FCC Pocket Manual 2024.pdf iocl plant unit
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About This Presentation
The IOCL FCC manual serves as a comprehensive guide for the operation, maintenance, and optimization of Fluid Catalytic Cracking units within Indian Oil Corporation Limited (IOCL). It outlines detailed procedures and best practices for managing catalysts, processing feedstocks, and recovering valuab...
Slide Content
Indian Oil Corporation Limited
Mathura Refinery
FLUIDISED CATALYTIC CRACKING UNIT
POCKET MANUAL
(UPDATED: JAN 2024) NEXT UPDATE: JAN 2025
Mathura Refinery
FLUIDISED CATALYTIC CRACKING UNIT
POCKET MANUAL
(UPDATED: JAN 2024) NEXT UPDATE: JAN 2025
This Pocket Manual has been prepared to facilitate the operating personnel for safe,
smooth & efficient operation and emergency handling of “Fluidised Catalytic Cracking
Unit”. This will give useful guidance to the new entrants for better understanding of
the unit operation
Contents of this manual includes process description, operating parameters,
catalyst details, equipment details, utilities/chemical consumption, trips & alarm details
and gives necessary guidelines for normal startup, shut down, and emergency handling
of the unit, based on years of operating experiences. The various operating parameters
are indicative only and may be changed as per requirement.
All the information in this manual is for Production operating personnel only and not to
be divulged to anyone without the permission of the issuing authority.
Place: Mathura refinery
Prepared by Checked by Reviewed by Approved by
Mr. Niteesh Kr Vats
AMPN
Mr. Gyan R Dutta
SPNM
Mr. S. Karthikeyan
CPNM
Mr. S. P. Nigam
DGM PN
3
2
smooth & efficient operation and emergency handling of “Fluidised Catalytic Cracking
Unit”. This will give useful guidance to the new entrants for better understanding of
the unit operation
Contents of this manual includes process description, operating parameters,
catalyst details, equipment details, utilities/chemical consumption, trips & alarm details
and gives necessary guidelines for normal startup, shut down, and emergency handling
of the unit, based on years of operating experiences. The various operating parameters
are indicative only and may be changed as per requirement.
All the information in this manual is for Production operating personnel only and not to
be divulged to anyone without the permission of the issuing authority.
Place: Mathura refinery
Prepared by Checked by Reviewed by Approved by
Mr. Niteesh Kr Vats
AMPN
Mr. Gyan R Dutta
SPNM
Mr. S. Karthikeyan
CPNM
Mr. S. P. Nigam
DGM PN
3
2
INDEX
Sr. No. NAME PAGE NO.
1. INTRODUCTION 5
2. PROCESS DETAILS 7
3. FEED & PRODUCT DETAILS 9
4. PROCESS DESCRIPTION 12
5. MAJOR OPERATING PARAMETERS 21
6. PROCESS VARIABLES 23
7. START UP PROCEDURE 24
8. NORMAL SHUT DOWN PROCEDURE 40
9. EMERGENCY SHUT DOWN PROCEDURE 48
10. CRITICAL EQUIPMENT 71
11. DAILY ROUTINE CHECKS 88
12. STANDING INSTRUCTION 91
13. INTERLOCKS & TRIPS 97
14. EQUIPMENT DETAILS 114
15. CHEMICAL, CATALYST & LUBE OILS 125
16. PERMIT SYSTEM 132
17. COMMUNICATION NETWORK 137
18. OPERATIONAL SAFETY AND MSDS 139
19. QUALITY CONTROL OF PRODUCTS – DEFINITION & SIGNIFICANCE 144
20. FIRE FIGHTING LIST OF MCP’S 149 4
Sr. No. NAME PAGE NO.
