS-1336 at NGL-3
CCR
•
Activation of RGG burner manual shutdown pushbutton 91-HS-1404 at local
•
RGG burner flame detection failure alarm 91-BALL-1304
•
Combustion air flow to RGG low low alarm 91-FALL-1309
•
Fuel gas pressure to RGG high high alarm 91-PAHH-1303
•
Fuel gas pressure to RGG low low alarm 91-PALL-1305
•
RGG process outlet gas temperature high high alarm 91-TAHH-1305
•
Combustion air to RGG high high pressure alarm 91-PAHH-1341
•
Reactor Effluent Cooler level low low alarm 91-LALL-1309
Above mentioned ESD level -3 shutdown causes closes the following valves in TGTU:
•
Combustion air block valve 91-XV-1306 to RGG burner
•
Fuel gas block valve 91-XV-1303 to RGG burner
•
Fuel gas block valve 91-XV-1304 to RGG burner
•
Steam block valve 91-XV-1305 to RGG burner
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•
Instrument air purge block valve 91-XV-1302 to RGG instruments
•
Tail gas to Contact Condenser valve 91-XV-1332
•
Sour Water Stripper Overhead valve69-XV-1313
Above mentioned ESD level-3 shutdown causes opens the following valves in TGTU:
•
Fuel gas vent valve 91-XV-1308 from RGG
•
Nitrogen purge block valve 91-XV-1307 to RGG burner
•
Nitrogen purge block valve 91-XV-1301 to RGG instruments
•
Tail gas bypass valve 91-XV-1331 to Incinerator
Also above mentioned ESD level-3 shutdown causes trips the Combustion Air Blower’s
9102-K-11A/B in TGTU.
ESD level-3 is also activated by pressing emergency pushbutton 91-HS-1011 in CCR.
Following are the effects of above shutdown in TGTU section:
•
Combustion air block valve 91-XV-1306 to RGG closes
•
Fuel gas block valve 91-XV-1303 to RGG closes
•
Fuel gas vent valve 91-XV-1308 to RGG opens
•
Fuel gas block valve 91-XV-1304 to RGG closes
•
Steam block valve 91-XV-1305 to RGG closes
•
Nitrogen purge block valve 91-XV-1307 to RGG opens
•
Nitrogen purge block valve 91-XV-1301 to RGG opens
•
Instrument air purge block valve 91-XV-1302 to RGG closes
•
De-super heater Circulation Pump 9102-P-11A/B trip
•
Cooling Water Circulation Pump 9102-P-12A/B trip
•
Combustion Air Blowers 9102-K-11A/B is trip
•
Contact Condenser Cooler Fans trip
•
Tail gas bypass block valve 91-XV-1331 to Incinerator opens
•
Tail gas block valve 91-XV-1332 to Contact Condenser closes
•
Sour Water Stripper 6922-C-01 overhead block valve 69 XV-1313 closes
•
Combustion Air Blowers 9102-K-11A/B trip
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11.2.3.5 ESD–Level 4 Shutdown in TGTU System
Following are the ESD-4 shutdowns (equipment wise) in TGTU:
Contact Condenser:
•
Low low level alarm (91-LALL-1306) in de-super heater/contact condenser
bottom trips the de-super heater circulation pumps 9102-P-11A/B
•
De-super heater/contact condenser bottom water circulation low low flow
alarm (91-FALL-1306) trips the de-super heater circulation pumps 9102-P-11A/B
•
Low low level alarm (91-LALL-1304) in De-super Heater/Contact Condenser
water draw off tray trips the Cooling Water Circulation Pumps 9102-P-12A/B
•
Low low cooling water circulation flow alarm (91-FALL-1316) trips the Cooling
Water Circulation Pumps 9102-P-12A/B
•
De-super Heater Condenser Cooler Fans 9102-E-12AA to 9102-E-12BC trips due
to high high vibration alarms sensed by their respective cooler vibration
probes.
Detail list of coolers and vibration alarms are as listed below:
Vibration Tag No.
Cooler Tag No.
91-VAHH-1301
9102-EM-12AA
91-VAHH-1302
9102-EM-12AB
91-VAHH-1303
9102-EM-12AC
91-VAHH-1504
9102-EM-12BA
91-VAHH-1307
9102-EM-12BB
91-VAHH-1308
9102-EM-12BC
RGG (9102-F-11) Combustion Blower
Combustion air blower 9102-K-11A trips due to the following causes:
Tag No.
Description
91-VAHH-1457
High high radial vibration alarm
91-ZAHH-1451
High high axial vibration alarm
91-VAHH-1451
High high vibration alarm in motor bearing DE side
91-VAHH-1456
High high vibration alarm in motor bearing NDE side
91-TAHH-1451
High high temperature alarm in compressor bearing
91-TAHH-1452
High high temperature alarm in bull gear bearing
91-PALL-1459
Low low lube oil pressure alarm
91-TAHH-1459
High high lube oil temperature alarm
91-PALL-1460
Low low seal air pressure alarm
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Tag No.
Description
91-TAHH-1453
High high discharge air temperature alarm
91-HS-1453
Emergency stop pushbutton
91-TAHH-1460
High high lube oil return line temperature alarm
91-PDAHH-1461
High high differential pressure alarm
91-TAHH-1473
High high lube oil reservoir temperature alarm
91-VAHH-1458
High high radial vibration alarm
91-TAHH-1457
High high temperature alarm in thrust bearing
91-VAHH-1454
High high vibration alarm in compressor lube oil cooler fan-1
91-VAHH-1455
High high vibration alarm in compressor lube oil cooler fan-1
91-TAHH-1471
High high temperature alarm in motor DE bearing
91-TAHH-1472
High high temperature alarm in blower motor NDE bearing
Combustion Air Blower 9102-K-11B trips due to the following causes:
Tag No.
Description
91-VAHH-1717
High high radial vibration alarm
91-ZAHH-1711
High high axial vibration alarm
91-VAHH-1711
High high vibration alarm in motor bearing DE side
91-VAHH-1716
High high vibration alarm in motor bearing NDE side
91-TAHH-1711
High high temperature alarm in compressor bearing
91-TAHH-1712
High high temperature alarm in bull gear bearing
91-PALL-1719
Low low lube oil pressure alarm
91-TAHH-1459
High high lube oil temperature alarm
91-PALL-1720
Low low seal air pressure alarm
91-TAHH-1713
High high discharge air temperature alarm
91-HS-1713
Emergency stop pushbutton
91-TAHH-1720
High high lube oil return line temperature alarm
91-PDAHH-1721
High high differential pressure alarm
91-TAHH-1733
High high lube oil reservoir temperature alarm
91-VAHH-1716
High high radial vibration alarm
91-TAHH-1717
High high temperature alarm in thrust bearing
91-VAHH-1714
High high vibration alarm in compressor lube oil cooler fan-1
91-VAHH-1715
High high vibration alarm in compressor lube oil cooler fan-1
91-TAHH-1731
High high temperature alarm in motor DE bearing
91-TAHH-1732
High high temperature alarm in blower motor NDE bearing
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11.2.4
Incinerator
11.2.4.1 ESD Level 0 Shutdown in Incinerator system
ESD level-0 activated by pressing emergency pushbutton 65-HS-4001 in CCR, directly
trips the Incinerator through UCP.
11.2.4.2 ESD Level 1 Shutdown in Incinerator system
ESD level 1 shutdown is activated on the following causes:
•
Fire detection alarm (91-XS-01-1801) from AGEU/TGTU unit (LER-4)
•
Fire detection alarm (91-XS-02-1801) from Incinerator area (LER-4)
•
Fire detection alarm (68-XS-02-1801) from Utility area (LER-6)
•
Fire detection alarm (68-XS-03-1801) from Utility Boiler area (LER-6)
•
Fire detection alarm (66-XS-01-1801) from New Substation area
•
Fire detection alarm (66-XS-03-1801) from LER-6
•
Flammable gas detection alarm (91-XS-01-1802) from AGEU/TGTU unit (LER-4)
•
Flammable gas detection alarm (91-XS-02-1802) Incinerator area (LER-4)
•
Flammable gas detection alarm (68-XS-02-1802) from Utility area (LER-6)
•
Flammable gas detection alarm (68-XS-03-1802) from Utility boiler area (LER-6)
•
Flammable gas detection alarm (66-XS-03-1802) from LER-6
•
Flammable gas detection alarm (66-XS-01-1802) from New Substation area
•
Activation of ESD Level-1 shutdown pushbutton 65-HS-001 in CCR
All the above mentioned ESD Level-1 causes directly trips the Incinerator through UCP.
11.2.4.3 ESD Level 2 Shutdown in Incinerator system
ESD Level 2 Shutdown is activated by the following causes:
•
Total power failure signal (65-XS-1024)
•
Instrument air pressure low low (2oo3) alarm 65-PALL-1003
•
Instrument air pressure 2oo3 low low alarm (68-PALL-1312A/B/C)
•
Activation of ESD-2 shutdown pushbutton 61-HS-006 in CCR
All the above mentioned ESD Level-2 causes directly trips the Incinerator through UCP.
Also incinerator is tripped due to the activation of Incinerator manual shutdown
pushbutton 91-HS-1169 in CCR.
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11.2.4.4 Incinerator Emergency Shutdown from UCP
UCP checks all trip and alarm condition for healthy status before start-up and during
operation. Alarm conditions are flagged on display of UCP but the Incinerator remains
running. Trip conditions initiate a shutdown and a reset is required before the unit is
available.
Following are the causes that initiates the Incinerator trip action in UCP:
•
Remote ESD signal 91-XS-1185
•
Local ESD (PB on LCP) 91-HS-1167
•
Combustion Air flow Low low alarm 91-FALL-1156B
•
Fuel gas to burner pressure Low low alarm 91-PALL-1155
•
Fuel gas to burner pressure Low low alarm 91-PALL-1156
•
Fuel gas to burner pressure High high alarm 91-PAHH-1156
•
Flame fail (2oo3) alarm 91-BSLL-1155
•
Incinerator Temperature high high alarm 91-TAHH-1160
Following are the effects of trips in Incinerator:
•
Fuel gas control valve 91-FV-1155 at low fire position
•
Fuel gas upstream block valve (91-XV-1155) in close position
•
Fuel gas vent valve (91-XV-1156) in open position
•
Fuel gas downstream block valve (91-XV-1157) in close position
•
Pilot gas upstream block valve (91-XV-1158) in close position
•
Pilot gas vent valve (91-XV-1159) in open position
•
Fuel gas downstream block valve (91-XV-1160) in close position
•
After 15 minutes air supply valve (91-XV-1161) will close
Note: Blower’s 9101-K-12A/B to be stopped manually.
Local ESD pushbutton (91-HS-1167) and remote ESD signal (91-XS-1185) shutdown the
blowers directly.
Also above mentioned causes in UCP initiates ESD Level-2 trip signal to 91-XS-1186 to
plant ESD system.
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11.3
11.3.1
UTILITIES
Steam Generation System
11.3.1.1 ESD Level 0 Shutdown in Steam Generator Package
ESD level-0 activated by pressing emergency pushbutton 65-HS-4001 in CCR, directly
trips all the running Steam Generation Packages (6848-A02A/B/C) through UCP.
11.3.1.2 ESD Level 1 Shutdown in Steam Generator Package
ESD level1 is activated on the following causes:
•
Activation of ESD Level-1 shutdown pushbutton 65-HS-001 in CCR
•
Fire detection alarm (91-XS-01-1801) from AGEU/TGTU unit (LER-4)
•
Fire detection alarm (91-XS-01-1801) from AGEU/TGTU unit (LER-4)
•
Fire detection alarm (91-XS-02-1801) from Incinerator area (LER-4)
•
Fire detection alarm (68-XS-02-1801) from Utility area (LER-6)
•
Fire detection alarm (68-XS-03-1801) from Utility boiler area (LER-6)
•
Fire detection alarm (66-XS-01-1801) from New Substation area
•
Fire detection alarm (66-XS-03-1801) from LER-6
•
Flammable gas detection alarm (91-XS-01-1802) from AGEU/TGTU unit (LER-4)
•
Flammable gas detection alarm (91-XS-02-1802) Incinerator area (LER-4)
•
Flammable gas detection alarm (68-XS-02-1802) from Utility area (LER-6)
•
Flammable gas detection alarm (68-XS-03-1802) from Utility boiler area (LER-6)
•
Flammable gas detection alarm (66-XS-03-1802) from LER-6
•
Flammable gas detection alarm (66-XS-01-1802) from New Substation area
All the above mentioned ESD Level-1 causes directly trips all the running Steam
Generation Packages (6848-A02A/B/C) through UCP.
11.3.1.3 ESD Level 2 Shutdown in Steam Generator Package
ESD Level 2 Shutdown is activated by the following causes:
•
Total power failure signal (65-XS-1024)
•
Instrument air pressure low low (2oo3) alarm 65-PALL-1003
•
Instrument air pressure 2oo3 low low alarm (68-PALL-1312A/B/C)
•
Activation of ESD level-2 shutdown pushbutton 61-HS-006
•
Fuel gas header pressure high high alarm 62-PAHH-1304
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All the above mentioned ESD Level-2 causes directly trips all the running Steam
Generation Packages (6848-A02A/B/C) through UCP.
11.3.1.4 ESD Level 3 Shutdown in Steam Generator Package
•
Activation of Manual Shutdown pushbutton 68-HS-1580 from CCR console trips the
Steam Generation Package6848-A02A.
•
Activation of Manual Shutdown pushbutton 68-HS-1680 from CCR console trips the
Steam Generation Package6848-A02B.
•
Activation of Manual Shutdown pushbutton 68-HS-1780 from CCR console trips the
Steam Generation Package6848-A02B.
•
Main LP steam header pressure low low alarm 68-PALL-1303A/B/C and De-aerator
level low low alarm 68-LALL-1310 trips all the running Steam Generation Packages
(6848-A02A/B/C) through UCP.
11.3.1.5 Steam Generator Package Trip through UCP Causes
Emergency trip causes in UCP are given below:
Sl. #
Description
Tag No.
1
Combustion chamber pressure high-high
68-PAHH-1528A/B/C
2
Boiler level low low
68-LALL-1523A/B/C
3
Boiler level high high
68-LAHH-1523A/B/C
4
Saturated steam pressure high-high
68-PAHH-1522A/B/C
5
Upstream burner gas pressure low-low
68-PALL-1525A/B/C
6
Downstream burner gas pressure high-high
68-PAHH-1526A/B/C
7
Combustion air flow low-low
68-FALL-1526B/C/D
8
Natural gas flow High-High
68-FAHH-1525B/C/D
9
Instrument air pressure low-low
68-PALL-1527A/B/C
10
ESD from boiler control panel
68-HS-1523
11
ESD from boiler local control panel
68-HS-1524
12
Emergency shutdown
68-HS-1525
13
Forced draft fan not running
68-ZI-1548
14
Emergency shutdown from ESD
68-XS-1327
If a trip condition is present, an emergency shutdown is performed and burners will
not be allowed to restart until the cause is recognized and corrective actions are taken
for logic reset.
During the ESD trip the following actions are performed:
•
Close main burner shut-off valve 68-XV-1528 & open vent valve 68 XV-1530
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•
Close igniters main shut-off valve 68-XV-1531if the pilot is lighted
•
Perform a boiler post firing purge
Note: only Steam Generation Package 6848-A02A tags are considered.
11.3.2
Boiler Feed Water System
Equipment in this ESD Zone is as follows:
•
Steam Condensates Flash Drum (6834-V-05)
•
De-aerator Feed Pumps (6834-P-20A/B)
•
Steam Condensate Coolers (6834-E-02)
•
BFW De-aerator Package (6834-A-08)
•
Boiler Feed Water Pumps (6834-P-22A/B/C)
•
Steam Generation Package (6848-A-02A/B/C)
•
Boiler Blow Down Pit (6848-T-02)
•
Drinking Water Pumps (6834-P-23A/B)
•
BFW Chemical Injection Package (6834-A-09)
11.3.2.1 ESD Level 0 Shutdown in Boiler Feed Water System
ESD level-0 is activated only by pressing emergency pushbutton 65-HS-4001 in CCR.