1. INTRODUCTION 5
2. PROCESS DETAILS 7
3. FEED & PRODUCT DETAILS 9
4. PROCESS DESCRIPTION 12
5. MAJOR OPERATING PARAMETERS 21
6. PROCESS VARIABLES 23
7. START UP PROCEDURE 24
8. NORMAL SHUT DOWN PROCEDURE 40
9. EMERGENCY SHUT DOWN PROCEDURE 48
10. CRITICAL EQUIPMENT 71
11. DAILY ROUTINE CHECKS 88
12. STANDING INSTRUCTION 91
13. INTERLOCKS & TRIPS 97
14. EQUIPMENT DETAILS 114
15. CHEMICAL, CATALYST & LUBE OILS 125
16. PERMIT SYSTEM 132
17. COMMUNICATION NETWORK 137
18. OPERATIONAL SAFETY AND MSDS 139
19. QUALITY CONTROL OF PRODUCTS – DEFINITION & SIGNIFICANCE 144
20. FIRE FIGHTING LIST OF MCP’S 149 4
1.0 INTRODUCTION
Fluidized catalytic cracking is a process for converting higher molecular weight hydrocarbons into
lighter, more valuable product through contact with a powdered catalyst at appropriate process
conditions
FCC unit at Mathura refinery was originally licensed by M/s UOP, USA and commissioned in 1983
at a capacity of 1.0 MMTPA. FCC unit was subsequently revamped to 1.3 MMTPA in the year 2000
after incorporation of feed injection nozzle from M/s Stone & Webster, USA.
The unit was subsequently revamped in 2014. CBI Lummus Global prepared the Basic Engineering
Package (BEP) for the complete Rx / Rg (R/R) section modifications. M/s Technip KTI was the
Engineering Procurement Construction Management (EPCM) consultant for executing the revamp
project.
Revamp Objectives :-
A) Increase FCCU processing capacity from 1.3 MMTPA to 1.5 MMTPA (180 M
3
/hr to
205M
3
/hr)
B) Shifting Rg operation from “partial mode” to “full burn” mode
C) Maximize yield of LPG & Gasoline and improve Gasoline Octane
D) Minimize yields of dry gas, clarified oil & coke
E) Improve unit run length to minimum of 36 months
F) Reduce particulate emissions to < 100 mg/nm
3
5
Fluidized catalytic cracking is a process for converting higher molecular weight hydrocarbons into
lighter, more valuable product through contact with a powdered catalyst at appropriate process
conditions
FCC unit at Mathura refinery was originally licensed by M/s UOP, USA and commissioned in 1983
at a capacity of 1.0 MMTPA. FCC unit was subsequently revamped to 1.3 MMTPA in the year 2000
after incorporation of feed injection nozzle from M/s Stone & Webster, USA.
The unit was subsequently revamped in 2014. CBI Lummus Global prepared the Basic Engineering
Package (BEP) for the complete Rx / Rg (R/R) section modifications. M/s Technip KTI was the
Engineering Procurement Construction Management (EPCM) consultant for executing the revamp
project.
Revamp Objectives :-
A) Increase FCCU processing capacity from 1.3 MMTPA to 1.5 MMTPA (180 M
3
/hr to
205M
3
/hr)
B) Shifting Rg operation from “partial mode” to “full burn” mode
C) Maximize yield of LPG & Gasoline and improve Gasoline Octane
D) Minimize yields of dry gas, clarified oil & coke
E) Improve unit run length to minimum of 36 months
F) Reduce particulate emissions to < 100 mg/nm
3
5
Following major modifications were carried out during revamp:
A) Direct Coupled Cyclones at riser.
B) Mod Grid spent catalyst stripper
C) New cold wall Regenerated Catalyst Standpipe (RCSP)
D) New cold wall Regenerated Catalyst Valve (RCSV)
E) New hot wall Spent Catalyst Standpipe (SCSP)
F) New hot wall Spent Catalyst Valve (SCSV)
G) New internal spent catalyst Distributor
H) New Third stage Separator (TSS)
I) New Cold-wall orifice chamber
J) Cold wall flue gas duct from Rg to two-port slide valve
K) New Double Disc Slide valve
L) New air grid N) New main air blower
M) Main fractionation Column internals
N) Primary absorber & Sponge absorber internals
O) Stripper internals
P) Existing debutanizer column
Q) New Wet gas compressor
R) New debutanizer column and receiver
S) New Main Column receiver
T) New High pressure receiver
U) New WGC Inter-stage vessel
V) New LPG Treater unit
6
A) Direct Coupled Cyclones at riser.