Following are the effects of ESD Level 0 Shutdowns in Heating System:
•
Boiler 6848-A-02A fuel gas ON/OFF valve 68-XV-1302 close
•
Boiler 6848-A-02A fuel gas ON/OFF valve 68-XV-1303 close
•
Boiler 6848-A-02A fuel gas ON/OFF valve 68-XV-1304 close
•
Drinking Water Pumps (68-P-23A/B) trip
•
DM Water Feed Pumps (68-P-24A/B) trip
•
De-aerator Feed Pumps (68-P-20A/B) trip
•
Steam Condensate Coolers trip
•
Boiler Feed Water Pumps 68-P-22A/B/C trip
•
De aerator inlet ESD valve 68-XV-1301 close
11.3.2.2 ESD Level 1 Shutdown in Boiler Feed Water System
ESD level 1 is activated on the following causes:
•
Fire detection alarm (91-XS-01-1801) from AGEU/TGTU unit (LER-4)
•
Fire detection alarm (91-XS-02-1801) from Incinerator area (LER-4)
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•
Fire detection alarm (68-XS-02-1801) from Utility Area (LER-6)
•
Fire detection alarm (68-XS-03-1801) from Utility Boiler area (LER-6)
•
Fire detection alarm (66-XS-01-1801) from New Substation area
•
Fire detection alarm (66-XS-03-1801) from LER-6
•
Flammable gas detection alarm (91-XS-01-1802) from AGEU/TGTU unit (LER-4)
•
Flammable gas detection alarm (91-XS-02-1802) Incinerator area (LER-4)
•
Flammable gas detection alarm (68-XS-02-1802) from Utility area (LER-6)
•
Flammable gas detection alarm (68-XS-03-1802) from Utility boiler area (LER-6)
•
Flammable gas detection alarm (66-XS-03-1802) from LER-6
•
Flammable gas detection alarm (66-XS-01-1802) from New substation area
•
Activation of ESD Level-1 shutdown pushbutton 65-HS-001 in CCR
Following are the effects of ESD Level 1 Shutdowns in Heating System:
•
Boiler 6848-A-02A fuel gas ON/OFF valve 68-XV-1302 close
•
Boiler 6848-A-02A fuel gas ON/OFF valve 68-XV-1303 close
•
Boiler 6848-A-02A fuel gas ON/OFF valve 68-XV-1304 close
•
DM Water Feed Pumps (68-P-24A/B) trip
•
De-aerator Feed Pumps (68-P-20AA/B) trip
•
Steam Condensate Coolers trip
•
De aerator inlet ESD valve 68-XV-1301 close
•
Boiler Feed Water Pumps 68-P-22A/B/C trip
11.3.2.3 ESD Level 2 Shutdown in Boiler Feed Water System
ESD Level 2 Shutdown is activated by the following causes:
•
Total power failure signal (65-XS-1024)
•
Instrument air pressure low low (2oo3) alarm 65-PALL-1003
•
Instrument air pressure 2oo3 low low alarm (68-PALL-1312A/B/C)
•
Activation of ESD level-2 shutdown pushbutton 61-HS-006
•
Steam Generation Packages trip (68-XS-1580/68-XS-1680/68-XS-1780)
Following are the effects of ESD Level 2 Shutdowns in Heating System:
•
Boiler 6848-A-02A fuel gas ON/OFF valve 68-XV-1302 close
•
Boiler 6848-A-02A fuel gas ON/OFF valve 68-XV-1303 close
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•
Boiler 6848-A-02A fuel gas ON/OFF valve 68-XV-1304 close
•
DM Water Feed Pumps (68-P-24A/B) trip
•
De aerator Feed Pumps (68-P-20A/B) trip
•
Steam Condensate Coolers trip
•
De aerator inlet ESD valve 68-XV-1301 close
•
Boiler Feed Water Pumps 68-P-22A/B/C trip
11.3.2.4 ESD Level 3 Shutdown in Boiler Feed Water System
1. Main LP steam header pressure low low alarm 68-PALL-1303A/B/C and de-aerator
level low low alarm 68-LALL-1310 causes the following effects in heating system:
•
Boiler 6848-A-02A fuel gas ON/OFF valve 68-XV-1302 close
•
Boiler 6848-A-02A fuel gas ON/OFF valve 68-XV-1303 close
•
Boiler 6848-A-02A fuel gas ON/OFF valve 68-XV-1304 close
•
De aerator feed pumps (68-P-20A/B) trip
•
Steam Condensate Coolers trip
•
De-aerator inlet ESD valve 68-XV-1301 close
•
Boiler Feed Water Pumps 68-P-22A/B/C trip
2. Steam Generation Package 6848-A-02A trip signal 68-XS-1580 closes the Boiler
6848-A-02A fuel gas ON/OFF valve 68-XV-1302
3. Steam Generation Package 6848-A-02B trip signal 68-XS-1680 closes the Boiler
6848-A-02B fuel gas ON/OFF valve 68-XV-1303.
4. Steam Generation Package 6848-A-02C trip signal 68-XS-1780 closes the Boiler
6848-A-02C fuel gas ON/OFF valve 68-XV-1304.
11.3.2.5 ESD Level 4 Shutdown in Boiler Feed Water System
Following are the ESD-4 shutdowns (equipment wise) in BFW/Steam Generation
Packages:
Steam Condensate Coolers
•
High high vibration alarm 68-VAHH-1301 in steam condensate cooler 6834-E-02A
trips the steam condensate cooler motor 6834-EM-2A1
•
High high vibration alarm 68-VAHH-1302 in steam condensate cooler 6834-E-02A
trips the steam condensate cooler motor 6834-EM-2A2
•
High high vibration alarm 68-VAHH-1303 in steam condensate cooler (6834-E-02B
trips the steam condensate cooler motor 6834-EM-2B1
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•
High high vibration alarm 68-VAHH-1304 in steam condensate cooler 6834-E-02B
trips the steam condensate cooler motor 6834-EM-2AB2
•
High high vibration alarm 68-VAHH-1305 in steam condensate cooler 6834-E-02C
trips the steam condensate cooler motor 6834-EM-2C1
•
High high vibration alarm 68-VAHH-1306 in steam condensate cooler 6834-E-02C
trips the steam condensate cooler motor 6834-EM-2C.
Drinking Water
•
Low low level alarm 68-LALL-006 in existing Drinking Water Storage Tank 6834-T01A trips the Drinking Water Pumps 6834-P-23A/B.
•
Low low level alarm 68-LALL-007 in existing Drinking Water Storage Tank 6834-T01B trips the Drinking Water Pumps 6834-P-23A/B.
•
Low low level alarm 68-LALL-1307 in DMW storage tank 6834-T-08 trips the DMW
Water Feed Pumps 6834-P-24A/B.
•
High high level alarm 68-LAHH-1306 in DMW storage tank 6834-T-08 trips the DMW
package.
Steam Condensate Flash Drum
•
Low low level alarm 68-LALL-1309 in Steam Condensate Flash Drum 6834-V-05 trips
the De-aerator Water Feed Pumps 6834-P-20A/B.
•
High high level alarm 68-LAHH-1308 in Steam Condensate Flash Drum 6834-V-05
trips the DMW Water Feed Pumps 6834-P-24A/B.
BFW De-aerator Package
High high level alarm 68-LAHH-1312 in BFW De-aerator Package 6834-A-08 closes the
De-aerator inlet ESD valve 68-XV-1301.
11.3.3
DM water system
11.3.3.1 ESD Level 0 Shutdown in DM water package
ESD level-0 is activated by pressing emergency pushbutton 65-HS-4001 in CCR which
directly trips the DM water package through UCP.
11.3.3.2 ESD Level 1 Shutdown in DM Water Package
ESD level1 is activated on the following causes:
•
Activation of ESD Level-1 shutdown pushbutton 65-HS-001 in CCR
•
Fire detection alarm (91-XS-01-1801) from AGEU/TGTU unit (LER-4)
•
Fire detection alarm (91-XS-01-1801) from AGEU/TGTU unit (LER-4)
•
Fire detection alarm (91-XS-02-1801) from Incinerator area (LER-4)
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•
Fire detection alarm (68-XS-02-1801) from Utility area (LER-6)
•
Fire detection alarm (68-XS-03-1801) from Utility boiler area (LER-6)
•
Fire detection alarm (66-XS-01-1801) from New substation area
•
Fire detection alarm (66-XS-03-1801) from LER-6
•
Flammable gas detection alarm (91-XS-01-1802) from AGEU/TGTU unit (LER-4)
•
Flammable gas detection alarm (91-XS-02-1802) Incinerator area (LER-4)
•
Flammable gas detection alarm (68-XS-02-1802) from utility area (LER-6)
•
Flammable gas detection alarm (68-XS-03-1802) from utility boiler area (LER-6)
•
Flammable gas detection alarm (66-XS-03-1802) from LER-6
•
Flammable gas detection alarm (66-XS-01-1802) from New Substation Area
All the above mentioned ESD Level-1 causes directly trips the running DM water
package through UCP.
11.3.3.3 ESD Level 2 Shutdown in DM Water Package
ESD Level 2 Shutdown is activated by the following causes:
•
Total power failure signal (65-XS-1024)
•
Instrument air pressure low low (2oo3) alarm 65-PALL-1003
•
Instrument air pressure 2oo3 low low alarm (68-PALL-1312A/B/C)
•
Activation of ESD level-2 shutdown pushbutton 61-HS-006
All the above mentioned ESD Level-2 causes directly trips the DM water package
through UCP.
11.3.3.4 ESD Level 4 Shutdown in DM Water Package
ESD Level 4 Shutdown is activated by the following causes:
•
DM Water Storage Tank level low low alarm (68-LALL-1307)
•
DM Water Storage Tank level high high alarm (68-LAHH-1306)
All the above mentioned ESD Level-4 causes directly trips the DM Water Package
through UCP.
11.3.3.5 DM Water Package Trip through UCP Causes
•
Low low Level alarm 68-LALL-1825 in Acid Storage Tank 6834-T-16 trips the Acid
Dosing Pump 6834-P-35A/B/C in DM water package
•
Low low Level alarm 68-LALL-1827 in Caustic Storage Tank 6834-T-15 trips the
Caustic Dosing Pump 6834-P-34A/B/C in DM water package
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•
Low low Level alarm 68-LALL-1830 in Neutralisation Pit 6834-A-01 trips the
Neutralisation Pump 6834-P-38A/B in DM water package
•
Low low Level 68-LALL-1307 in De-mineralized Water Storage Tank 6834 T-08 trips
the following in DM water package:
•
Regeneration Pumps 6834-P-36A/B
•
Acid Dosing Pumps 6834-P-35A/B
•
Caustic Dosing Pump 6834-P-34A/B
•
High Conductivity Concentration 68-AHH-1829 in outlet of De mineralized Water
and trip the De mineralized Package 6834-A-07
•
High Silica Concentration 68-AHH-1830 in outlet of De mineralized Water trips the
De-mineralized Package 6834-A-07
•
Recycling Pump 6834-P-37A discharge flow low low alarm 68-FALL-1837 trips the
Recycling Pump 6834-P-37A
•
Recycling Pump 6834-P-37B discharge flow low low alarm 68-FALL-1838 trips the
Recycling Pump 6834-P-37B
•
Regeneration Pump 6834-P-36A/B discharge flow low low alarm 68-FALL-1839 trips
the following:
1. Regeneration Pump 6834-P-36A/B
2. Acid Dosing Pump 6834-P-35A/B
3. Caustic Dosing Pump 6834-P-34A/B
DM Package flow low low alarm 68-FALL-1830 trips recycling Pump 6834-P-37A/B.
11.3.4
Chemical Injection System
Equipment in this ESD Zone is as follows:
•
Complex Product Tank (6834-T-18)
•
Complex Product Pumps (6834-P-41A/B)
•
Oxygen Scavenger Tank (6834-T-17)
•
Oxygen Scavenger Pumps (6834-P-39A/B)
•
Corrosion Inhibitor Tank (9103-T-13)
•
Corrosion Inhibitor Pumps (9103-P-101A/B)
•
Caustic Injection Tank (9103-T-14)
•
Caustic Injection Pumps (9103-P-103A/B)
•
Antifoam Injection Tank (9103-T-12)
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•
Antifoam Injection Pumps (9103-P-16A/B)
•
Catalyst Injection Pumps (9101-P-01A/B)
11.3.4.1 ESD Level 0 Shutdown in Chemical Injection System
ESD level-0 is activated only by pressing emergency pushbutton 65-HS-4001 in CCR.
Following are the effects of ESD Level 0 Shutdowns in chemical injection system:
•
Complex Product Pumps (6834-P-41A/B)
•
Complex Product Tank Agitator (6834-M-04)
•
Oxygen Scavenger Injection Pumps (6834-P-39A/B)
•
Oxygen Scavenger Product Tank Agitator (6834-M-03)
•
Corrosion Inhibitor Tank Agitator (9103-M-13)
•
Corrosion Inhibitor Pumps (9103-P-101A/B)
•
Caustic Injection Pumps (9103-P-103A/B)
•
Caustic Injection Tank Agitator (9103-M-14)
•
Antifoam Injection Pumps (9103-P-16A/B)
•
Antifoam Injection Tank Agitator (9103-M-12)
•
Catalyst Injection Pump (9101-P-01A/B)
11.3.4.2 ESD Level 1 Shutdown in Chemical Injection System
ESD level1 is activated on the following causes:
•
Activation of ESD Level-1 shutdown pushbutton 65-HS-001 in CCR
•
Fire detection alarm (91-XS-01-1801) from AGEU/TGTU unit (LER-4)
•
Fire detection alarm (91-XS-01-1801) from AGEU/TGTU unit (LER-4)
•
Fire detection alarm (91-XS-02-1801) from Incinerator area (LER-4)
•
Fire detection alarm (68-XS-02-1801) from utility area (LER-6)
•
Fire detection alarm (68-XS-03-1801) from utility boiler area (LER-6)
•
Fire detection alarm (66-XS-01-1801) from new substation area
•
Fire detection alarm (66-XS-03-1801) from LER-6
•
Flammable gas detection alarm (91-XS-01-1802) from AGEU/TGTU unit (LER-4)
•
Flammable gas detection alarm (91-XS-02-1802) Incinerator area (LER-4)
•
Flammable gas detection alarm (68-XS-02-1802) from utility area (LER-6)
•
Flammable gas detection alarm (68-XS-03-1802) from utility boiler area (LER-6)
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•
Flammable gas detection alarm (66-XS-03-1802) from LER-6
•
Flammable gas detection alarm (66-XS-01-1802) from new substation area
Following are the effects of ESD Level 1 Shutdowns in chemical injection system:
•
Complex Product pumps (6834-P-41A/B)
•
Complex Product Tank Agitator (6834-M-04)
•
Oxygen Scavenger Injection Pumps (6834-P-39A/B)
•
Oxygen Scavenger Product Tank Agitator (6834-M-03)
•
Corrosion Inhibitor Tank Agitator (9103-M-13)
•
Corrosion inhibitor Pumps (9103-P-101A/B)
•
Caustic Injection Pumps (9103-P-103A/B)
•
Caustic injection Tank Agitator (9103-M-14)
•
Antifoam injection Pumps (9103-P-16A/B)
•
Antifoam Injection Tank Agitator (9103-M-12)
•
Catalyst Injection Pump (9101-P-01A/B)
11.3.4.3 ESD Level 2 Shutdown in Chemical Injection System
ESD Level 2 Shutdown is activated by the following causes in chemical injection
systems:
•
Total power failure signal (65-XS-1024)
•
Instrument air pressure low low (2oo3) alarm 65-PALL-1003
•
Instrument air pressure 2oo3 low low alarm (68-PALL-1312A/B/C)
•
Activation of ESD level-2 shutdown pushbutton 61-HS-006
Following are the effects of ESD Level 2 Shutdowns in Chemical Injection System:
•
Complex Product Pumps (6834-P-41A/B)
•
Complex Product Tank Agitator (6834-M-04)
•
Oxygen Scavenger Injection pumps (6834-P-39A/B)
•
Oxygen Scavenger Product Tank Agitator (6834-M-03)
•
Corrosion Inhibitor Tank Agitator (9103-M-13)
•
Corrosion Inhibitor Pumps (9103-P-101A/B)
•
Caustic Injection Pumps (9103-P-103A/B)
•
Caustic Injection Tank Agitator (9103-M-14)
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•
Antifoam Injection Pumps (9103-P-16A/B)
•
Antifoam Injection Tank Agitator (9103-M-12)
•
Catalyst Injection Pump (9101-P-01A/B)
11.3.4.4 ESD–Level 3 Shutdown in Chemical Injection System
Following are the ESD-3 shutdowns in Chemical Injection Package:
Complex Product
Low low level alarm (68-LALL-1316) in Complex Product Tank trips the Complex Product
Injection Pumps (6834-P-41A/B) and Complex Product Tank Agitator (6834-M-04)
Oxygen Scavenger
Low low level alarm (68-LALL-1315) in Oxygen Scavenger Tank 6834-T17 trips the
Oxygen Scavenger Injection Pumps (6834-P-39A/B) and Oxygen Scavenger Product Tank
Agitator (6834-M-03)
Corrosion Inhibitor
Low low level alarm (91-LALL-1522) in Corrosion Inhibitor Tank 9103-T-13 trips the
Corrosion Inhibitor Pumps (9103-P-101A/B) and Corrosion Inhibitor Tank Agitator
(9103-M-13)
Caustic Injection
Low low level alarm (91-LALL-1524) in Caustic Injection Tank 9103-T-14 trips the Caustic
Injection Pumps (9103-P-103A/B) and Caustic Injection Tank Agitator (9103-M-14)
Antifoam Injection
Low low level alarm (91-LALL-1520) in Antifoam Injection Tank 9103-T-12 trips the
Antifoam Injection Pumps (9103-P-16A/B) and Antifoam Injection Tank Agitator
(9103-M-12)
Catalyst Injection
Low low level alarm (91-LALL-1128) in Catalyst Injection Tank 9101-T-901 trips the
Antifoam Injection Pumps (9103-P-16A/B)
11.3.4.5 ESD–Level 4 Shutdown in Chemical Injection System
Following are the ESD-4 shutdowns (equipment wise) in Chemical Injection Package:
Complex Product
•
Low low level alarm (68-LALL-1316) in complex product tank trips the Complex
Product Pumps (6834-P-41A/B)
•
High high diaphragm pressure alarm (68-PAHH-1326) in Complex Product Injection
Pump 6834-P-41A trips the pump
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•
High high diaphragm pressure alarm (68-PAHH-1327) in Complex Product Injection
Pump 6834-P-41B trips the pump
Oxygen Scavenger
•
Low low level alarm (68-LALL-1315) in Oxygen Scavenger Tank 6834-T17 trips the
Oxygen Scavenger Injection Pumps (6834-P-39A/B)
•
High high diaphragm pressure alarm (68-PAHH-1324) in Oxygen Scavenger Injection
Pump 6834-P-39A trips the pump
•
High high diaphragm pressure alarm (68-PAHH-1325) in Oxygen Scavenger Injection
Pump 6834-P-39B trips the pump
Corrosion Inhibitor
•
Low low level alarm (91-LALL-1522) in Corrosion Inhibitor Tank 9103-T-13 trips the
corrosion inhibitor pumps (9103-P-101A/B)
•
High high diaphragm pressure alarm (91-PAHH-1567) in Corrosion Inhibitor Pump
9103-P-101A trips the pump
•
High high diaphragm pressure alarm (91-PAHH-1568) in Corrosion Inhibitor Pump
9103-P-101B trips the pump
Caustic Injection
•
Low low level alarm (91-LALL-1524) in Caustic Injection Tank 9103-T-14 trips the
caustic injection pumps (9103-P-103A/B)
•
High high diaphragm pressure alarm (91-PAHH-1567) in Caustic Injection Pump
9103-P-103A trips the pump
•
High high diaphragm pressure alarm (91-PAHH-1568) in Caustic Injection Pump
9103-P-103B trips the pump
Antifoam Injection
•
Low low level alarm (91-LALL-1520) in Antifoam Injection Tank 9103-T-12 trips the
Antifoam Injection Pumps (9103-P-16A/B)
•
High high diaphragm pressure alarm (91-PAHH-1565) in Antifoam Injection Pump
(9103-P-16A trips the pump
•
High high diaphragm pressure alarm (91-PAHH-1566) in Antifoam Injection Pump
9103-P-16B trips the pump
Catalyst Injection
•
Low low level alarm (91-LALL-1128) in Catalyst Injection Tank 9101-T-901 trips the
Antifoam Injection Pumps (9103-P-16A/B)
•
High high diaphragm pressure alarm (91-PAHH-1128 in Catalyst Injection Pump
(9103-P-16A) trips the pump
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•
11.3.5
High high diaphragm pressure alarm (91-PAHH-1130) Catalyst Injection Pump
(9103-P-16B) trips the pump
Electro Chlorination System
Electro Chlorination System UCP trip
If an emergency Shutdown is commenced then the immediate shutdown of the
complete package takes place, without a run on time for electrolyser flushing and tank
venting.