B) Mod Grid spent catalyst stripper
C) New cold wall Regenerated Catalyst Standpipe (RCSP)
D) New cold wall Regenerated Catalyst Valve (RCSV)
E) New hot wall Spent Catalyst Standpipe (SCSP)
F) New hot wall Spent Catalyst Valve (SCSV)
G) New internal spent catalyst Distributor
H) New Third stage Separator (TSS)
I) New Cold-wall orifice chamber
J) Cold wall flue gas duct from Rg to two-port slide valve
K) New Double Disc Slide valve
L) New air grid N) New main air blower
M) Main fractionation Column internals
N) Primary absorber & Sponge absorber internals
O) Stripper internals
P) Existing debutanizer column
Q) New Wet gas compressor
R) New debutanizer column and receiver
S) New Main Column receiver
T) New High pressure receiver
U) New WGC Inter-stage vessel
V) New LPG Treater unit
6
2.0 PROCESS DETAILS
DESIGN CAPACITY : 1.0 MMTPA
PRESENT CAPACITY : 1.5 MMTPA
DESIGN FEED : HVGO (derived from light Arabian and North
Rumaila crude)
PRESENT FEED : HVGO derived from Nigerian & Bombay High crude
and OHCU Bottom (UCO)
Full Range Naphtha (SRN)/Visbreaker Naphtha( VBN)
DESIGN PACKAGE : M/s Universal Oil Product (Co), USA (UOP)
Revamp by M/s CBI Lummus, USA
DATE OF COMMISSIONING : 28.01.1983
PLANT ON STREAM FACTOR
ON STREAM HOURS PER YEAR: 8280 hours
PLANT TURN AROUND PERIOD: Once in Three years
7
DESIGN CAPACITY : 1.0 MMTPA
PRESENT CAPACITY : 1.5 MMTPA
DESIGN FEED : HVGO (derived from light Arabian and North
Rumaila crude)
PRESENT FEED : HVGO derived from Nigerian & Bombay High crude
and OHCU Bottom (UCO)
Full Range Naphtha (SRN)/Visbreaker Naphtha( VBN)
DESIGN PACKAGE : M/s Universal Oil Product (Co), USA (UOP)
Revamp by M/s CBI Lummus, USA
DATE OF COMMISSIONING : 28.01.1983
PLANT ON STREAM FACTOR
ON STREAM HOURS PER YEAR: 8280 hours
PLANT TURN AROUND PERIOD: Once in Three years
7
3.0 FEED & PRODUCT DETAILS
Feed Specification: m3/hr vol% wt %
Nigerian HVGO 140 68.29 70.20
OHCU Bottom 65 31.71 29.80
Nigerian HVGO OHCU Bottom
Specific Gravity @ 15°C 0.9167
Sulfur wt% 0.2 0.001
Total Nitrogen - 10
Basic Nitrogen 600 -
Conradson Carbon Residue 0.6 0.1
IBP °C - -
5% °C 362 419
10% °C 377 -
50% °C 438 464
90% °C 496 533
FBP °C 540 557
8
Feed Specification: m3/hr vol% wt %
Nigerian HVGO 140 68.29 70.20
OHCU Bottom 65 31.71 29.80
Nigerian HVGO OHCU Bottom
Specific Gravity @ 15°C 0.9167
Sulfur wt% 0.2 0.001
Total Nitrogen - 10
Basic Nitrogen 600 -
Conradson Carbon Residue 0.6 0.1
IBP °C - -
5% °C 362 419
10% °C 377 -
50% °C 438 464
90% °C 496 533
FBP °C 540 557
8
Product Yield :
Component wt%
H
2S 0.07
H
2
0.06
C1 1.30
Total Dry Gas 3.16
C3= 13.61
C3 1.91
Total LPG 35.01
Gasoline 34.82
Heavy Naphtha 10.1
LCO 8.44
CLO 3.81
Coke 4.59
Conversion 87.75%
Above yield is based on design feed with 50 Kg/Day ZSM-5 additive dosing & 3 m3/hr Slurry
recycle to riser.