Causes responsible for emergency shutdown are tabulated below:
Sl. #
11.3.6
Tag No.
Description
1
69-HS-1451
Emergency stop in UCP
2
69-HS-1452
Emergency stop in ECP skid
3
69-HS-1453
Emergency stop in ECP skid
4
69-XS-1336
Sea cooling water pump (6932-P-04A/B) trip
5
66-GF-02-1801
Hydrogen gas high-high alarm
6
66-GF-02-1801
Hydrogen gas high-high alarm
Sea Cooling Water System
Equipment in this ESD Zone is as follows:
•
Sea Cooling Water Pumps (6932-P-04A/B)
•
Sea Cooling Water Filters (6932-S-02A/B)
•
Electro Chlorination Package (6932-A-05)
•
Biocide Injection Package (6932-A-06)
•
Scale Inhibitor Package (6932-A-07)
•
Local Chemical Drain Pit (6932-T-01)
ESD–Level 4 shutdown in Sea Cooling Water System
Following are the ESD-4 shutdowns (equipment wise) in Sea Cooling Water System:
•
High high vibration alarm (69-VSHH-1301) in Sea Cooling water Pump 6932-P04A trips the sea cooling water pump 6932-P-04A
•
High high vibration alarm (69-VSHH-1302) in Sea Cooling Water Pump 6932-P04B trips the sea cooling water pump 6932-P-04B
Sea Cooling Water Pumps 6932-P-04A/B trip signals (69-XZA-1311/69-XZA-1322) trips
the following packages:
•
Electro chlorination Package (6932-A-05)
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11.3.7
•
Biocide Injection Package (6932-A-06)
•
Scale Inhibitor Package (6932-A-07)
Fuel Gas System
11.3.7.1 ESD Level 0 Shutdown in Fuel Gas System
ESD level-0 is activated only by pressing emergency pushbutton 65-HS-4001 in CCR.
Following are the effects of ESD Level 0 Shutdowns in Fuel Gas System:
•
Fuel gas from 1st Stage Booster Compressor ON/OFF valve 62-XV-1301 close
•
Fuel gas from 6103-K-01A/B ON/OFF valve 62-XV-1302 close
•
Fuel gas from 30” existing main line inlet ON/OFF valve 62-XV-1303 close
11.3.7.2 ESD Level 1 Shutdown in Fuel Gas System
ESD level1 is activated on the following causes:
•
Activation of ESD Level-1 shutdown pushbutton 65-HS-001 in CCR
•
Fire detection alarm (91-XS-01-1801) from AGEU/TGTU unit (LER-4)
•
Fire detection alarm (91-XS-01-1801) from AGEU/TGTU unit (LER-4)
•
Fire detection alarm (91-XS-02-1801) from Incinerator area (LER-4)
•
Fire detection alarm (68-XS-02-1801) from utility area (LER-6)
•
Fire detection alarm (68-XS-03-1801) from utility boiler area (LER-6)
•
Fire detection alarm (66-XS-01-1801) from new substation area
•
Fire detection alarm (66-XS-03-1801) from LER-6
•
Flammable gas detection alarm (91-XS-01-1802) from AGEU/TGTU unit (LER-4)
•
Flammable gas detection alarm (91-XS-02-1802) Incinerator area (LER-4)
•
Flammable gas detection alarm (68-XS-02-1802) from utility area (LER-6)
•
Flammable gas detection alarm (68-XS-03-1802) from utility boiler area (LER-6)
•
Flammable gas detection alarm (66-XS-03-1802) from LER-6
•
Flammable gas detection alarm (66-XS-01-1802) from new substation
Following are the effects of ESD Level 1 Shutdowns in fuel gas system:
•
Fuel gas from 1st Stage Booster Compressor ON/OFF valve 62-XV-1301 close
•
Fuel gas from 6103-K-01A/B ON/OFF valve 62-XV-1302 close
•
Fuel gas from 30” existing main line inlet ON/OFF valve 62-XV-1303 close
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11.3.7.3 ESD Level 2 Shutdown in Fuel gas system
ESD level2 is activated by high high fuel gas header pressure alarm 62-PAHH-1304 and
following are the effects of level-2 shutdown:
11.3.8
•
Fuel gas from 1st Stage Booster Compressor ON/OFF valve 62-XV-1301 close
•
Fuel gas from 6103-K-01A/B ON/OFF valve 62-XV-1302 close
•
Fuel gas from 30” existing main line inlet ON/OFF valve 62-XV-1303 close
Effluent Waste Water System
Equipment in this ESD Zone is as follows:
•
Waste Water Degasser (6922-V-07)
•
Sour Water Filter (6922-S-06)
•
Sour/stripped Water Exchanger (6922-E-01)
•
Stripped Water Cooler (6922-E-02)
•
Sour water Stripper (6922-C-01)
•
Sour water Stripper Re-boiler (6922-E-04)
•
Stripper Overheads Cooler (6922-E-03)
•
Re-boiler Condensate Drums (6922-V-09)
•
De-super Heater (6922-X-01)
•
Waste Water Degasser Pumps (6922-P-08A/B)
•
Stripped Water Pumps (6922-P-10A/B)
•
Stripped Overhead Circulation Pumps (6922-P-11A/B)
11.3.8.1 ESD-Level 0 Shutdown in Effluent Waste Water System
ESD level-0 is activated (cause) only by pressing emergency pushbutton 65-HS-4001 in
CCR.
Following are the effects of ESD Level 0 Shutdown in Effluent Waste Water System:
•
Waste Water Degasser Pump (6922-P-08A/B) trip
•
Stripper Overhead Circulation Pumps (6922-P-11A/B) trip
•
Stripper Overhead Cooler Fan motor (69-EM-03AA/AB) trip
•
Stripped Water Pumps (6922-P-10A/B) trip
•
Stripper Water Cooler Fan motor (69-EM-02AA/AB) trip
•
6922-V-07 inlet ON/OFF valve 69-XV-1312 close
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•
Stripper overhead ON/OFF valve 69-XV-1313 close
•
LP steam supply ON/OFF valve 69-XV-1314 close
•
LP fuel gas supply ON/OFF valve 69-XV-1315 close
•
6922-V-07 outlet ON/OFF valve 69-XV-1316 close
•
6922-C-01 outlet ON/OFF valve 69-XV-1339 close
•
Sour water to Waste Water Degasser ON/OFF valve 91-XV-1575 close
11.3.8.2 ESD-Level 1 Shutdown in Effluent Waste Water System
Following are the causes of ESD level1 shutdown:
•
Fire detection alarm (91-XS-01-1801) from AGEU/TGTU unit (LER-4).
•
Fire detection alarm (91-XS-02-1801) from Incinerator area (LER-4).
•
Fire detection alarm (68-XS-02-1801) from utility area (LER-6)
•
Fire detection alarm (68-XS-03-1801) from utility boiler area (LER-6)
•
Fire detection alarm (66-XS-01-1801) from new substation area
•
Fire detection alarm (66-XS-03-1801) from LER-6
•
Flammable gas detection alarm (91-XS-01-1802) from AGEU/TGTU unit (LER-4)
•
Flammable gas detection alarm (91-XS-02-1802) Incinerator area (LER-4)
•
Flammable gas detection alarm (68-XS-02-1802) from utility area (LER-6)
•
Flammable gas detection alarm (68-XS-03-1802) from utility boiler area (LER-6)
•
Flammable gas detection alarm (66-XS-03-1802) from LER-6
•
Flammable gas detection alarm (66-XS-01-1802) from new substation area
•
Activation of ESD Level-1 shutdown pushbutton 65-HS-001 in CCR
Following are the effects of ESD Level 1 Shutdown in effluent waste water system:
•
Waste Water Degasser pump (6922-P-08A/B) trip
•
Stripper Overhead Circulation Pumps (6922-P-11A/B) trip
•
Stripper Overhead Cooler Fan motor (69-EM-03AA/AB) trip
•
Stripped Water Pumps (6922-P-10A/B) trip
•
Stripper Water Cooler Fan motor (69-EM-02AA/AB) trip
•
6922-V-07 inlet ON/OFF valve 69-XV-1312 close
•
Stripper overhead ON/OFF valve 69-XV-1313 close
•
LP steam supply ON/OFF valve 69-XV-1314 close
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•
LP fuel gas supply ON/OFF valve 69-XV-1315 close
•
6922-V-07 outlet ON/OFF valve 69-XV-1316 close
•
6922-C-01 outlet ON/OFF valve 69-XV-1339 close
•
Sour water to Waste Water Degasser ON/OFF valve 91-XV-1575 close.
11.3.8.3 ESD Level 2 Shutdown in Effluent Waste Water System
ESD Level 2 Shutdown is activated by the following causes:
•
High high level alarm 91-LAHH-1504 in Acid Gas Amine Absorber bottom
9103-C-11
•
High high level alarm 91-LAHH-1509 in Amine Regenerator bottom 9103-C-12
•
Low low flow alarm 91-FALL-1515 in Lean Amine Pumps 9103-P-13A/B
discharge
•
Incinerator shutdown signal 91-XS-1186 from Incinerator UCP
•
Unit -91 general shutdown activation by pushbutton 91-HS-1011
•
Total power failure signal (65-XS-1024)
•
Instrument air pressure low low (2oo3) alarm 65-PALL-1003
•
Steam failure signal 65-XS-1021
•
Existing SRU shutdown signal 65-XA-1001
•
De-aerator drum level low low signal 68-XS-1310
•
Steam Generator Package shutdown signal 68-XS-1580/68-XS-1680/68-XS-1780
•
Fuel gas header pressure high high alarm 62-PAHH-1304
•
Instrument air pressure 2oo3 low low alarm 68-PALL-1312A/B/C
Following are the effects of ESD Level 2 Shutdown in effluent waste water system:
•
Waste Water Degasser Pump 6922-P-08A/B trip
•
Stripper Overhead Circulation Pumps 6922-P-11A/B trip
•
Stripper Overhead Cooler Fan motor 69-EM-03AA/AB trip
•
Stripped Water Pumps 6922-P-10A/B trip
•
Stripper Water Cooler Fan motor 69-EM-02AA/AB trip
•
6922-V-07 inlet ON/OFF valve 69-XV-1312 close
•
Stripper overhead ON/OFF valve 69-XV-1313 close
•
LP steam supply ON/OFF valve 69-XV-1314 close
•
LP fuel gas supply ON/OFF valve 69-XV-1315 close
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•
6922-V-07 outlet ON/OFF valve 69-XV-1316 close
•
6922-C-01 outlet ON/OFF valve 69-XV-1339 close
•
Sour water to Waste Water Degasser ON/OFF valve 91-XV-1575 close
11.3.8.4 ESD–Level 4 Shutdown in Effluent Waste Water System
Following are the ESD-4 shutdowns (equipment wise) in effluent waste water system:
Waste Water Degasser
•
Low low level alarm 69-LALL-1311 in Waste Water Degasser 6922-V-07 trips the
Waste Water Degasser Pumps (6922-P-08A/B)
•
High high level alarm 69-LAHH-1311 in Waste Water Degasser 6922-V-07 closes the
waste water degasser inlet valve 69-XV-1312, LP fuel gas supply valve 69-XV-1315
and sour water to Waste Water Degasser valve 91-XV-1575.
•
High high pressure alarm 69-PAHH-1311 in Waste Water Degasser 6922-V-07
Sour Water Stripper
•
Low low level alarm 69-LALL-1315 in Sour Water Stripper 6922-C-01 trips the
Stripper overhead Circulation Pumps 6922-P-11A/B
•
Low low level alarm 69-LALL-1316 in Sour Water Stripper 6922-C-01 bottom
section trips the Stripper Water Pumps (6922-P-10A/B) and closes the Sour Water
Stripper outlet ON/OFF valve 69-XV-1339
•
High high level alarm 69-LAHH-1316 in Sour Water Stripper 6922-C-01 bottom
section trips Waste Water Degasser Pumps 6922-P-08A/B and closes the 6922-V-07
outlet ON/OFF valve 69-XV-1316
Stripper Overheads Cooler
•
High high vibration alarm 69-VSHH-1304 in Stripper Overheads Cooler Fan
6922-E-03AA trips the Stripper Overheads Cooler Fan motor 69-EM-03AA
•
High high vibration alarm 69-VSHH-1303 in Stripper Overheads Cooler Fan
6922-E-03AB trips the Stripper Overheads Cooler Fan motor 69-EM-03AB
•
High high vibration alarm 69-VSHH-1305 in Stripper Overheads Cooler Fan
6922-E-02AA trips the Stripper Overheads Cooler Fan motor 69-EM-02AA
•
High high vibration alarm 69-VSHH-1306 in Stripper Overheads Cooler Fan
6922-E-02AB trips the Stripper Overheads Cooler Fan motor 69-EM-02AB
•
TGTU shutdown signal 91-XS-1335 closes the Stripper overhead ON/OFF valve
69-XV-1313.
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11.3.9
Instrument Air Compressors
11.3.9.1 ESD Level 0 Shutdown in Instrument Air Compressor (6837-K-02A/B)
ESD level-0 is activated (cause) only by pressing emergency pushbutton 65-HS-4001 in
CCR which trips both the instrument air packages in UCP through the signal 68-XS-1424.
11.3.9.2 Emergency Shutdown from UCP
UCP checks all trip and alarm condition for healthy status before start-up and during
operation. Alarm conditions are flagged on display of UCP but the compressor remains
running. Trip conditions initiate a compressor shutdown and a reset is required before
the unit is available.
Following causes initiates the Compressor trip in UCP:
11.4
•
Compressor outlet pressure high-high (68-PT-1406)
•
Compressor air inlet pressure low-low (68-PDT-1401)
•
Compressor oil pressure low-low (68-PT-1402)
•
Compressor oil filter DP high-high (68-PDT-1403)
•
LP stage outlet temperature high-high (68-TT-1401)
•
Compressor oil temperature high-high (68-TT-1402)
•
LP stage inlet temperature high-high (68-TT-1403)
•
Compressor outlet temperature high-high (68-TT-1405)
•
Over load relays of main motor, inter external after cooler motors
•
Main motor winding temperatures high-high
•
Emergency stop at LCP (68-HS-1401)
UTILITY FAILURE
While every emergency situation must be handled individually, depending upon the
existing conditions when the emergency originates. The following recommended
procedures provide sequences of major steps which must be taken for the most likely
emergency situations.
The extent to which the plant has to be shut down depends on the specific emergency.
In any emergency, determine the extent of the emergency condition, and decide how
to cope with it. Then proceed with one of the following actions as warranted by the
emergency:
•
Handle the emergency as a localized condition without shutting down the rest of
the plant. For example, in case of a faulty control valve. Block in and bypass the
malfunctioning item until repairs can be made.
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TITLE: OPERATION AND MAINTENANCE MANUAL
•
Shut down the unit using the normal shutdown procedure described in Section
10.2.
•
Shut down the unit using the emergency procedures given below for a specific
emergency.
11.4.1
LP Steam Failure
Consequence
Generally, steam failure is for long duration. Due to loss of LP steam, the stripping of
the amine solution in Amine Regenerator, Reducing Gas Generator, BFW Preheater
9101-E-08, Sulphur Degassing Pit 9101-T-01B, Sour Water Stripper Reboiler and Steam
tracing of fuel gas lines are affected. The lack of steam to AGEU Regenerator Reboiler
produce off spec gas to Sulphur Recovery Unit, it affects the sulphur quality which is
produced by Sulphur Recovery Unit. So, the off spec gas is lined up to acid gas flare.
When the temperature reaches below Sulphur melting temperature, solid formation
occurs inside Sulphur transfer lines. Hence, the SRU unit shutdown is necessary until
steam flow reaches normal flow of plant running.
Action
•
Shutdown AGEU, SRU and TGTU unit due as the LP steam is not available for
Reboilers, Preheating and heat tracing.
•
Isolate sulphur transfer lines and drain all the sulphur to collection area.
11.4.2
Sea Cooling Water Failure
Consequence
•
In the event of Sea Cooling Water failure, there is no cooling water supply to
coolers and condensers.
•
AGEU Acid Gas Coolers 9103-E-101A/B, Regenerator Condenser Trim Cooler
9103-E-16, Lean Amine Trim Cooler 9103-E-15, Contact Condenser Trim Cooler
9102-E-13A/B process gas/liquid temperature rises.
Action
•
Shutdown the AGEU and TGTU unit by initiating ESD level-1 shutdown.
•
If Sulphur Recovery Unit upstream unit shutdown duration is short-time <24 hrs
there is no need to take shutdown of Claus sulphur recovery and Incinerator units.
Maintain the Reaction Furnace temperature and maintain the Incinerator
temperature with the help of fuel gas firing.
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11.4.3
Instrument Air Failure
Consequence
In case, the instrument air supply to SRU upgrade is stopped, all the control valves
position is kept on fail safe position as per the position indicated in P&ID. If the
instrument air is not immediately restored, the SRU Upgrade units must be shut down.
Action
Shut down the AGEU, SRU, TGTU and Incinerator units as instrument air supply to SRU
is not available for operating control valves and ESD valves.
11.4.4
Power Failure
In case of power failure, all pumps and compressors are stopped due to loss of power.
Only UPS power is available for DCS, F&G panel and emergency light. Generally, the
power failure affects all the units.
Consequence
The plant has to be shut down as:
Power failure trips all the pumps, blowers, compressors and air cooler fans.
Action
Shut down all the units of SRU Upgrade facilities due to unavailability of feed for
running the plant.
11.4.5
Boiler Feed Water Failure
In the general boiler feed water failure, all the Steam Generators, SRU Reaction
Furnace Boiler, Reaction Furnace Condensers, 1st Stage Condenser and Reaction
Effluent Cooler in TGTU initiates shutdown to respective unit, due to loss of boiler
feed water.
Consequence
The plant has to be shut down as:
SRU Upgrade Reaction Furnace Boiler & Last condenser and TGTU unit Reactor Effluent
Cooler tubes will be damaged due to loss of boiler feed water.
Action
Shutdown the AGEU, SRU and TGTU units as the boiler feed water is not available for
recovering heat from the above equipment.
11.4.6
Fuel Gas Failure
Consequence
•
Steam Generation from the Boilers is affected
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•
Complete burning of Sulphur and hydrocarbon compound are not possible when
Incinerator temperature is less than normal operating temperature.
•
Hydrogenation reaction rate is reduced due to low temperature in RGG.
Action
Shutdown AGEU, SRU, TGTU and Incinerator units of SRU units as fuel gas is not
available.
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TITLE: OPERATION AND MAINTENANCE MANUAL
SECTION XII
MAINTENANCE
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TITLE: OPERATION AND MAINTENANCE MANUAL
12.1
GENERAL
Maintenance is an activity which helps to keep the plant and equipments in running
condition for a longer period of time. It is the work performed on an equipment,
vessel, column or piping to preserve it in as near to its original condition as is practical
and to realize its normal life expectancy.
Types of Maintenance
Maintenance is classified as below:
a. Preventive maintenance (PM)
Preventive maintenance is a routine maintenance (cleaning, inspection, oiling and retightening) design to retain the healthy condition of equipment and prevent failure
through the prevention of deterioration, periodic inspection or equipment condition
diagnosis, to measure deterioration.
Preventive maintenance (PM) is the practice of maintaining equipment on a regular
schedule, based on elapsed time, run-time meter readings, or number of operations.
The intent of PM is to “prevent” maintenance problems or failures before they take
place by following routine and comprehensive maintenance procedures. The goal is to
achieve fewer, shorter, and more predictable outages.
b. Shutdown Maintenance
Shutdown maintenance consists of those activities that can be carried out only during
the shutdown of the plant/equipments. In order to ensure that a process plant
continues to run at peak efficiency, it is prudent to do shutdown maintenance for huge
sections of the plant at specific intervals. During this shutdown period, the plant is
stopped, cleaning and repairing of equipments is carried out and then the plant is
started back. The plant has to be carefully and safely shutdown for this activity. For
handing over to maintenance the plant has to be depressurised, drained of liquids,
purged with nitrogen, steaming out is carried out if necessary, chemicals disposed of
safely. Refer section–X for safe shutdown and handing over of the plant for
maintenance.
12.2
12.2.1
PREVENTIVE MAINTENANCE
Process
Regular inspection and maintenance of the rotary equipment pays rich dividends.
Potentially hazardous situations can be avoided and costly delays in production can be
minimized. QP standard maintenance schedules and procedures shall be followed for
the regular maintenance of the mechanical equipment (blowers, pumps, etc.)
electrical equipment and instruments. Refer to the vendor O & M manuals for detailed
maintenance procedures of package equipment (Instrument Air Compressors, Electrical
Equipment, etc.).
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12.2.1.1 Acid Gas Enrichment Unit
a. Centrifugal Pumps
Equipment Description
Acid Gas KO Drum Return Pump 9103-P-14A/B,
Acid Gas Rich Amine Pumps 9103-P-12A/B,
Hot Lean Amine Pumps 9103-P-17A/B,
Regenerator Reflux Drum Pumps 9103-P-11A/B,
Lean Amine Pumps 9103-P-13A/B,
Amine Sump Pump 9103-P-15
Activity
Area
Activity Description
Frequency
Joints/
Flanges,
Mechanical
Seal
Check all joints/flanges/gaskets
for amine/liquid leakage. Report
to maintenance any leakage.
Operator Rounds
Abnormal
Noises
Pumps
Check for unusual noises or noise
levels. Report to maintenance.
Operator Rounds
Strainers/
Filters
Differential
Pressures.
Pump
Suction
Report to Maintenance for
further actions.
Operator Rounds
Loose
Component
Checks
All
Component
Check entire skid for loose nuts
& bolts. Report to maintenance
any abnormality.
Operator Rounds
Lube Oil
Level Checks
Pumps
Bearings DE
& NDE
Check the oil levels (Top-up Lube
Oil as required)
Operator Rounds
Excessive
Vibration
Pumps
Check the Pumps for any
abnormal vibrations and report
to maintenance.
Operator Rounds
Excessive
Bearing
Temperature
Bearings
Check the oil system and inform
to maintenance.
Operator Rounds
Test Run
Stand by
Pump
Ensure readiness for Operation
As per QP
schedule
Coupling
Guard Checks
Pumps
Coupling
Check the security of Coupling
guards.
As per QP
schedule
Holding Down
Bolts Checks
Pump Units
Check the security of all holdingdown bolts
As per QP
schedule
Pump Units
Carry out logging of key
parameters of Pump Units
required
As per QP
schedule
Leakage
Logging
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TITLE: OPERATION AND MAINTENANCE MANUAL
b. Vessels
Equipment Description
Lean Acid Gas KO Drum 9103-V-14
Regenerator Reflux Drum 9103-V-12
Regenerator Reboiler Condensate Pot 9103-V-13
Amine Sump 9103-V-10
Amine Sump Filter 9103-S-14
Activity
Area
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets
for any leakage. Report to
maintenance for any leakage.
Operator Rounds
Loose
Component
All
Components
Check vessels for loose nuts &
bolts, cable trays & earthing
wire. Report to maintenance any
abnormality.
Operator Rounds
Logging
Vessels
Carry out logging of key
parameters required
As per QP
schedule
c. Filter
Equipment Description
Lean Amine Filter 9103-S-11
Activated Carbon Filter 9103-S-12
Fines Filter 9103-S-13
Activity
Area
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets for
process flow leakage. Report to
maintenance any leakage.
Operator
Rounds
Loose
Component
All
Components
Check entire skid for loose nuts &
bolts. Report to maintenance any
abnormality.
Operator
Rounds
Filter
Cleaning
Filter
Clean the filter and reinstall as
required
Dictated by
pressure drop
Logging
Sour Water
Filter
Carry out logging of key parameters
required.
As per QP
schedule
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d.
Columns
Equipment Description
Activity
Area
Acid Gas Amine Absorber 9103-C-11
Amine Regenerator 9103-C-12
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets for
any leakage. Report to maintenance
for any leakage.
Operator
Rounds
Loose
Component
All
Components
Check the columns for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance for any
abnormality.
Operator
Rounds
Logging
Columns
Carry out logging of key parameters
required.
As per QP
schedule
e.
Heat Exchanger
Equipment Description
Activity
Area
Acid Gas Coolers 9103-E-101A/B
Regenerator Reboiler 9103-E-13
Lean/Rich Amine Exchangers 9103-E-11A/B
Regenerator Condenser Trim Cooler 9103-E-16
Lean Amine Trim Cooler 9103-E-15
Activity Description
Frequency
Joints/
Flanges
Check all joints/flanges/gaskets for
process flow leakage. Report to
maintenance any leakage.
Operator
Rounds
Loose
Component
All
Components
Check entire skid for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance any
abnormality.
Operator
Rounds
Logging
Heat
Exchangers
Carry out logging of key parameters
required.
As per QP
schedule
Leakage
f.
Tank
Equipment Description
Amine Surge Tank 9103-T-11
Activity
Area
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets for
amine leakage. Report to
maintenance for any leakage.
Operator
Rounds
Loose
Component
All
Components
Check the Tank for loose nut &
bolts, cable trays and report to
maintenance for any abnormality
Operator
Rounds
Logging
Tank
Carry out logging of Key Parameters
required.
As per QP
schedule
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TITLE: OPERATION AND MAINTENANCE MANUAL
g.
Air Coolers
Equipment Description
Activity
Area
Regenerator Condenser Cooler 9103-E-12
Lean Amine Cooler 9103-E-14
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets
for process flow leakage. Report
to maintenance any leakage.
Operator
Rounds
Loose
Component
All
Components
Check air coolers for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance for any
abnormality.
Operator
Rounds
Motor Bearing
Check lubricant levels, and top up
as and when required.
Operator
Rounds
Motor
Check for abnormal motor
vibrations and report to
maintenance
Operator
Rounds
Temperature
Motor
Check for abnormal motor
Temperature and report to
maintenance
Operator
Rounds
Logging
Air Coolers
Carry out logging of key
parameters required.
As per QP
schedule
Grease/
Oil Level
12.2.1.2 Sulphur Recovery Unit
a. Blower
Equipment Description
Activity
Area
Process Air Blowers 9101-K-01A/B
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets
for process flow leakage. Report to
maintenance any leakage.
During
Operator
Rounds
Loose
Component
All
Components
Check entire skid for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance any
abnormality.
During
Operator
Rounds
Oil Level
Lube Oil Tank,
Bearings and
Gear Box
Check the oil levels (Top-up lube
oil as and when required.)
As per QP
schedule
Condensate
Draining
Lube Oil Tank
Draining condensed water from the
Lube Oil Tank
As per QP
schedule
Lube Oil
Circuit
Check whether the Lube Oil Filters
differential pressure across the oil
filters exceed the limit value. If
exceeded, inform Maintenance to
change the oil filter element.
Daily
Lube Oil
Pressure too
Low
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Activity
Abnormal
Noise
Vibrations
Temperature
Logging
Area
Activity Description
Frequency
Blower
Check the blower for abnormal
noise. If abnormal, report to
maintenance.
Operator
Rounds
Motor
Check the motor for abnormal
noise. If abnormal, report to
maintenance.
Operator
Rounds
Lube oil
Cooler Fan/
Motor
Check the fan/motor for abnormal
noise. If abnormal, report to
maintenance.
Operator
Rounds
Blower
Check the blower for abnormal
vibrations. If abnormal, report to
maintenance.
Operator
Rounds
Motor
Check the motor for abnormal
vibrations. If abnormal, report to
maintenance.
Operator
Rounds
Lube oil
Cooler Fan/
Motor
Check the fan/motor for abnormal
vibrations. If abnormal, report to
maintenance.
Operator
Rounds
Motor
Check for abnormal motor winding
temperature. If abnormal, report
to maintenance.
Operator
Rounds
Lube oil
Cooler Fan
Motor
Check for abnormal fan motor
winding temperature. If abnormal,
report to maintenance.
Operator
Rounds
Blower
Carry out logging of key
parameters of the blower required
Operator
Rounds
b. Vessels
Equipment Description
Activity
Area
Acid Gas KO Drum 9101-V-04
HP Condensate Drum 91014-V-06
Final Separator 9101-V-05
Activity Description
Frequency
Joints/
Flanges
Check all joints/flanges/gaskets
for any leakage. Report to
maintenance for any leakage.
Operator
Rounds
Loose
Component
All
Components
Check entire skid for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance any
abnormality.
Operator
Rounds
Logging
Vessels
Carry out logging of key
parameters required
As per QP
schedule
Leakage
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c. Pumps
Equipment Description
Activity
Acid Water Pump 9101-P-01A/B,
Sulphur Product Pumps 9101-P-10A/B
Sulphur Degassing Pumps 9101-P-09A/B
Sulphur Tank Pumps 9101-P-15A/B
Catalyst Metering Pumps 9101-P-11A/B
Sulphur Product Pumps 9101-P-10A/B
Sulphur Degassing Pumps 9101-P-09A/B
Area
Activity Description
Joints/Flanges
Mechanical
Seal
Check all joints/flanges/
gaskets for leakage. Report to
maintenance any leakage.
Operator Rounds
Pumps
Check for unusual noises or
noise levels. Report to
maintenance.
Operator Rounds
Strainers
Differential
Pressure
Pump Suction
Check the Differential
Pressures, if it is abnormal,
report to Maintenance for
further actions.
Operator Rounds
Loose
Component
Check
All
Component
Check for loose nuts & bolts,
cable trays & earthing wire.
Report to maintenance any
abnormality.
Operator Rounds
Lube Oil Level
Checks
Pumps
Bearings DE &
NDE, Motor
Bearings DE &
NDE.
Check the oil levels (Top-up
Lube Oil as required)
Operator Rounds
Excessive
Vibration
Pumps
Check the Pumps for any
abnormal vibrations and
report to maintenance.
Operator Rounds
Excessive
Bearing
Temperature
Bearings
Check the oil supply system
and inform to maintenance.
Operator Rounds
Test Run
Stand by
Pump
Ensure readiness for
Operation
As per QP
schedule
Coupling
Guard Checks
Pumps
Coupling
Check the security of
Coupling guards.
As per QP
schedule
Holding Down
Bolts Checks
Pump Units
Check the security of all
holding-down bolts
As per QP
schedule
Logging
Pump Units
Carry out logging of key
parameters of Pump Units
required
As per QP
schedule
Leakage
Abnormal
Noise
Frequency
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d. Boiler
Equipment Description
Reaction Furnace Boiler 9101-E-07
Activity
Area
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/
gaskets for process flow
leakage. Report to
maintenance any leakage.
Operator Rounds
All
Components
Check entire skid for loose
nuts & bolts, cable trays &
earthing wire. Report to
maintenance any
abnormality.
Operator Rounds
Carry out logging of key
parameters required.
As per QP
schedule
Loose
Component
Logging
Boiler
e. Heat Exchanger
Equipment Description
Activity
Area
Process Air Preheater 9101-E-05
Acid Gas Preheater 9101-E-06
Reaction Furnace Condenser 9101-E-01
1st Stage Condenser 9101-E-02
Last Condenser 9101-E-04
BFW Preheater 9101-E-08
Activity Description
Frequency
Joints/
Flanges
Check all joints/flanges/
gaskets for process flow
leakage. Report to
maintenance any leakage.
Operator Rounds
Loose
Component
All
Components
Check entire skid for loose
nuts & bolts, cable trays &
earthing wire. Report to
maintenance any
abnormality.
Operator Rounds
Logging
Heat
Exchangers
Carry out logging of key
parameters required.
As per QP
schedule
Leakage
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TITLE: OPERATION AND MAINTENANCE MANUAL
f.
Combustion Chamber
Reaction Furnace 9101-F-01
1st Stage Auxiliary Burner 9101-F-02
2nd Stage Auxiliary Burner 9101-F-03
Equipment Description
Activity
Area
Activity Description
Frequency
Joints/Flanges
Check all joints/flanges/
gaskets for any leakage.
Report to maintenance
for any leakage.
Operator Rounds
Loose
Component
All Components
Check entire skid for
loose nuts & bolts, cable
trays & earthing wire.
Report to maintenance
any abnormality.
Operator Rounds
Logging
Reaction Furnace,
1st Stage Auxiliary
Burner, 2nd Stage
Auxiliary Burner
Carry out logging of key
parameters required
As per QP
schedule
Leakage
g. Reactor
Equipment Description
Activity
Area
1st Stage Converter 9101-V-01
2nd Stage Converter 9101-V-02
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets
for any leakage. Report to
maintenance for any leakage.
Operator Rounds
Loose
Component
All
Components
Check entire skid for loose nuts
& bolts, cable trays & earthing
wire. Report to maintenance
any abnormality.
Operator Rounds
Logging
1st Stage
Converter,
2nd Stage
Converter
Carry out logging of key
parameters required
As per QP
schedule
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TITLE: OPERATION AND MAINTENANCE MANUAL
h. Tank
Equipment Description
Activity
Area
Catalyst Tank 9101-T-03/09
Sulphur Degassing Pit 9101-T-01/01B
Activity Description
Frequency
Joints/
Flanges
Check all joints/flanges/
gaskets for process flow
leakage. Report to maintenance
for any leakage.
Operator Rounds
Loose
Component
All
Components
Check entire Skid for loose nut
& bolts, cable trays & earthing
wire. and report to
maintenance for any
abnormality
Operator Rounds
Level
Tank
Monitor the level in Storage
Tank.
Operator Rounds
Leakage
12.2.1.3 Tail Gas Treatment Unit
a. Blowers
Equipment Description
Activity
Area
Combustion Air Blowers 9102-K-11A/B
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets
for process flow leakage.
Report to maintenance any
leakage.
During Operator
Rounds
Loose
Component
All
Components
Check entire skid for loose nuts
& bolts, cable trays & earthing
wire. Report to maintenance
any abnormality.
During Operator
Rounds
Oil Level
Lube Oil
Tank,
Bearings and
Gear Box
Check the oil levels (Top-up
lube oil as and when required.)
As per QP
schedule
Condensate
Draining
Lube Oil Tank
Draining condensed water from
the Lube Oil Tank
As per QP
schedule
Lube Oil
Pressure too
Low
Lube Oil
Circuit
Check whether the Lube Oil
Filters differential pressure
across the oil filters exceed the
limit value. If exceeded, inform
Maintenance to change the oil
filter element.
As per QP
schedule
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TITLE: OPERATION AND MAINTENANCE MANUAL
Activity
Abnormal
Noise
Vibrations
Area
Frequency
Blower
Check the blower for abnormal
noise. If abnormal, report to
maintenance.
Operator Rounds
Motor
Check the motor for abnormal
noise. If abnormal, report to
maintenance.
Operator Rounds
Lube oil
Cooler Fan/
Motor
Check the fan/motor for
abnormal noise. If abnormal,
report to maintenance.
Operator Rounds
Blower
Check the blower for abnormal
vibrations. If abnormal, report
to maintenance.
Operator Rounds
Motor
Check the motor for abnormal
vibrations. If abnormal, report
to maintenance.
Operator Rounds
Lube oil
Cooler Fan/
Motor
Check the fan/motor for
abnormal vibrations. If
abnormal, report to
maintenance.
Operator Rounds
Motor
Check for abnormal motor
winding temperature. If
abnormal, report to
maintenance.
Operator Rounds
Lube oil
Cooler Fan
Motor
Check for abnormal fan motor
winding temperature. If
abnormal, report to
maintenance.
Operator Rounds
Blower
Carry out logging of key
parameters of the blower
required
As per QP
schedule
Temperature
Logging
Activity Description
b. Combustion Chamber
Equipment Description
Activity
Area
Reducing Gas Generator 9102-F-11
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/
gaskets for any leakage. Report
to maintenance for any
leakage.
Operator Rounds
Loose
Component
All
Components
Check entire skid for loose nuts
& bolts, cable trays & earthing
wire. Report to maintenance
any abnormality.