9
Component wt%
H
2S 0.07
H
2
0.06
C1 1.30
Total Dry Gas 3.16
C3= 13.61
C3 1.91
Total LPG 35.01
Gasoline 34.82
Heavy Naphtha 10.1
LCO 8.44
CLO 3.81
Coke 4.59
Conversion 87.75%
Above yield is based on design feed with 50 Kg/Day ZSM-5 additive dosing & 3 m3/hr Slurry
recycle to riser.
9
TBP Cut point, °C C5-150
Specific Gravity 0.730
Total Sulfur, wppm 101
RONC 94.2
MONC 81.6
TBP Distillation
IBP, °C 5
10%, °C 28
30%, °C 62
50%, °C 91
70%, °C 116
90%, °C 142
EP, °C 150
TBP Cut point, °C 150-220
Specific Gravity 0.843
Total Sulfur, wppm 416
Cetane Index 35.1
TBP Distillation
IBP, °C 150
10%, °C 169
30%, °C 183
50%, °C 195
70%, °C 202
90%, °C 212
EP, °C 220
Product Specification:
Gasoline Heavy Naphtha
10
Specific Gravity 0.730
Total Sulfur, wppm 101
RONC 94.2
MONC 81.6
TBP Distillation
IBP, °C 5
10%, °C 28
30%, °C 62
50%, °C 91
70%, °C 116
90%, °C 142
EP, °C 150
TBP Cut point, °C 150-220
Specific Gravity 0.843
Total Sulfur, wppm 416
Cetane Index 35.1
TBP Distillation
IBP, °C 150
10%, °C 169
30%, °C 183
50%, °C 195
70%, °C 202
90%, °C 212
EP, °C 220
Product Specification:
Gasoline Heavy Naphtha
10
TBP Cut point, °C 220 - 370
Specific Gravity 0.964
Total Sulfur, wt% 0.40
Cetane Index 16.6
TBP Distillation
IBP, °C 220
10%, °C 265
30%, °C 283
50%, °C 295
70%, °C 312
90%, °C 340
EP, °C 370
TBP Cut point, °C 370+
Specific Gravity 1.083
Total Sulfur, wt% 0.63
Catalyst Fines, wt% 0.1
TBP Distillation
IBP, °C 370
10%, °C 434
30%, °C 457
50%, °C 470
70%, °C 479
90%, °C 521
EP, °C 548
Product Specification:
LCO CLO
11
Specific Gravity 0.964
Total Sulfur, wt% 0.40
Cetane Index 16.6
TBP Distillation
IBP, °C 220
10%, °C 265
30%, °C 283
50%, °C 295
70%, °C 312
90%, °C 340
EP, °C 370
TBP Cut point, °C 370+
Specific Gravity 1.083
Total Sulfur, wt% 0.63
Catalyst Fines, wt% 0.1
TBP Distillation
IBP, °C 370
10%, °C 434
30%, °C 457
50%, °C 470
70%, °C 479
90%, °C 521
EP, °C 548
Product Specification:
LCO CLO
11
Feed & Preheat:
4.0 PROCESS DESCRIPTION
Charge Heater
To Reactor
Riser
019-P-02A/B & 102C
019-P-25A/B
1. The raw oil charge system provides feed to the unit, removes heat from the fractionation section,
and heats the charge feed to the desired reactor riser inlet temperature. Raw oil from storage is
pumped to the raw oil charge drum (019-V-4). Feed to surge drum 019-V-4 can also be received directly
from the vacuum distillation unit and hydrocracker unit (UCO) at a temperature of 100°C to 165°C.
2. Fresh Feed is pumped on flow control from the feed surge drum through pump 019-P-2A/B & 102C to
the series of exchangers to recover heat from the hot process streams. The Fresh feed flows in parallel
in exchangers namely (019-E-2 & 019-E-17 LCO CR) and (019-E-15, HNCR). This preheated feed is then
passed through exchanger 19-E-21 where it is heated against Main Column Bottoms & finally enters the
exchanger 019-E-3A/B/C/D/E/F
3. Exchanger 19-E-3A/B & C/D & E/Fare a set of four exchanger shells which are arranged in stacks of
two 12
Raw oil
Surge Drum
019-V-04
LCO PA
HN PA
Slurry PA
019-E-15
019-E-02
Cold feed from
Tankfarm
Slurry PA
019-E-21
019-E-3A/B/C/D
Charge Heater
Burner
019-F-01
Hot feed -
OHCU Bottom
019-E-17
Hot feed - VGO
4.0 PROCESS DESCRIPTION
Charge Heater
To Reactor
Riser
019-P-02A/B & 102C
019-P-25A/B
1. The raw oil charge system provides feed to the unit, removes heat from the fractionation section,
and heats the charge feed to the desired reactor riser inlet temperature. Raw oil from storage is
pumped to the raw oil charge drum (019-V-4). Feed to surge drum 019-V-4 can also be received directly
from the vacuum distillation unit and hydrocracker unit (UCO) at a temperature of 100°C to 165°C.
2. Fresh Feed is pumped on flow control from the feed surge drum through pump 019-P-2A/B & 102C to
the series of exchangers to recover heat from the hot process streams. The Fresh feed flows in parallel
in exchangers namely (019-E-2 & 019-E-17 LCO CR) and (019-E-15, HNCR). This preheated feed is then
passed through exchanger 19-E-21 where it is heated against Main Column Bottoms & finally enters the
exchanger 019-E-3A/B/C/D/E/F
3. Exchanger 19-E-3A/B & C/D & E/Fare a set of four exchanger shells which are arranged in stacks of
two 12
Raw oil
Surge Drum
019-V-04
LCO PA
HN PA
Slurry PA
019-E-15
019-E-02
Cold feed from
Tankfarm
Slurry PA
019-E-21
019-E-3A/B/C/D
Charge Heater
Burner
019-F-01
Hot feed -
OHCU Bottom
019-E-17
Hot feed - VGO
shells each. The two stacks are parallel to each other. After feed preheating, the pressure of the
preheated feed is boosted through Raw Oil Booster pump (019-P-25A/B) up to 16 kg/cm²g.
4. The final raw oil temperature up to 330°C is controlled by passing feed to the charge heater (019-
F1) controlling the firing in the charge heater. The charge heater has two passes and is designed for
dual fuel firing.
The feed preheat temperature is an important process variable. Lower feed preheat temperature
increases cat/oil and conversion, but more coke make to heat balance the unit. If the preheat
temperature is too low (<250
0
C), increasing feed viscosity can result in poor feed distributor
atomization, with a resulting loss in unit selectivity.
Reactor-Regenerator Section :
13
preheated feed is boosted through Raw Oil Booster pump (019-P-25A/B) up to 16 kg/cm²g.
4. The final raw oil temperature up to 330°C is controlled by passing feed to the charge heater (019-
F1) controlling the firing in the charge heater. The charge heater has two passes and is designed for
dual fuel firing.
The feed preheat temperature is an important process variable. Lower feed preheat temperature
increases cat/oil and conversion, but more coke make to heat balance the unit. If the preheat
temperature is too low (<250
0
C), increasing feed viscosity can result in poor feed distributor
atomization, with a resulting loss in unit selectivity.
Reactor-Regenerator Section :
13
Reactor Section :
1. At riser bottom feed comes in contact with hot stream of regenerated catalyst and cracking starts
occurring. Flow of hot catalyst is regulated by slide valve in order to control reactor temperature.