Operator Rounds
Logging
Reducing Gas
Generator
Carry out logging of key
parameters required
As per QP
schedule
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TITLE: OPERATION AND MAINTENANCE MANUAL
c. Reactor
Equipment Description
Activity
Area
Hydrogenation Reactor 9102-V-11
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets
for any leakage. Report to
maintenance for any leakage.
Operator Rounds
Loose
Component
All
Components
Check entire skid for loose nuts
& bolts, cable trays & earthing
wire. Report to maintenance
any abnormality.
Operator Rounds
Logging
Hydrogenation
Reactor
Carry out logging of key
parameters required
As per QP
schedule
d. Boiler
Equipment Description
Activity
Area
Reactor Effluent Cooler 9102-E-11
Activity Description
Frequency
Joints/
Flanges
Check all joints/flanges/gaskets
for process flow leakage.
Report to maintenance any
leakage.
Operator Rounds
Loose
Component
All
Components
Check entire skid for loose nuts
& bolts, cable trays & earthing
wire. Report to maintenance
any abnormality.
Operator Rounds
Logging
Reactor
Effluent
Cooler
Carry out logging of key
parameters required.
As per QP
schedule
Leakage
e. Heat Exchanger
Equipment Description
Activity
Area
Contact Condenser Trim Cooler 9102-E-13A/B
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets
for process flow leakage. Report
to maintenance any leakage.
Operator
Rounds
Loose
Component
All
Components
Check entire skid for loose nuts &
bolts, cable trays, earthing wire.
Report to maintenance any
abnormality.
Operator
Rounds
Logging
Heat
Exchanger
Carry out logging of key
parameters required.
As per QP
schedule
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TITLE: OPERATION AND MAINTENANCE MANUAL
f.
Pumps
Equipment Description
Activity
Area
Cooling Water Circulation Pump 9102-P-12A/B
Desuperheater Circulation Pumps 9102-P-11A/B
Tail Gas Rich Amine Pumps 9102-P-16A/B
Activity Description
Frequency
Leakage
Joints/
Flanges
Mechanical
Seal
Check all joints/flanges/gaskets
for any leak. Report to
maintenance any leakage.
Operator
Rounds
Abnormal
Noises
Pumps
Check for unusual noises or noise
levels. Report to maintenance.
Operator
Rounds
Strainers
Differential
Pressure
Pump Suction
Check the Differential Pressures,
if it is abnormal, report to
Maintenance for further actions.
Operator
Rounds
Loose
Component
Checks
All
Component
Check entire skid for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance any
abnormality.
Operator
Rounds
Lube Oil
Level Checks
Pumps
Bearings DE &
NDE, Motor
Bearings DE &
NDE.
Check the oil levels (Top-up Lube
Oil as required)
Operator
Rounds
Excessive
Vibration
Pumps
Check the Pumps for any abnormal
vibrations and report to
maintenance.
Operator
Rounds
Excessive
Bearing
Temperature
Bearings
Check the oil supply system and
inform to maintenance.
Operator
Rounds
Test Run
Stand by
Pump
Ensure readiness for Operation
As per QP
schedule
Coupling
Guard
Checks
Pumps
Coupling
Check the security of Coupling
guards.
As per QP
schedule
Holding
Down Bolts
Checks
Pump Units
Check the security of all holdingdown bolts
As per QP
schedule
Logging
Pump Units
Carry out logging of key
parameters of Pump Units
required
Once per Shift
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TITLE: OPERATION AND MAINTENANCE MANUAL
g. Air Coolers
Equipment Description
Activity
Area
Contact Condenser Cooler 9102-E-12
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets
for process flow leakage. Report
to maintenance any leakage.
Operator
Rounds
Loose
Component
All
Components
Check entire skid for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance for any
abnormality.
Operator
Rounds
Motor Bearing
Check lubricant levels, and top up
as and when required.
Operator
Rounds
Motor
Check for abnormal motor
vibrations and report to
maintenance
Operator
Rounds
Temperature
Motor
Check for abnormal motor
Temperature and report to
maintenance
Operator
Rounds
Logging
Air Coolers
Carry out logging of key
parameters required.
As per QP
schedule
Grease/
Oil Level
h. Columns
Equipment Description
Activity
Area
Desuperheater/Contact Condenser 9102-C-11
Tail Gas Amine Absorber 9102-C-12
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets for
any leakage. Report to maintenance
for any leakage.
Operator
Rounds
Loose
Component
All
Components
Check entire unit for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance for any
abnormality.
Operator
Rounds
Logging
DCC
Carry out logging of key parameters
required.
As per QP
schedule
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Doc. No.: 2970-0-22-0001
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TITLE: OPERATION AND MAINTENANCE MANUAL
i.
Filter
Equipment Description
Activity
Area
Wash Water Filter 9102-S-15
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets for
any leakage. Report to maintenance
for any leakage.
Operator
Rounds
Loose
Component
All
Components
Check entire skid for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance any
abnormality.
Operator
Rounds
Logging
Wash Water
Filter
Carry out logging of key parameters
required
As per QP
schedule
12.2.1.1 Tail Gas Incinerator
a. Combustion Chamber
Equipment Description
Activity
Area
Leakage
Joints/
Flanges
Loose
Component
All
Components
Logging
Incinerator
Incinerator 9101-F-14
Activity Description
Check all joints/flanges/gaskets for
any leakage. Report to maintenance
for any leakage.
Check entire skid for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance any
abnormality.
Carry out logging of key parameters
required
Frequency
Operator
Rounds
Operator
Rounds
As per QP
schedule
b. Blowers
Equipment Description
Activity
Area
Incinerator Air Blowers 9101-K-12A/B
Activity Description
Frequency
Joints/
Flanges
Check all joints/flanges/gaskets for
process flow leakage. Report to
maintenance any leakage.
During
Operator
Rounds
Loose
Component
All
Components
Check entire skid for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance any
abnormality.
During
Operator
Rounds
Oil Level
Bearings
Check the oil levels (Top-up lube oil
as and when required.)
As per QP
schedule
Leakage
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Page: 470 of 517
TITLE: OPERATION AND MAINTENANCE MANUAL
Activity
Area
Frequency
Blower
Check the blower for abnormal
noise. If abnormal, report to
maintenance.
Operator
Rounds
Motor
Check the motor for abnormal
noise. If abnormal, report to
maintenance.
Operator
Rounds
Blower
Check the blower for abnormal
vibrations. If abnormal, report to
maintenance.
Operator
Rounds
Motor
Check the motor for abnormal
vibrations. If abnormal, report to
maintenance.
Operator
Rounds
Temperature
Motor
Check for abnormal motor winding
temperature. If abnormal, report to
maintenance.
Operator
Rounds
Logging
Blower
Carry out logging of key parameters
of the blower required
Operator
Rounds
Abnormal
Noise
Vibrations
12.2.2
Activity Description
UTILITIES
12.2.2.1 Plant and Instrument Air Compressor
Description
Comments
Maintenance Frequency
Daily
Overall
Visual
Inspection
Complete overall visual
inspection to be sure all
equipment is operating &
safety systems are in
place.
X
Leakage
Assessment
Look for and report any
system leakage
X
Compressor
Operation
Monitor operation for run
time and temperature
variance from trended
norms
X
Dryers
Dryers should be observed
for proper function
X
Compressor
Ventilation
Make sure proper
ventilation is available for
compressor inlet
X
Condensate
Drains
Drain condensate from
tanks, legs, and/or traps
X
Operating
Temperature
Verify operating
temperature is per
manufacturer specification
X
Weekly
Monthly
Annually
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TITLE: OPERATION AND MAINTENANCE MANUAL
Description
Maintenance Frequency
Comments
Daily
Weekly
Pressure
Relief Valves
Verify all pressure relief
valves are functioning
properly
X
Air
Consuming
Device
Check
All air consumer devices
need to be inspected on a
regular basis for leakage
X
Drain Traps
Clean out debris and check
operation
X
Monthly
Annually
12.2.2.2 Chemical Injection System
The following maintenance procedures are applicable to the all the chemical injection
systems listed below.
1. Antifoam Injection Package 9103-A-11
2. Caustic Injection Package 9103-A-13
3. Corrosion Inhibitor Injection Package 9103-A-12
4. Complex Product Injection Package 6834-A-09
5. Oxygen Scavenger Injection Package 6834-A-09
6. Biocide Injection Package 6932-A-06
7. Scale Inhibitor Injection Package 6932-A-07
8. Catalyst Injection Package 9101-A-01
Equipment Description
a. Chemical Unloading Pump
Activity
Area
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets for
process flow leakage. Report to
maintenance for any leakage.
Operator
Rounds
Loose
Component
All
Components
Check entire Skid for loose nuts &
bolts, cable trays & earthing wire.
and report to maintenance for any
abnormality
Operator
Rounds
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TITLE: OPERATION AND MAINTENANCE MANUAL
b. Chemical Storage Tank
Activity
Area
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets for
process flow leakage. Report to
maintenance for any leakage.
Operator
Rounds
Loose
Component
All
Components
Check entire Skid for loose nut &
bolts, cable trays & earthing wire.
and report to maintenance for any
abnormality
Operator
Rounds
Logging
Tank
Carry out logging of Key Parameters
required.
As per QP
schedule
c. Chemical Storage Tank Agitator (If applicable)
Equipment Description
Activity
Area
Chemical Dosing Pumps
Activity Description
Frequency
Oil level
Gear Box
Check lubricant levels, and top up as
and when required.
Operator
Rounds
Vibration
Motor
Check for abnormal motor Vibrations
and report to maintenance
Operator
Rounds
Abnormal
Temperature
Motor
Bearings
Check for abnormal motor Bearings
temperature and report to
maintenance
Operator
Rounds
Loose
Component
All
Components
Check agitator
Operator
Rounds
Logging
Agitator
Carry out logging of key parameters
required
As per QP
schedule
d. Chemical Injection Pumps
Equipment Description
Activity
Area
Chemical Dosing Pumps
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets for
process flow leakage. Report to
maintenance for any leakage.
Operator
Rounds
Oil level
Pumps
Check lubricant levels, and top up as
and when required.
Operator
Rounds
Pump
Check pump Vibrations and report to
maintenance
Operator
Rounds
Motor
Check for abnormal motor Vibrations
and report to maintenance
Operator
Rounds
Pump
Bearings
Check for abnormal Pump Bearings
temperature and report to
maintenance
Operator
Rounds
Vibration
Abnormal
Temperature
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Doc. No.: 2970-0-22-0001
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Date: 03/09/2012
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TITLE: OPERATION AND MAINTENANCE MANUAL
Activity
Area
Activity Description
Frequency
Pressure
Drop
Suction
Strainer
Check for any choke in Suction
Strainer. Strainer to be cleaned
periodically.
Dictated by
Pump
Discharge
Pressure
Loose
Component
All
Components
Check entire Skid for loose nut &
bolts, cable trays & earthing wire.
and report to maintenance for any
abnormality
Operator
Rounds
Logging
Pumps
Carry out logging of key parameters
required
As per QP
schedule
12.2.2.3 LP Fuel Gas System
Equipment Description
Activity
LP Fuel Gas KO Drum 6236-V-05
Area
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets for
any leakage. Report to maintenance
for any leakage.
Operator
Rounds
Loose
Component
All
Components
Check entire skid for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance any
abnormality.
Operator
Rounds
Logging
LP Fuel Gas
KO Drum
Carry out logging of key parameters
required
As per QP
schedule
12.2.2.4 Waste Water Treatment System
a. Vessels
Equipment Description
Activity
Area
Waste Water Degasser 6922-V-07
Sour Water Stripper Reboiler 6922-E-04
Reboiler Condensate Drum 6922-V-09
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets for
any leakage. Report to maintenance
for any leakage.
Operator
Rounds
Loose
Component
All
Components
Check entire unit for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance for any
abnormality.
Operator
Rounds
Logging
Waste Water
Treatment
System
Carry out logging of key parameters
required.
As per QP
schedule
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Doc. No.: 2970-0-22-0001
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Date: 03/09/2012
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TITLE: OPERATION AND MAINTENANCE MANUAL
b. Columns
Equipment Description
Activity
Area
Sour Water Stripper 6922-C-01
Activity Description
Frequency
Joints/
Flanges
Check all joints/flanges/gaskets for
any leakage. Report to maintenance
for any leakage.
Operator
Rounds
Loose
Component
All
Components
Check entire unit for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance for any
abnormality.
Operator
Rounds
Logging
Sour Water
Stripper
Carry out logging of key parameters
required.
As per QP
schedule
Leakage
c. Heat Exchanger
Equipment Description
Activity
Area
Sour/Stripped Water Exchanger 6922-E-01
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets for
process flow leakage. Report to
maintenance any leakage.
Operator
Rounds
Loose
Component
All
Components
Check entire skid for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance any
abnormality.
Operator
Rounds
Logging
Sour/
Stripped
Water
Exchanger
Carry out logging of key parameters
required.
As per QP
schedule
d. Filter
Equipment Description
Activity
Area
Sour Water Filter 6922-S-06
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets for
process flow leakage. Report to
maintenance any leakage.
Operator
Rounds
Loose
Component
All
Components
Check entire skid for loose nuts &
bolts. Report to maintenance any
abnormality.
Operator
Rounds
Filter
Cleaning
Filter
Clean the filter and reinstall as
required
Dictated by
69-PDIA-1320
Logging
Sour Water
Filter
Carry out logging of key parameters
required.
As per QP
schedule
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Doc. No.: 2970-0-22-0001
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Date: 03/09/2012
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TITLE: OPERATION AND MAINTENANCE MANUAL
e. Pumps
Equipment Description
Activity
Area
Waste Water Degasser Pumps 6922-P-08A/B
Stripped Water Pumps 6922-P-10A/B
Stripper Overheads Circulation Pumps 6922-P-11A/B
Activity Description
Frequency
Leakage
Joints/
Flanges
Mechanical
Seal
Check all joints/flanges/gaskets for
process flow/oil leakage. Report to
maintenance any leakage.
Operator
Rounds
Abnormal
Noises
Pumps
Check for unusual noises or noise
levels. Report to maintenance.
Operator
Rounds
Strainers
Differential
Pressure
Pump
Suction
Check the suction Pressure, if it is
abnormal, Change over the pump
or report to Maintenance for
further actions.
Operator
Rounds
Loose
Component
Checks
All
Component
Check entire skid for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance any
abnormality.
Operator
Rounds
Lube Oil
Level Checks
Pumps
Bearings DE
& NDE
Check the oil levels (Top-up Lube
Oil as required)
Operator
Rounds
Excessive
Vibration
Pumps
Check the Pumps for any abnormal
vibrations and report to
maintenance.
Operator
Rounds
Excessive
Bearing
Temperature
Bearings
Check the oil supply system and
inform to maintenance.
Operator
Rounds
Test Run
Stand by
Pump
Ensure readiness for Operation
As per QP
schedule
Coupling
Guard
Checks
Pumps
Coupling
Check the security of Coupling
guards.
As per QP
schedule
Holding
Down Bolts
Checks
Pumps
Check the security of all holdingdown bolts
As per QP
schedule
Logging
Pumps
Carry out logging of key parameters
As per QP
schedule
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TITLE: OPERATION AND MAINTENANCE MANUAL
f.
Air Coolers
Equipment Description
Activity
Area
Stripper Overheads Cooler 6922-E-03
Stripped Water Cooler 6922-E-02
Activity Description
Frequency
Joints/
Flanges
Check all joints/flanges/gaskets for
process flow leakage. Report to
maintenance any leakage.
Operator
Rounds
All
Components
Check entire skid for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance for any
abnormality.
Operator
Rounds
Motor
Bearing
Check lubricant levels, and top up
as and when required.
Operator
Rounds
Motor
Check for abnormal motor
vibrations and report to
maintenance
Operator
Rounds
Temperature
Motor
Check for abnormal motor
Temperature and report to
maintenance
Operator
Rounds
Logging
Air Coolers
Carry out logging of key parameters
required.
As per QP
schedule
Leakage
Loose
Component
Grease/
Oil Level
12.2.2.5 Sea Cooling Water System
Equipment Description
Activity
Leakage
Area
Joints/
Flanges
Mechanical
Seal
Sea Cooling Water Pumps 6932-P-04A/B
Activity Description
Check all joints/flanges/gaskets for
any leakage. Report to
maintenance any leakage.
Check for unusual noises or noise
levels. Report to maintenance.
Check entire skid for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance any
abnormality.
Check the Pumps for any abnormal
vibrations and report to
maintenance.
Frequency
Operator
Rounds
Abnormal
Noises
Pumps
Operator
Rounds
Loose
Component
Checks
All
Component
Excessive
Vibration
Pumps
Excessive
Bearing
Temperature
Bearings
Check the oil supply system and
inform to maintenance.
Operator
Rounds
Test Run
Stand by
Pump
Ensure readiness for Operation
As per QP
schedule
Operator
Rounds
Operator
Rounds
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TITLE: OPERATION AND MAINTENANCE MANUAL
Activity
Coupling
Guard
Checks
Holding
Down Bolts
Checks
Logging
Area
Activity Description
Frequency
Pumps
Coupling
Check the security of Coupling
guards.
As per QP
schedule
Pumps
Check the security of all holdingdown bolts
As per QP
schedule
Pumps
Carry out logging of key
parameters
As per QP
schedule
12.2.2.6 Electro Chlorination
a. Filters
Equipment Description
Activity
Area
Auto Backwash Filters 6932-S-03A/B
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets for
process flow leakage. Report to
maintenance any leakage.
Operator
Rounds
Loose
Component
All
Components
Check entire skid for loose nuts &
bolts. Report to maintenance any
abnormality.
Operator
Rounds
Logging
Auto
Backwash
Filter
Carry out logging of key parameters
required.
As per QP
schedule
b. Electrolyser
Equipment Description
Activity
Area
Electrolyser 6932-G-01A/B
Degassing Tank 6932-T-02
Acid Wash Tank 6932-T-03
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets for
any leakage. Report to
maintenance for any leakage.
Operator
Rounds
Loose
Component
All
Components
Check entire skid for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance any
abnormality.