2. Naphtha, HCO/LCO & SLURRY recycles are injected into riser through of spray nozzles at different
elevations.
3. The cracking reactions are endothermic. Coke generated in the cracking reactions gets deposited on
the surface of the catalyst particles and thus the catalyst activity gets reduced.
4. The catalyst gets separated from cracked HC vapor and steam at 2 sets of Direct Coupled Cyclones
(primary & secondary). DCC provides quick separation of the cat & vapor reducing vapor residence
time in the reactor vessel. Hence non selective post riser cracking gets minimized.
5. Spent catalyst is further stripped off residual hydrocarbons at Modular Grid (MG™) spent catalyst
stripper where MP steam is used for stripping. A small amount of sweep steam (Dome steam) is
injected into the reactor vessel dome to keep the area purged of hydrocarbons. These vapors enter
the Primary Cyclone via the proprietary vent opening (orifice).
Regenerator :
1. The spent catalyst from Reactor stripper goes to regenerator under level control. In regenerator air is
being supplied from MAB to burn of the deposited coke and thus the catalyst gets regenerated.
Regeneration.
2. MAB is an axial compressor which uses rotating and stationary blades in series to develop pressure.
The rotating blades add velocity to the gas. Stator vanes convert this velocity back to pressure. The
air flow rate is controlled either by varying compressor shaft speed in a steam turbine or by adjusting
14
1. At riser bottom feed comes in contact with hot stream of regenerated catalyst and cracking starts
occurring. Flow of hot catalyst is regulated by slide valve in order to control reactor temperature.
2. Naphtha, HCO/LCO & SLURRY recycles are injected into riser through of spray nozzles at different
elevations.
3. The cracking reactions are endothermic. Coke generated in the cracking reactions gets deposited on
the surface of the catalyst particles and thus the catalyst activity gets reduced.
4. The catalyst gets separated from cracked HC vapor and steam at 2 sets of Direct Coupled Cyclones
(primary & secondary). DCC provides quick separation of the cat & vapor reducing vapor residence
time in the reactor vessel. Hence non selective post riser cracking gets minimized.
5. Spent catalyst is further stripped off residual hydrocarbons at Modular Grid (MG™) spent catalyst
stripper where MP steam is used for stripping. A small amount of sweep steam (Dome steam) is
injected into the reactor vessel dome to keep the area purged of hydrocarbons. These vapors enter
the Primary Cyclone via the proprietary vent opening (orifice).
Regenerator :
1. The spent catalyst from Reactor stripper goes to regenerator under level control. In regenerator air is
being supplied from MAB to burn of the deposited coke and thus the catalyst gets regenerated.
Regeneration.
2. MAB is an axial compressor which uses rotating and stationary blades in series to develop pressure.
The rotating blades add velocity to the gas. Stator vanes convert this velocity back to pressure. The
air flow rate is controlled either by varying compressor shaft speed in a steam turbine or by adjusting
14
the stator vane position in fixed speed applications. During low air flow condition, a protective anti-
surge controller activates the blow off valve in the discharge line of the compressor.
3. Oxidation of coke is highly exothermic reaction and supplies the necessary heat to Reactor for
reaction in such a way that the unit remains in heat balance always. For better catalyst regeneration,
Regenerator operates in full burn mode with excess O2 in flue gas.
4. Flue gas leaving the dense bed of catalyst passes through three sets of two-stage cyclone separators
supported from the plenum chamber on top of regenerator. From the top of the vessel the flue gas
passes through the orifice chamber via Third Stage Separator (TSS) to the CO Boiler. The cyclones
return the entrained catalyst from the flue gas to the dense bed. Back pressure in the regenerator is
maintained by the orifice chamber and double disc slide valve (DDSV).