Operator
Rounds
Logging
Electrolyser/
Degassing
Tank
Carry out logging of key parameters
required
As per QP
schedule
EPIC for Gas Sweetening Facilities Project (GSF)
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Doc. No.: 2970-0-22-0001
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TITLE: OPERATION AND MAINTENANCE MANUAL
c. Tanks
Equipment Description
Activity
Area
Degassing Tank 6932-T-02
Acid Wash Tank 6932-T-03
Activity Description
Frequency
Leakage
Joints/Flang
es
Check all joints/flanges/gaskets for
process flow leakage. Report to
maintenance for any leakage.
Operator
Rounds
Loose
Component
All
Components
Check entire Skid for loose nut &
bolts, cable trays & earthing wire.
and report to maintenance for any
abnormality
Operator
Rounds
Logging
Tank
Carry out logging of Key Parameters
required.
As per QP
schedule
d. Blowers
Equipment Description
Activity
Area
Hydrogen Dilution Blowers 6932-K-01A/B
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets for
process flow leakage. Report to
maintenance any leakage.
During
Operator
Rounds
Loose
Component
All
Components
Check entire skid for loose nuts &
bolts, cable trays & earthing wire.
Report to maintenance any
abnormality.
During
Operator
Rounds
Blower
Check the blower for abnormal
noise. If abnormal, report to
maintenance.
Operator
Rounds
Motor
Check the motor for abnormal noise.
If abnormal, report to maintenance.
Operator
Rounds
Blower
Check the blower for abnormal
vibrations. If abnormal, report to
maintenance.
Operator
Rounds
Motor
Check the motor for abnormal
vibrations. If abnormal, report to
maintenance.
Operator
Rounds
Temperature
Motor
Check for abnormal motor winding
temperature. If abnormal, report to
maintenance.
Operator
Rounds
Logging
blower
Carry out logging of key parameters
of the blower required.
Operator
Rounds
Abnormal
Noise
Vibrations
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TITLE: OPERATION AND MAINTENANCE MANUAL
e. Pumps
Equipment Description
Activity
Dosing Pumps 6932-P-05A/B
Acid Wash Pump 6932-P-06
Area
Activity Description
Frequency
Leakage
Mechanical
Seal/Gland/
Joints/
Flanges
Check all joints/flanges/gaskets for
process flow leakage. Report to
maintenance for any leakage.
Operator
Rounds
Oil level
Pumps
Check lubricant level, and top up as
and when required.
Operator
Rounds
Pump
Check pump Vibration and report to
maintenance
Operator
Rounds
Motor
Check for abnormal motor Vibration
and report to maintenance
Operator
Rounds
Pump
Bearings
Check for abnormal Pump Bearings
temperature and report to
maintenance
Operator
Rounds
Pressure
Drop
Suction
Strainer
Check for any choke in Suction
Strainer. Strainer to be cleaned
periodically.
Dictated by
Pump
Discharge
Pressure
Gauge
Loose
Component
All
Components
Check entire Skid for loose nut &
bolts, cable trays & earthing wire.
and report to maintenance for any
abnormality
Operator
Rounds
Logging
Water
Carry out logging of key parameters
required.
As per QP
schedule
Vibration
Abnormal
Temperature
12.2.2.7 Demineralized Water System
a. Pumps
Equipment Description
Activity
Leakage
Regeneration Pumps 6834-P-36A/B
Recycling Pumps 6834-P-37A/B
Neutralisation Pit Pumps 6834-P-38A/B
HCl Injection Pumps 6834-P-35A/B/C
NaOH Injection Pumps 6834-P-34A/B/C
Demineralized Water Feed Pumps 6834-P-24A/B
Area
Activity Description
Mechanical
Seal/Gland/
Joints/
Flanges
Check all joints/flanges/ gaskets for
process flow leakage. Report to
maintenance for any leakage.
Frequency
Operator
Rounds
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TITLE: OPERATION AND MAINTENANCE MANUAL
Activity
Area
Activity Description
Frequency
Pumps
Check lubricant level, and top up as
and when required.
Operator
Rounds
Pump
Check pump Vibration and report to
maintenance
Operator
Rounds
Motor
Check for abnormal motor Vibration
and report to maintenance
Operator
Rounds
Pump
Bearings
Check for abnormal Pump Bearings
temperature and report to
maintenance
Operator
Rounds
Pressure
Drop
Suction
Strainer
Check for any choke in Suction
Strainer. Strainer to be cleaned
periodically.
Dictated by
Pump
Discharge
Pressure
Gauge
Loose
Component
All
Components
Check entire Skid for loose nut &
bolts, cable trays & earthing wire.
and report to maintenance for any
abnormality
Operator
Rounds
Logging
Pumps
Carry out logging of key parameters
required.
As per QP
schedule
Oil level
Vibration
Abnormal
Temperature
b. Tanks
Equipment Description
Activity
Area
Demineralised Water Storage Tank 6834-T-08
HCl Storage Tank 6834-T-16
NaOH Storage Tank 6834-T-15
Neutralisation Pit 6834-A-01
Activity Description
Frequency
Leakage
Joints/
Flanges
Check all joints/flanges/gaskets for
process flow leakage. Report to
maintenance for any leakage.
Operator
Rounds
Loose
Component
All
Components
Check entire Skid for loose nut &
bolts, cable trays & earthing wire.
and report to maintenance for any
abnormality
Operator
Rounds
Logging
Tank
Carry out logging of Key Parameters
required.
As per QP
schedule
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TITLE: OPERATION AND MAINTENANCE MANUAL
c. Vessels
Equipment Description
Activity
Cation Exchangers 6834-S-21A/B
Anion Exchangers 6834-S-22A/B
Area
Activity Description
Frequency
Joints/Flanges
Check all joints/flanges/gaskets
for any leakage. Report to
maintenance for any leakage.
Operator
Rounds
Loose
Component
All Components
Check entire unit for loose nuts
& bolts, cable trays & earthing
wire. Report to maintenance for
any abnormality.
Operator
Rounds
Logging
Cation Exchangers
6834-V-02A/B,
Anion Exchangers
6834-V-03A/B
Carry out logging of key
parameters required.
As per QP
schedule
Leakage
12.2.2.8 Boiler Feed Water System
a. Pumps
Equipment Description
Activity
Area
Deaerator Feed Pumps 6834-P-20A/B
Boiler Feed Water Pumps 6834-P-22A/B/C
Activity Description
Frequency
Leakage
Mechanical
Seal/Gland/
Joints/Flanges
Check all joints/flanges/gaskets
for process flow leakage. Report
to maintenance for any leakage.
Operator
Rounds
Oil level
Pumps
Check lubricant level, and top
up as and when required.
Operator
Rounds
Pump
Check pump Vibration and
report to maintenance
Operator
Rounds
Motor
Check for abnormal motor
Vibration and report to
maintenance
Operator
Rounds
Pump Bearings
Check for abnormal Pump
Bearings temperature and
report to maintenance
Operator
Rounds
Suction Strainer
Check for any choke in Suction
Strainer. Strainer to be cleaned
periodically.
Dictated by
Pump
Discharge
Pressure
Gauge
Vibration
Abnormal
Temperature
Pressure
Drop
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TITLE: OPERATION AND MAINTENANCE MANUAL
Activity
Area
Activity Description
Frequency
Loose
Component
All Components
Check entire Skid for loose nut &
bolts, cable trays & earthing
Operator
wire. and report to maintenance Rounds
for any abnormality
Logging
Water
Carry out logging of key
parameters required.
b.
Vessels
Equipment Description
Activity
Area
Leakage
Joints/Flanges
Loose
Component
All Components
Logging
Steam Condensate
Flash Drum
6834-V-05, BFW
Deaerator Package
6834-A-08
c.
As per QP
schedule
Steam Condensate Flash Drum 6834-V-05
BFW Deaerator Package 6834-A-08
Activity Description
Check all joints/flanges/gaskets
for any leakage. Report to
maintenance for any leakage.
Check entire unit for loose nuts
& bolts, cable trays & earthing
wire. Report to maintenance for
any abnormality.
Carry out logging of key
parameters required.
Frequency
Operator
Rounds
Operator
Rounds
As per QP
schedule
Air Coolers
Equipment Description
Activity
Area
Leakage
Joints/Flanges
Loose
Component
All Components
Motor Bearing
Grease/
Oil Level
Motor
Temperature
Motor
Logging
Steam Condensate
Cooler
Steam Condensate Cooler 6834-E-02
Activity Description
Check all joints/flanges/gaskets
for process flow leakage. Report
to maintenance any leakage.
Check entire skid for loose nuts
& bolts, cable trays & earthing
wire. Report to maintenance for
any abnormality.
Check lubricant levels, and top
up as and when required.
Check for abnormal motor
vibrations and report to
maintenance
Check for abnormal motor
Temperature and report to
maintenance
Carry out logging of key
parameters required.
Frequency
Operator
Rounds
Operator
Rounds
Operator
Rounds
Operator
Rounds
Operator
Rounds
As per QP
schedule
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TITLE: OPERATION AND MAINTENANCE MANUAL
12.2.2.9 Steam Generation System
a.
Fans
Equipment Description
Activity
FD Fan 6848-K-02A
Flue Gas Recirculation Fan 6848-K-03A
Area
Leakage
Joints/Flanges
Loose
Component
All Components
Oil Level
Bearings and Gear
Box
Fan
Abnormal
Noise
Motor
Blower
Vibrations
Motor
Temperature
Motor
Logging
Fan
b.
Activity Description
Check all joints/flanges/gaskets
for process flow leakage. Report
to maintenance any leakage.
Check entire skid for loose nuts
& bolts, cable trays & earthing
wire. Report to maintenance
any abnormality.
Check the oil levels (Top-up
lube oil as and when required)
Check the blower for abnormal
noise. If abnormal, report to
maintenance.
Check the motor for abnormal
noise. If abnormal, report to
maintenance.
Check the blower for abnormal
vibrations. If abnormal, report
to maintenance.
Check the motor for abnormal
vibrations. If abnormal, report
to maintenance.
Check for abnormal motor
winding temperature. If
abnormal, report to maintenance.
Carry out logging of key
parameters
Frequency
During
Operator
Rounds
During
Operator
Rounds
Daily
Operator
Rounds
Operator
Rounds
Operator
Rounds
Operator
Rounds
Operator
Rounds
Each shift
Drums
Equipment Description
Activity
Area
Steam Drum 6848-V-02A
Activity Description
Frequency
Joints/ Flanges
Check all joints/flanges/gaskets
for any leakage. Report to
maintenance for any leakage.
Operator
Rounds
Loose
Component
All Components
Check entire unit for loose nuts
& bolts, cable trays & earthing
wire. Report to maintenance for
any abnormality.
Operator
Rounds
Logging
Steam Drum
6848-V-02A
Carry out logging of key
parameters required.
As per QP
schedule
Leakage
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TITLE: OPERATION AND MAINTENANCE MANUAL
c.
Combustion Chamber
Equipment Description
Activity
Steam Generation System
Area
Activity Description
Frequency
Joints/Flanges
Check all joints/flanges/gaskets
for any leakage. Report to
maintenance for any leakage.
Operator
Rounds
Loose
Component
All Components
Check entire skid for loose nuts
& bolts, cable trays & earthing
wire. Report to maintenance
any abnormality.
Operator
Rounds
Logging
Steam Generation
System
Carry out logging of key
parameters required
As per QP
schedule
Leakage
d.
Phosphate Dosing Package
Phosphate Storage Tank
Equipment Description
Activity
Area
Phosphate Storage Tank 6848-T-01A
Activity Description
Frequency
Gland/
Joints/Flanges
Check all joints/flanges/gaskets
for process flow leakage. Report
to maintenance for any leakage.
Operator
Rounds
Loose
Component
All Components
Check entire Skid for loose nut
& bolts, cable trays & earthing
wire. and report to
maintenance for any
abnormality
Operator
Rounds
Logging
Tank
Carry out logging of Key
Parameters required.
As per QP
schedule
Leakage
Phosphate Dosing Pumps
Equipment Description
Activity
Area
Phosphate Dosing Pumps 6848-P-01A/02A
Activity Description
Frequency
Leakage
Mechanical
Seal/Gland/
Joints/Flanges
Check all joints/flanges/gaskets
for process flow leakage. Report
to maintenance for any leakage.
Operator
Rounds
Oil level
Pumps
Check lubricant levels, and top
up as and when required.
Operator
Rounds
Pumps
Check pump Vibrations and
report to maintenance
Operator
Rounds
Motor
Check for abnormal motor
Vibrations and report to
maintenance
Operator
Rounds
Vibration
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TITLE: OPERATION AND MAINTENANCE MANUAL
Activity
12.3
Area
Activity Description
Loose
Component
All Components
Check entire Skid for loose nut
& bolts, cable trays & earthing
wire. and report to
maintenance for any
abnormality
Logging
Pumps
Carry out logging of key
parameters required
Frequency
Operator
Rounds
As per QP
schedule
SHUTDOWN MAINTENANCE
a. Plant and Instrument Air Compressor & Dryer
For detailed Maintenance Procedures, refer vendor “Installation, Operation and
Maintenance Manual” 2970-0006-5-26-0002
b.
Steam Generation Package 6848-A-02A/B/C
For detailed Maintenance Procedures, refer vendor “Installation, Operation and
Maintenance Manual” 2970-0025-5-26-0002
c.
Electrochlorination Package 6932-A-05
For detailed Maintenance Procedures, refer vendor “Technical Installation, Operating
and Maintenance Manual” 2970-0008-5-26-0003
d.
Sea Cooling Water Pumps 6932-P-04A/B
For detailed Maintenance Procedures, refer vendor “Installation, Operation and
Maintenance Manual” 2970-0028-5-26-0002
e.
Chemical Injection Package
For detailed Maintenance Procedures, refer vendor “Installation, Operation and
Maintenance Manual” 2970-0102-5-26-0006
f.
Combustion Air Blowers 9102-K-11A/B
For detailed Maintenance Procedures, refer vendor “Installation, Operation and
Maintenance Manual” 2970-0101-5-00-0004
12.4
CATALYST LOADING & SPECIAL PROCEDURES
Catalyst loading has to be carried out for the following reactors:
1. SRU 1st Stage & 2nd Stage Converters
2. Hydrogenation Reactor
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SRU 1st Stage & 2nd Stage Converters/Hydrogenation Reactor
12.4.1
a.
Catalyst loading
This operation is carried out taking precautions highlighted hereafter:
Note: The catalyst is a sophisticated product and should be handled carefully,
avoiding any hazardous loss.
•
Before loading, it is recommended to check that all reactors are dry, clean and
that all internals are in the proper place and installed as recommended in the
various drawings and process data sheets
•
Covers must be installed at the top of each reactor on temporary structures to
protect against rain
•
Loading of catalyst shall not be done during a period of rain or of great level of
humidity
b.
Preliminary operations
•
When the reaction section drying out is complete and nitrogen has been replaced
by air, the reactors can be opened for inspection of the internals. All damaged
internal parts must be replaced or repaired
•
If needed, the reactors will be brushed and vacuum cleaned before catalyst
loading starts
•
Catalyst loading will be interrupted in case of rain or snow, or efficient protection
must be set in place
c.
Equipment and personnel
The list below is based on the following assumption: catalyst loading will be carried
out with one crane.
•
One telescopic crane capable of lifting about 3 tons, 5 meters above the reactor
upper manhole (see Fig. 33)
•
One forklift to handle the catalyst drum pallets
•
Stationary hopper equipped with 8 to 10" nozzles to be installed on the reactor
upper manhole (see Fig. 38)
•
Two mobile hoppers, each having a capacity of about 5 to 6 catalyst drums (see
Fig. 37)
•
One structure (scaffolding and timbers) to unload the drums into the mobile
hoppers (see Fig. 35)
•
One safety harness, rope ladders, portable oxygen analyzer, low voltage lighting,
dust masks, air masks, goggles, plastic sheets to protect drums and reactor in case
of rain
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TITLE: OPERATION AND MAINTENANCE MANUAL
•
To serve the above mentioned equipment the following personnel is necessary:
•
One foreman
•
One crane operator
•
One fork lift operator
•
One team of 4 riggers at ground level for catalyst handling and loading into
the mobile hoppers
•
One team of 6 fitters for vessels opening closing and for catalyst loading,
•
One sock loading operator inside the reactor.
Note: These personnel shall be permanently present during the loading operation. The
total number of personnel will be obtained by multiplying by the number of shifts, if
the loading takes place on 24 hours basis.
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Fig. 33 – Catalyst handling with drums
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Fig. 34 – Catalyst handling with big bags
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Fig. 35 – Filling up the hopper at ground level from drums
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Fig. 36 – Ground level preparation for big bag lifting
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Fig. 37 – Catalyst Loading – Mobile Hopper
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Fig. 38 – Catalyst Loading – Stationary Hopper
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Fig. 39 – Catalyst Loading – Slide Valve
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Fig. 40 – Sock loading under air
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TITLE: OPERATION AND MAINTENANCE MANUAL
d.
Catalyst loading procedure
•
Check that the quality of the catalyst and the amount available are as specified.
•
The following guideline for the reactor loading assumes a single catalyst bed. It
also assumes that the internals have been, first inspected in position and then
dismantled to speed up the loading process. When there is only one catalyst bed,
internals (except the bottom collector) would be installed and inspected after the
catalyst loading.
•
Refer to the loading drawing for the various heights of catalyst and alumina layers
etc., and to the detail drawings for the installation of the internals. Inside the
reactor measures will be taken from the welding line. Manufacturer's vessels
measurements are generally shown from tangent lines.
•
Make the necessary adjustment. Materialize the various levels with chalk marks on
the reactor wall.
•
Before loading catalyst ensure that operators have available wooden boards upon
which to stand when inside the reactor, to spread their weight and avoid crushing
of catalyst with the feet. Ensure also that the boards are counted into the reactor
and from time to time during loading and as they are taken out of the reactor.
Boards left in the reactor will interfere with pressure drop and flow distribution.
•
The reactor to be loaded should be placed under a reverse air flow to remove any
dust generated during the loading process, out of the reactor. Ideally, the dust
should be collected in bag filters installed at the outlet man-way.
•
Lift down the required volume of inert support balls, or active supports as
appropriate, and build up the bottom layer. Carefully level the surface, before
loading catalyst
•
Start loading the catalyst bed according to the loading diagram. The person
inside the reactor shall build a level of catalyst as uniformly as possible
•
During the catalyst loading a sample shall be taken in each drum/big bag in
order to prepare a composite sample of the reactor load.
•
when the upper level of the catalyst bed is reached stop loading the catalyst
and carefully level the surface
•
Add the layer of ½” or ¾” hold down balls on top of the active catalyst if
required.
Note: Vendor does recommend loading inert ceramic balls to hold down the active
catalyst if no deflector is installed in the vessel, and/or if the active catalyst bed
height is lower than 90 cm.
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TITLE: OPERATION AND MAINTENANCE MANUAL
If deflector is installed and if the catalyst bed height is comprised in between 0.9 and
1 m, Vendor advises to load ceramic balls, when the height difference in between the
deflector and the top of the active catalyst is lower than 1 m.
According to what Vendor commonly sees, hold down ceramic balls can be avoided if a
deflector is installed and if the active catalyst bed height is larger than 1 m. Loading
hold down balls may also be avoided if a deflector is installed and if the active catalyst
bed height is comprised in between 0.9 and 1m, providing that the height difference in
between the deflector and the top of the active catalyst is larger than 1 m.
•
Install the inlet distributor and the top flange
A loading report must be carefully filled with:
•
Number of drums or big bags loaded in each layer
•
Catalyst batch and drum/big bag reference numbers
The loading density is checked at the end of the loading.
e.
Leak test
After closure of the reactor and prior to catalyst activation, leak tests will be
conducted.
f.
Catalyst Handling
The SRU first and second Claus converters are part filled with alumina and titanium
dioxide catalysts, the titanium dioxide catalyst being located in the bottom of the
converter with the alumina on top. The titanium dioxide catalyst is supported on the
ceramic balls support material.
The TGTU hydrogenation reactor contains a special CoMo catalyst which is supported
on ceramic balls support material. A layer of ceramic balls material is also located on
the top of the catalyst to protect the catalyst from refractory dust and debris that
may be carried forward from the upstream SRU.
All catalysts and ceramic ball support material will be delivered to site in either one
tonne big bags or 220 litre drums. Until the time of loading into a converter/reactor
all catalyst should be kept in a covered heated warehouse to ensure no contamination
from rain, sand, dust or low temperature damage can occur.
12.4.2
Catalyst Activity & Life Expectancy
a.
SRU Converters
Provided the acid feed gases being processed in the SRU compositions are near to
design then the converters catalysts can be expected to operate satisfactorily for a
minimum of three years before replacement is necessary.
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Catalyst life can be prolonged by maintaining a low hydrocarbon content in the acid
gas feed, by preventing carryover of amine solutions to the SRU, by ensuring that
ammonia salts are not being formed in the process, by avoiding emergency shutdown
conditions during which the catalyst beds may be exposed to high temperatures caused
by burning sulphur, and by operating care to avoid water condensation on the catalyst.
The first catalyst bed generally accounts for most of the conversion. Therefore, the
life expectancy of the second bed will almost always exceed that of the first. A shift
of the primary activity from the first to second bed is a reliable indication that the
first bed requires attention.
The best measure of a SRU converters catalyst activity is the percentage of H2S
conversion to sulphur obtained in normal operation. This activity will decrease over a
period of time, depending on the quality of acid gas feed used and the care with which
the SRU is operated. Normally a loss of activity will be seen in the first converter with
the point of reaction and temperature increase, moving down the catalyst bed. The
activity of the catalyst is observed by watching the temperature change across the
converter bed. Good activity is observed when a significant temperature increase is
seen in the top/upper portion of the catalyst bed. Record the bed temperature
differentials at the initial start-up, during, and at the end of a run as a reference for
operation of the unit. A permanent decrease in temperature differential usually
indicates catalyst deactivation. Normally, this is an accumulation of carbon, sulphates,
or other contaminants on the bed. An indication of sulphate formation in the catalyst
is by the increased concentrations of COS, CS2 and CO in the treated gas from the
upstream amine absorbers. Some catalyst activity may be restored by carrying out the
catalyst management procedures.
Since catalyst life expectancy cannot be predicted accurately in advance for any given
SRU, it is a good practice to maintain a full replacement supply of catalyst for the
converters of one SRU in the refinery warehouse, or be able to acquire the catalyst
quickly from the catalyst supplier should a replacement charge of catalyst be
required.
After sufficient data has been accumulated on the catalysts conversion performance,
it is generally advisable to replace all or part of the catalyst on a regular time
schedule.
b.
TGTU Hydrogenation Reactor
Under normal operations this catalyst is expected to maintain its activity for a
minimum of six years.
A hydrogen gas concentration of >1.5% is required to ensure conversion of the sulphur
compounds in reactors feed gases to hydrogen sulphide. Catalyst life will be prolonged
if a hydrogen concentration of approximately 3% is recorded by the amine absorber
vent gas outlet analyser.
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Similarly to the SRU converters catalysts the TGTU Hydrogenation Reactor catalyst
activity is observed by watching the temperature change across the reactor bed. Good
activity is observed when a significant temperature change occurs in the top/upper
portion of the catalyst bed. Also records of the catalyst bed temperature differentials
should be taken at the initial start-up, during, and at the end of a run as a reference
for operation of the unit.
Although the Hydrogenation Reactor catalyst is not likely to be fouled and deactivated
by contaminants as the SRU converters catalysts may be it is advised to maintain a full
replacement supply of catalyst for one TGTU Hydrogenation Reactor in the refinery
warehouse or be able to acquire the catalyst quickly from the catalyst supplier should
a replacement charge of catalyst be required. Some catalyst activity may be restored
by carrying out the catalyst management procedures.
12.4.3
Catalyst Preparation
When preparing to inspect and/or replace a SRU or TGTU reactors catalyst the
SRU/TGTU must first follow the normal shutdown and sulphur stripping and
regeneration procedures.
Following the shutdown of the unit no vessel should be entered until it has been
cooled and all process gas utility streams to the SRU/TGTU have been isolated. Prior
to entry to a converter/reactor the vessel must be tested to determine if it is free of
noxious gases. Even when a satisfactory oxygen reading is recorded in the vessel it is
advised that persons entering the vessel should be supplied with an air mask and a
safety belt and that a safety attendant/standby person is continually stationed outside
the vessel to monitor the person(s) in the vessel.
a.
Catalyst Sampling
When a SRU converter or the TGTU hydrogenation reactor is first opened it is advised
that samples of the catalysts are taken and sent to the catalyst supplier for analysis.
Samples should be taken from various levels in the beds.
b.
Catalyst Inspection
The inspection of the catalyst will determine if part, or the complete, catalyst bed is
to be replaced because of catalyst contamination, fusion with other products, loss of
granular size or evidence of reduced activity.
c.
Catalyst Replacement
Catalyst replacement alternatives are described in the following sub-sections:
d.
Top Layer Replacement
If the deactivation of the catalyst is caused by fusion or some condition affecting only
the top layer, carefully remove this layer, rake and smooth the top of the remaining
catalyst bed and replace with new catalyst to the design bed depth.
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e.
Full Bed Replacement with Old and New Catalyst
If the contamination and deterioration extends deeper into the catalyst bed it is
advised to remove and screen the remainder of the catalyst and then recharge the
usable portion.
If the entire catalyst bed is to be removed proceed as follows:
If installed, carefully remove any top layer of ceramic balls followed by the catalyst
and catalyst support layer ceramic balls.
Screen the ceramic balls.
Examine the process gas outlet pipe and screens.
Replace the catalyst support ceramic balls in the bottom of the vessel.
Screen the catalyst that was removed, discard the fines and reserve the usable portion.
Add enough new catalyst to compensate for the amount discarded and spread this in
an even layer over the catalyst support ceramic balls.
Add the screened used catalyst to bring the bed to full depth.
If required add the top layer of ceramic balls.
f.
Full Bed Replacement with New Catalyst
If inspection shows the whole catalyst bed is of questionable value, replace all the old
catalyst with new. Follow the applicable steps for a full bed replacement above.
Inspect the physical condition of the new catalyst to determine if screening is required
to remove fines. Do not screen unless necessary and avoid excessive handling.
g.
Catalyst Unloading Methods
A gravity method or a vacuum method may be used to remove catalyst from a
converter/reactor. If the catalyst is to be reused then the gravity method is advised so
that a minimum of damage and the production of catalyst fines and dusts are produced
during the unloading operation.
Unloading is carried out through temporary chutes connected to the converter/reactor
side manways with the catalyst collected in clean dry drums or other suitable
containers. During the unloading process care should be taken to separate the ceramic
balls support material from the catalyst. For the SRU first and second converter care
will have to be taken to separate the titanium dioxide catalyst from the alumina
catalyst during the unloading operations.
If only the top section of catalyst in a converter has to be replaced then this layer is
normally removed by hand through the converters top manways; alternatively if care is
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taken, then the catalyst may be removed through the converters top manways by
means of the vacuum method.
If the catalyst is not to be reused then vacuum method is advised as this method
minimises the unloading time and does not require the opening of the converters side
manways.
h.
Catalyst Disposal
Regenerated alumina catalyst may be disposed of to a land fill site. Titanium dioxide
and hydrogenation catalysts should be disposed of via a catalyst reclamation company.
At the end of the life of each catalyst it is advised that the supplier is consulted
regarding its disposal.
12.4.4
Catalyst Management
a.
SRU Reactor Catalyst
The alumina catalyst in the SRU converters consists of small spheres that have very
small pores. The H2S and SO2 gases enter into these pores and emerge as sulphur and
water vapour. Some sulphur in the liquid phase may collect in the catalyst and over a
period of time will lower the sulphur conversion efficiency making it necessary for the
catalyst beds to be given a rejuvenation or heat soak. A loss of catalyst activity is seen
by the temperature increase and start of the exothermic reaction moving further down
the converters catalyst beds.
To improve converters catalyst activity a rejuvenation of the catalyst is carried out with
the SRU and TGTU in normal operation processing acid feed gas. If no improvement in
conversion is seen, a sulphur stripping procedure will then be necessary.
A sulphur stripping procedure may also be required if the catalyst is contaminated by
carbon laydown from hydrocarbons carried in the unit’s acid feed gas or because of
contamination by liquid carryover with the acid gas from the Amine Regenerator which
is so severe that a SRU shutdown is required and the converters opened to replace the
contaminated catalyst.
Prior to sulphur stripping, the catalyst beds and the SRU will contain potentially
hazardous and contaminating materials such as H2S, SO2, sulphur and other sulphurous
compounds. The object of the sulphur stripping exercise is to remove these
contaminants under controlled conditions.
At the conclusion of the sulphur stripping operations the catalyst should be clean and
the plant should be free of harmful gases and deposits.
A sulphur stripping operation will also be carried out before the plant is opened for
any maintenance work, where there is a possibility of air entering the system, which
could cause the ignition of any sulphurous compounds in the catalysts or process gas
stream side of the unit.
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Sulphur stripping is carried out with the SRU Reaction Furnace burner operating on
fuel gas only, initially at stoichiometric firing conditions.
Sulphur stripping should only be carried out for the requirements stated above, since
the operation can be potentially hazardous to both catalyst and equipment.
b.
TGTU Hydrogenation Reactor Catalyst
Under normal operations this catalyst is expected to maintain its activity for many
years, much longer than the SRU catalysts.
A hydrogen gas concentration normally of >1.5% is advised to ensure efficient
conversion of the sulphur compounds in reactor’s feed gas to hydrogen sulphide.
Catalyst life will be prolonged if a hydrogen concentration of approximately 2-4% is
seen by the Tail Gas Amine Absorber outlet vent gas H2 analyser.
The activity of the catalyst is observed by watching the temperature change across the
reactor bed. Good activity is observed when a significant change occurs in the upper
portion of the bed. A decrease in activity will be seen by the point of start of
temperature increase moving down the catalyst bed. A permanent decrease in
temperature differential usually indicates catalyst deactivation. Normally, this is an
accumulation of carbon, sulphates or other contaminants on the catalyst bed.
Sulphation of the catalyst will be increased if concentrations of COS, CS2 and CO in
the acid feed gas increase.
Increasing the Hydrogenation Reactor inlet temperature by a few degrees above
normal will help to restore some catalyst activity.
Oxidation of the Hydrogenation Reactor catalyst will restore some activity. Oxidation
must be carried out prior to the TGTU being opened for maintenance and inspection.
Prior to unit restart the catalyst will require sulphiding.
12.4.5
SRU Converter Catalyst Rejuvenation:
A catalyst rejuvenation is carried out whilst the SRU and TGTU are in normal operation
processing acid gas.
The rejuvenation will proceed as follows:
•
Slowly increase the SRU converters auxiliary burners outlet temperatures as high as
possible above normal operating temperatures for the first auxiliary burner,
~260°C, and to ~235°C for the second auxiliary burner.
•
Hold these temperatures for 24 hours to allow any sulphur contained in the catalyst
pores to flow out of the pores.
•
After 24 hours, still holding the higher than normal auxiliary burners outlet
temperatures, go off ratio at the SRU Reaction Furnace to decrease the volume of
air to the reaction furnace burner to produce a H2S:SO2 ratio of approx. 5.0:1.0 in
the unit's tail gases as indicated by the tail gas analyser.
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•
Maintain this rich in H2S ratio for 24/36 hours.
•
Following this hold period return to normal operations with a tail gas H2S:SO2 ratio
of 4.0:1.0.
•
Reduce auxiliary burners outlet
temperatures of 230°C and 210°C.
•
If following a number of rejuvenation exercises, no temperature increase is seen
across the converters then a stripping exercise will have to be carried out in an
attempt to re-establish catalyst activity.
12.4.6
temperatures to their
normal
operating
SRU Converter Catalyst Stripping
To carry out this exercise the TGTU is first taken out of service and the SRU tail gas
routed directly to the Incinerator.
The procedure for sulphur stripping the SRU converters catalyst may be broken down
into three sub-procedures:
I.
•
Hot inert gas sweep
•
Sulphur stripping
•
Cool down
Hot Inert Gas Sweep
A hot inert gas sweep of the SRU converters catalyst will commence as soon as acid gas
feed to the Reaction Furnace burner has been stopped and the burner is operating only
on fuel gas at slightly sub-stoichiometric firing conditions with LP steam injection to
the fuel gas and process air lines to the Reaction Furnace burner.
During the hot inert gas sweep note the following:
•
Monitor the converters temperatures closely and increase the flow of fuel gas if an
unexpectedly high temperature, (indicating burning of sulphur compounds), is
seen in the converters catalyst beds.
•
Hold this hot inert gas sweep of the converters catalyst beds for a period that
includes four hours after the flow of sulphur is seen to cease from all condensers
sulphur seals, before proceeding with a sulphur stripping operation.
II. Sulphur Stripping
Sulphur stripping will commence immediately following the completion of the hot inert
gas sweep of the unit as described above.
Sulphur stripping will proceed as follows:
•
Confirm that the auxiliary burners outlet and converters catalyst bed
temperatures are at 230°C and 210°C.
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•
With process air and fuel gas controllers in manual operating mode, very slowly
increase process air flow to the Reaction Furnace burner by adjustments to
process air controller.
•
Maintain the auxiliary burners temperature outlet controllers in automatic
operating mode throughout the sulphur stripping operation set at their normal
operating temperatures of 230°C and 210°C.
•
Every few minutes increase process air flow in very small increments until there is
evidence of burning of sulphur compounds within the SRU. Note that the trim air
control valve may be used to allow a fine control of excess process air is achieved.
•
Observe all temperature points across the SRU.
•
The first sign of the burning of sulphur compounds in the SRU should be seen by a
temperature increase in the top layer of catalyst in the first converter. A
temperature increase may also be seen in the Reaction Furnace Condenser process
gas outlet or 1st Stage Condenser process gas outlet as sulphur compounds in these
sections commence burning.
•
Hold the process air flow at its present flow when a temperature front is seen in
the first converter.
•
Note the flows of fuel gas and process air.
•
Closely observe the converters catalyst bed temperatures, if temperatures
approach 400°C, reduce the amount of process air to the Reaction Furnace
burner.
Note: Under no circumstances should converter catalyst temperatures exceed 425°C
(or other temperature advised by the catalyst supplier).
•
In the event of a sudden increase in temperature in a converter catalyst bed,
immediately increase fuel gas flow to allow the fuel gas to consume any excess
oxygen and to stop the temperature rise. This action will ensure a flow of hot
combustion gas through the unit at a high flow rate to displace any pockets of gas
which contain high oxygen content.
•
Once the temperature front has passed through the first converter it will move
into the second converter. There may be some overlapping of temperature fronts
between the first and second converters due to the possibility of channelling of
gases through the first converter catalyst.
•
When the temperature front has moved through the second converter catalyst,
over a period of eight hours, gradually reduce the flow of fuel gas to the reaction
furnace burner leaving the process air flow unchanged to allow an excess of
oxygen to appear in the process gas stream.
•
Closely observe all temperature points across the unit for any secondary burning
of sulphur compounds. If secondary burning is seen, immediately increase fuel gas
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flow to the reaction furnace burner to consume the excess oxygen in the process
gases and halt the temperature increase in the area of burning.
III. Cool Down
Cool down will commence immediately after sulphur stripping of the converters
catalyst is completed as follows:
•
Close MS steam control valve to the process air pre-heater.
•
Start increasing process air flow to the Reaction Furnace burner whilst holding fuel
gas flow constant. The Reaction Furnace temperature will slowly fall.
•
With process air at a fairly high flow, start lowering process temperatures by
reducing fuel gas flow to the Reaction Furnace burner.
•
Start reducing converters catalyst bed temperatures by reducing auxiliary burners
outlet temperatures at 50°C/hr.
•
When <400°C is seen in the Reaction Furnace, stop LP steam injection to the fuel
gas and combustion lines to the Reaction Furnace burner and manually isolate.
Also close LP steam to the acid gas bypass line to the reaction furnace.
•
Continue reducing fuel gas flow to the Reaction Furnace burner until the lowest
temperature possible is seen on the reaction furnace and converters temperature
indicators, ideally ~100°C, then stop fuel gas flow to the Reaction Furnace burner.
•
Isolate fuel gas to the auxiliary burners.
•
Continue process air flow through the SRU to further cool the equipment to near
blower discharge/ambient temperature.
The SRU converter catalyst regeneration procedure is now complete.