5. TSS has a central inlet for the flue gas, which is distributed evenly over 32 numbers of parallel axial
flow cyclones, called swirl tubes. During separation process, separated dust (catalyst fines) drops into
the bottom conical part of the TSS and is removed with the assistance of some gas underflow. The
underflow gas and the dust are separated in the fourth Stage Separator (FSS). The catalyst fines
collected by the FSS is discharged into a Fines Disposal Hopper (FDH) via Fines Collection Hopper
(FCH) for further cooling. Finally collected catalyst fines are unloaded towards truck/ container for
disposal.
6. Flue gas passes through the CO-boiler where sensible heat is used for steam production.
7. Direct Fired Air Heater (DFAH) installed at Rg bottom is used during the normal start-up to heat the
regenerator catalyst inventory. The DFAH outlet temperature is controlled by the fuel gas / NG rate.
8. During MAB tripping, there is a chance of backflow of catalyst from Regenerator. Catalyst backflow is
prevented by 2 nos. quick closing check valves installed in the discharge line of MAB. Provision for dry
15
surge controller activates the blow off valve in the discharge line of the compressor.
3. Oxidation of coke is highly exothermic reaction and supplies the necessary heat to Reactor for
reaction in such a way that the unit remains in heat balance always. For better catalyst regeneration,
Regenerator operates in full burn mode with excess O2 in flue gas.
4. Flue gas leaving the dense bed of catalyst passes through three sets of two-stage cyclone separators
supported from the plenum chamber on top of regenerator. From the top of the vessel the flue gas
passes through the orifice chamber via Third Stage Separator (TSS) to the CO Boiler. The cyclones
return the entrained catalyst from the flue gas to the dense bed. Back pressure in the regenerator is
maintained by the orifice chamber and double disc slide valve (DDSV).
5. TSS has a central inlet for the flue gas, which is distributed evenly over 32 numbers of parallel axial
flow cyclones, called swirl tubes. During separation process, separated dust (catalyst fines) drops into
the bottom conical part of the TSS and is removed with the assistance of some gas underflow. The
underflow gas and the dust are separated in the fourth Stage Separator (FSS). The catalyst fines
collected by the FSS is discharged into a Fines Disposal Hopper (FDH) via Fines Collection Hopper
(FCH) for further cooling. Finally collected catalyst fines are unloaded towards truck/ container for
disposal.
6. Flue gas passes through the CO-boiler where sensible heat is used for steam production.
7. Direct Fired Air Heater (DFAH) installed at Rg bottom is used during the normal start-up to heat the
regenerator catalyst inventory. The DFAH outlet temperature is controlled by the fuel gas / NG rate.
8. During MAB tripping, there is a chance of backflow of catalyst from Regenerator. Catalyst backflow is
prevented by 2 nos. quick closing check valves installed in the discharge line of MAB. Provision for dry
15
air injection is also provided at discharge line.
3. There are 4 slide valves in the catalyst section of the unit. Two of which serve to regulate the flow of
catalyst from (a) reactor to regenerator (SCSV), (b) regenerator to riser (RCSV). The other two slide
valves are in the regenerator flue gas service. Double Disc Slide Valve (DDSV) is in the regenerator flue
gas line which regulates the flow of flue gases into the orifice chamber to control the differential
pressure between reactor and regenerator which indirectly controls the regenerator pressure. The
two port slide valve (TPSV) below orifice chamber enables the flue gases to be diverted to CO Boiler
or bypassed directly to the stack.
Fractionator :
16
3. There are 4 slide valves in the catalyst section of the unit. Two of which serve to regulate the flow of
catalyst from (a) reactor to regenerator (SCSV), (b) regenerator to riser (RCSV). The other two slide
valves are in the regenerator flue gas service. Double Disc Slide Valve (DDSV) is in the regenerator flue
gas line which regulates the flow of flue gases into the orifice chamber to control the differential
pressure between reactor and regenerator which indirectly controls the regenerator pressure. The
two port slide valve (TPSV) below orifice chamber enables the flue gases to be diverted to CO Boiler
or bypassed directly to the stack.