12.4.7
TGTU Hydrogenation Reactor Catalyst Oxidation:
If the SRU and TGTU are to be opened for inspection and maintenance at the same
time then the sulphur stripping of the SRU converters and the oxidation of the TGTU
Hydrogenation Reactor may be carried out in the same operation. In this case the
oxidation of the Hydrogenation Reactor catalyst would be carried out in series with
the sulphur stripping of the SRU converters catalyst as described in Section 12.4.7-I
If the TGTU is to be opened for inspection and maintenance independently of the SRU
then the TGTU Hydrogenation Reactor oxidation is carried out as a stand alone
procedure as described in Section 12.4.7-II
I. TGTU Hydrogenation Reactor Catalyst Oxidation – (In series with the SRU
converters sulphur stripping operation):
Oxidation of the Hydrogenation Reactor in series with the sulphur stripping of the SRU
converters will proceed as follows:
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•
Confirm that the RGG outlet/Hydrogenation Reactor inlet temperature is at 290°C
•
Open the Reactor Effluent Cooler 9102-E-11 outlet process gas valve to the
Incinerator and close the Reactor Effluent Cooler outlet valve to the Contact
Condenser to take the TGTU wet section out of service.
•
Proceed with the sulphur stripping of the SRU converters catalyst beds as
described in section 12.4.6.
•
When the second SRU converter catalyst bed sulphur stripping is complete, or near
complete the excess oxygen in the SRU process air that was used to sulphur strip
the SRU converters catalysts will pass through to the TGTU to commence the
oxidation of the Hydrogenation Reactor catalyst. Note that there may be some
overlapping of sulphur stripping of the third SRU converter and the oxidation of
the Hydrogenation Reactor.
•
Closely observe the Hydrogenation Reactor catalyst temperatures, if temperatures
approach 400°C then reduce the amount of process air to the SRU Reaction
Furnace burner.
Note: Under no circumstances should the Hydrogenation Reactor catalyst
temperatures exceed 425°C (or other temperature advised by the catalyst
supplier).
•
When the catalyst oxidation is complete as seen by the temperature front having
passed through the Hydrogenation Reactor catalyst bed the fuel gas flow to the
SRU Reaction Furnace burner is slowly decreased, leaving the process air flow
unchanged so allowing an excess of oxygen in the process gases passing through
the SRU converters and TGTU Hydrogenation Reactor.
•
Maintain close observation of all temperature points across the SRU converters and
the TGTU Hydrogenation Reactor for any secondary burning. If secondary burning
is seen then increase fuel gas flow to the SRU Reaction Furnace burner to consume
the excess oxygen in the process gases and halt the temperature increase in the
area of burning.
•
Following oxidation of the Hydrogenation Reactor
hydrogenation section is cooled down with the SRU.
•
Reduce RGG outlet temperatures at approx. 50°C/hr to cool the Hydrogenation
Reactor catalyst. Note that the RGG process air to fuel gas ratio may now be
adjusted so that the RGG burner is operating in excess air conditions.
•
When ~100°C is seen in the Hydrogenation Reactor catalyst, via the shutdown
switch, stop the RGG.
catalyst,
the
TGTU
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•
Confirm that the action of the shutdown switch has closed or opened the following
RGG shutdown valves:
•
Nitrogen valve to the RGG combustion air line, open (valve will remain open
for ~15 minutes)
•
Nitrogen valve to the RGG instrument nozzles, open
•
Instrument air to the RGG instrument nozzles, closed
•
Combustion air valve, closed
•
Fuel gas, two valves closed and vent valve open
•
LP steam, closed
•
After a set time of ~15 minutes, confirm that the nitrogen purge valves to the RGG
combustion air line and to the RGG instrument nozzles have closed.
•
Close manual valves in the RGG combustion air, instrument air, fuel gas and LP
steam lines to the RGG.
The TGTU Hydrogenation Reactor may now be opened for inspection and maintenance.
Note: Complete oxidation of a TGTU Hydrogenation Reactor catalyst and the
elimination of all pyrophoric material in the reactor can sometimes be difficult to fully
carry out in a catalyst oxidation exercise. Care should therefore be taken when
opening a Hydrogenation Reactor as ignition of any pyrophoric material in pockets of
sulphided catalyst may result.
II. TGTU Hydrogenation Reactor Catalyst Oxidation – (Independent of the SRU
converters sulphur stripping operation):
In the event that the TGTU is taken out of service independently of the SRU and has to
be opened for inspection and maintenance then all sulphur compounds in the
Hydrogenation Reactor catalyst must be first removed by regeneration of the catalyst.
This is achieved by recycling nitrogen gases around the RGG, Hydrogenation Reactor,
Reactor Effluent Cooler and the DCC tower by means of the start-up gas steam ejector
and by adjusting the amount of excess air to the RGG burner to burn off all sulphur
compounds on the Hydrogenation Reactor catalyst. This procedure should be carried
out immediately after the TGTU is shutdown when the Hydrogenation Reactor catalyst
is still near its normal operating temperature.
Regeneration of the Hydrogenation Reactor catalyst may proceed as follows:
•
Shutdown the TGTU as described in Section 10.1.1 leaving the DCC top and bottom
circulating waters in service and a BFW level in the Reactor Effluent Cooler
•
Confirm that the SRU tail gas valve to the TGTU is closed
•
Confirm that the process gas valve from the Reactor Effluent Cooler to the DCC is
open
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•
Close the DCC process gas outlet valve to the Tail Gas Amine Absorber
•
Open manual valve in gas recycle line from the DCC outlet process gas line to the
RGG inlet line
•
Set vent gas pressure control valve from the DCC vent gas outlet line to the
Incinerator at 0.25 barg
•
Introduce a flow of nitrogen into the RGG inlet line
•
Observe the start-up pressure control valve opening to control the excess nitrogen
gases to the Incinerator
•
Open start-up gas steam ejector process gas inlet and outlet manual valves
•
Open LP steam to the start-up gas steam ejector to start circulating nitrogen gases
around the TGTU BSR section. Nitrogen gases will flow through and around the
RGG, Hydrogenation Reactor, Reactor Effluent Cooler and DCC with excess gases
being vented to the Incinerator via the recycle gas pressure control valve.
•
Ignite the RGG burner on fuel gas at normal slightly sub-stoichiometric firing
conditions and set RGG outlet temperature controller set point at 250ºC.
•
Open LP steam shutdown valve to the RGG and introduce steam to the RGG fuel
gas line to suppress the formation of carbon and soot at stoichiometric firing
conditions. Set the steam flow in a ratio of 2:1 (by wt) to fuel gas.
Notes:
1. As the Hydrogenation Reactor now contains sulphur compounds the RGG burner
must be operated at its normal, slightly sub-soichiometric, firing conditions.
2. If the Hydrogenation Reactor catalyst has cooled then slowly raise temperatures at
50°C/hr to 250ºC.
•
Slowly adjust the RGG combustion air to fuel gas ratio controller to allow a small
excess of combustion air at the RGG burner.
•
Observe all temperature points across the Hydrogenation Reactor
•
The first sign of the burning of sulphur compounds in the Hydrogenation Reactor
should be seen by a temperature increase in the top layer of catalyst.
•
Hold the RGG excess combustion air conditions when a temperature front is seen
in the Hydrogenation Reactor. Note the flow of combustion air and fuel gas.
•
Closely observe the Hydrogenation Reactor’s catalyst temperatures, if
temperatures approach 400°C, adjust the RGG combustion air to fuel gas ratio
controller to reduce the flow of combustion air to the RGG.
Note: Under no circumstances should catalyst temperatures exceed 425°C (or other
temperature advised by the catalyst supplier).
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•
In the event of a sudden increase in temperature in a reactor catalyst bed,
immediately adjust the RGG combustion air to fuel gas ratio controller to
stoichiometric firing conditions to stop excess air in the RGG combustion gases
Note: This action will ensure a flow of hot recycle gas through the Hydrogenation
Reactor at the start-up gas steam ejector flow rate to displace any pockets of gas in
the Hydrogenation Reactor which contain high oxygen content. In this case under no
circumstance should the start-up gas steam ejector be stopped.
•
When the temperature front has moved through the Hydrogenation Reactor
catalyst, over a period of approx. two hours, gradually adjust the RGG combustion
air to fuel gas ratio controller to increase excess air flow and an excess of oxygen
to appear in the recycle process gas stream.
•
Closely observe all temperature points across the Hydrogenation Reactor for any
secondary burning of sulphur compounds. If secondary burning is seen,
immediately reset the RGG combustion air to fuel gas ratio controller to reduce
excess combustion air flow to the RGG to reduce the excess oxygen in the recycle
gas and halt the temperature increase in the area of burning within the
Hydrogenation Reactor catalyst bed.
Proceed to cool down the Hydrogenation Reactor as follows:
•
Start reducing the RGG outlet temperature controller set point at 50°C/hr to cool
the Hydrogenation Reactor
•
Slowly adjust the RGG combustion air to fuel gas ratio controller to increase
excess combustion air flow to the RGG
•
When the RGG outlet temperature is 200°C, close LP steam to the RGG fuel gas
line
•
Continue reducing RGG outlet temperature controller set point until ~100°C is
seen in the hydrogenation reactor catalyst bed
•
Stop fuel gas to the RGG burner leaving combustion air flow to cool the
Hydrogenation Reactor to combustion air temperature
•
Close nitrogen to the RGG process gas inlet line
•
Activate the RGG shutdown switch to close all shutdown valves
•
Confirm that the action of the shutdown switch has closed or opened the following
RGG shutdown valves:
•
Nitrogen valve to the RGG combustion air line, open (valve will remain open
for ~15 minutes)
•
Nitrogen valve to the RGG instrument nozzles, open
•
Instrument air to the RGG instrument nozzles, closed
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•
Combustion air valve, closed
•
Fuel gas, two valves closed and vent valve open
•
LP steam, closed
•
Close LP steam to the start-up gas steam ejector
•
Close process gas inlet valve to and outlet valve from the start-up steam gas
ejector
•
Close BSR section start-up vent gas pressure control valve and manual valve
•
Observe the Reactor Effluent Cooler steam generator steam side pressure after
unit shutdown. When pressure has decreased to <1.0 barg on the steam side of the
vessel, open atmospheric vent to prevent a vacuum being formed in the vessel.
The TGTU hydrogenation reactor catalyst regeneration procedure is now complete.
Note: Complete oxidation of a TGTU hydrogenation reactor catalyst and the
elimination of all pyrophoric material in the reactor can sometimes be difficult to fully
carry out in a catalyst oxidation exercise. Care should therefore be taken when
opening a hydrogenation reactor as ignition of any pyrophoric material and pockets of
sulphided catalyst may result.
12.4.8
Hydrogenation Reactor Sulphiding in Series with the SRU
The following text is a guide only to the sulphiding of the hydrogenation reactor
catalyst. The catalyst manufacturer/supplier should advise the catalyst temperature
required at the start of sulphiding operations and the rate of temperature increase
and any temperature hold periods etc. during the operation.
Prior to the start of sulphiding operations, the SRU reaction furnace burner and the
RGG burner will be operating on fuel gas, and SRU tail gases will be routed through the
TGTU BSR section. TGTU process gases will be routed to the Incinerator from the
outlet of the Reactor Effluent Cooler and will be valve isolated to the contact
condenser.
Sulphiding operations will proceed as follows:
•
Confirm that the SRU Reaction Furnace burner is operating on fuel gas at slightly
sub-stoichiometric firing conditions.
•
Confirm that the RGG burner is operating on fuel gas at slightly sub-stoichiometric
firing conditions.
•
Confirm that the Hydrogenation Reactor catalyst bed is fully heated through to a
temperature of 200°C.
•
Using the acid gas sulphiding line from the Regenerator Reflux Drum 9103-V-12 to
the Hydrogenation Reactor inlet line, slowly open manual valve at the
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Hydrogenation Reactor to introduce a small flow of H2S acid gas into the
Hydrogenation Reactor. Aim initially for 1% - 2% vol. of H2S in process gases.
Notes:
1. The intention is to aim initially for a 1% - 2% vol. of H2S in process gases.
2. The reaction of H2S in the Hydrogenation Reactors catalyst is exothermic. For
every 1% vol. of H2S entering the reactor a catalyst temperature increase of
approximately 15°C can be expected.
•
Slowly increase Hydrogenation Reactor inlet temperatures at a rate of
approximately 15°C/hr to 290°C whilst keeping the catalyst bed delta
temperature <25°C.
•
If the exothermic reactions produce a catalyst bed delta temperature >25°C
then reduce the flow of H2S acid gas into the Hydrogenation Reactor.
Note: Under no circumstances should catalyst temperatures be allowed to exceed
425°C as damage to the catalyst and equipment will occur.
•
As soon as acid gases are introduced into the Hydrogenation Reactor inlet line
start sampling the reactor’s inlet and outlet process gas
Note: A hand-held Drager tube type sampling system is suggested where an immediate
read out of H2S concentration in % or ppm can be seen.
•
At one hour intervals, continue sampling the reactor outlet gas until the H2S
concentration in process gases are stable; then increase the RGG outlet
temperature at 25°C/hr to 390°C, or other advised temperature.
Note: Closely observe all temperature points across the Hydrogenation Reactor. If
temperatures approach 400°C reduce and/or temporarily stop acid gas flow to the
reactor. Under no circumstances should the reactor catalyst exceed 425°C as damage
to the catalyst will occur.
•
Hold the reactor catalyst bed temperature at 390°C with the H2S rich acid gas flow
passing through the reactor for a minimum of 4 hours to ensure the catalyst is
fully sulphided.
•
Following the 4 hours hold period, stop the flow of the H2S rich acid gas to the
inlet of the Hydrogenation Reactor.
•
Via the double block valves vent point valve, nitrogen purge the acid gas
sulphiding line to the Hydrogenation Reactor and then back to the SRU acid gas
feed line; then valve and blind isolate the line.
•
Reduce reactor inlet temperature to 240°C
Sulphiding of the hydrogenation reactor is now complete and amine acid feed gas may
be introduced to the SRU.
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12.5
COMBUSTION AIR BLOWER 9102-K-11A LUBE OIL REPLACEMENT
1. The lube oil to be replaced every 8760 hours of blower running
2. Start Combustion Air Blower 9102-K-11B
3. Stop Combustion Air Blower 9102-K-11A
4. Allow sufficient time to cool the lube oil in the tank
5. Drain the spent lube oil and collect in drums
6. Close the drain valve fully after draining the spent oil
7. After draining the spent oil remove the oil drums to the designated place
8. Open the top man way of the lube oil tank
9. Check the internals of the tank
10. If the inside of the tank is dirty it should be manually cleaned
11. After thorough cleaning of the inside of the tank close the top man way
12. Bring the new lube oil drums near to the tank
13. Transfer lube oil to the tank through a hand pump
14. Transfer 2222 litres of oil to the tank
15. If any oil is spilled in the drain pan it has to be collected and disposed of in the
same way as mentioned above.
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SECTION XIII
ANNEXURE
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TITLE: OPERATION AND MAINTENANCE MANUAL
13.1
PFD/P&ID
13.2
HEAT AND MATERIAL BALANCE
13.3
CAUSE AND EFFECT DIAGRAM
13.4
DESIGN BASIS
13.5
MSDS
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SECTION XIV
REFERENCE DOCUMENTS
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TITLE: OPERATION AND MAINTENANCE MANUAL
Description
Document No.
Design Basis Memorandum
2970-6-29-0001
Process Description
2970-6-11-0001
Instrumentation Control Philosophy
2970-6-03-0001
Operating, Control and Safeguarding
Philosophy - Utility Systems
2970-6-03-0002
Equipment List - Process Systems
2970-6-30-0001
Equipment List - Utility Systems
2970-6-30-0002
Line List - Process Systems
2970-6-33-0001
Line List - Utility Systems
2970-6-33-0002
Electrical Design Basis – SRU
2970-2-29-0001
Instrumentation Control Philosophy
2970-4-03-0001
Telecommunication Design Basis
2970-8-29-0001
Commissioning Execution Plan
2970-0-04-0031
Operating Guidelines for Sulphur Recovery
Upgrade (Worley Parsons)
2365-0100
Process Control Narrative & Philosophy
2365-0098
Punch List Procedure
2970-0-05-0051
Process Flow Diagram
2970-6-52-0001 to 10
Utility Flow Diagram
2970-6-53-0001 to 10
Piping and Instrumentation Diagram (Process)
2970-6-50-0002 to 53
Piping and Instrumentation Diagram (Utility)
2970-6-51-0001 to 46
Mass Balance AGEU/SRU/TGTU
2970-6-42-0003
Cause and Effect Chart – ESD – NGL 3
2970-3-55-0001
Cause and Effect Chart – ESD – NGL 1/2
2970-3-55-0002
ESD Cause and Effect Matrix – Modifications of
Existing Drawings – NGL 3
2970-3-55-0003
Instrument Air Compressor & Dryer Package –
Control Narrative
2970-0006-4-03-0001
Instrument Air Compressor & Dryer Package –
IOM Manual
2970-0006-5-26-0002
Instrument Air Compressor & Dryer Package –
P&IDs
2970-0006-6-50-0001-3
Instrument Air Compressor & Dryer Package PFD
2970-0006-6-52-0001
Electro-Chlorination Package - Control
Philosophy
2970-0008-4-03-0001
Electro-Chlorination Package – Alarm and Trip
Schedule
2970-0008-4-67-0001
Electro-Chlorination Package – IOM Manual
2970-0008-5-26-0003
Electro-Chlorination Package – P&IDs
2970-0008-6-50-0001-0001-005
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Description
Document No.
Electro-Chlorination Package - PFD
2970-0008-6-52-0001
Steam Generation Package – BMS Functional
Specification
2970-0025-4-14-0001
Steam Generation Package – BCS Functional
Specification
2970-0025-4-14-0002
Steam Generation Package - Alarm and Trip
Schedule
2970-0025-4-30-0005
Steam Generation Package - IOM Manual
2970-0025-5-26-0002
Steam Generation Package – P&IDs
2970-0025-6-50-0001-001-004
2970-0025-6-50-0002-001/002
2970-0025-6-50-0003
Steam Generation Package - PFD
2970-0025-6-52-0001
Sea Cooling Water Pumps - IOM Manual
2970-0028-5-26-0002
Sea Cooling Water Pumps – P&IDs
2970-0028-6-50-0001
Demineralization Water Treatment Package –
Control Philosophy
2970-0048-4-03-0001
Demineralization Water Treatment Package –
P&IDs
2970-0048-6-50-0001-001-005
Combustion Air Blower 9102-K-11A/B – Control
Philosophy