Fractionator :
16
1. The super heated vapors from reactor enters 19C-1 below the bottom most tray and is cooled down
to 360
0
C for Fractionation. Main column bottom (MCB) is circulated back to column through two
sets of exchangers 19E-3 A/B/C/D/E/F & 19E-4/E-21) to de-superheat the vapors coming from
reactor.
2. A stream of MCB is filtered in bucket type filter and one part is circulated back to riser at slurry
recycle nozzle. The other stream is routed to off-sites tanks as CLO after heat exchange with BFW
(19E-5) & cooling water (19E-6).
3. The de-superheated vapor rises up in the fractionation column. The first fraction accumulates in draw
off tray is HCO. The heavy cycle oil circulating reflux transfers its heat to 20C-4 / C-205 bottom
reboiler & to steam generator drum 19E-7. A part of the HCO is recycled back to riser at HCO nozzle.
4. LCO drawn from the accumulator below 19th tray is send back to column as a circulating reflux after
supplying heat to 20C-205 reboiler 20E-221, 19E-17/E-2 (feed preheating) & 20E-7 (Gascon stripper
reboiler). A slip stream of LCO is used as absorbent in 20C-2 also return back to 19C-1 with other LCO
reflux streams. LCO CR is further cooled by 2 nos. air coolers (19EM-125A/B).
5 Heavy naphtha cut is drawn from accumulator below 2nd packing and returns back to column as a
circulating reflux for the heat balance after exchanging heat in 18E-21 with hot water and in 19E-15
with raw oil. Return stream after passing 18E-21 & 19E-15 further can be cooled in air coolers (19E-
16 & 19E-122) on requirement.
6 A part of LCO & HEAVY NAPHTHA draws are stripped in 19C-2 & 19C-3 respectively and routed to
product tanks after exchanging heat in PRU and cooling as diesel component. A part of LCO is routed
back to unit as Flushing oil (FLO).
7 Overhead vapors from the top of column passes through 16 nos. of air coolers and finally cooled
down in 3 nos. of trim coolers 19E-13 A/B/C
17
to 360
0
C for Fractionation. Main column bottom (MCB) is circulated back to column through two
sets of exchangers 19E-3 A/B/C/D/E/F & 19E-4/E-21) to de-superheat the vapors coming from
reactor.
2. A stream of MCB is filtered in bucket type filter and one part is circulated back to riser at slurry
recycle nozzle. The other stream is routed to off-sites tanks as CLO after heat exchange with BFW
(19E-5) & cooling water (19E-6).
3. The de-superheated vapor rises up in the fractionation column. The first fraction accumulates in draw
off tray is HCO. The heavy cycle oil circulating reflux transfers its heat to 20C-4 / C-205 bottom
reboiler & to steam generator drum 19E-7. A part of the HCO is recycled back to riser at HCO nozzle.
4. LCO drawn from the accumulator below 19th tray is send back to column as a circulating reflux after
supplying heat to 20C-205 reboiler 20E-221, 19E-17/E-2 (feed preheating) & 20E-7 (Gascon stripper
reboiler). A slip stream of LCO is used as absorbent in 20C-2 also return back to 19C-1 with other LCO
reflux streams. LCO CR is further cooled by 2 nos. air coolers (19EM-125A/B).
5 Heavy naphtha cut is drawn from accumulator below 2nd packing and returns back to column as a
circulating reflux for the heat balance after exchanging heat in 18E-21 with hot water and in 19E-15
with raw oil. Return stream after passing 18E-21 & 19E-15 further can be cooled in air coolers (19E-
16 & 19E-122) on requirement.
6 A part of LCO & HEAVY NAPHTHA draws are stripped in 19C-2 & 19C-3 respectively and routed to
product tanks after exchanging heat in PRU and cooling as diesel component. A part of LCO is routed
back to unit as Flushing oil (FLO).
7 Overhead vapors from the top of column passes through 16 nos. of air coolers and finally cooled
down in 3 nos. of trim coolers 19E-13 A/B/C
17
Gas Concentration Unit
From Main Column Primary Absorber
Off Gas Cooler
Sponge
Amine Absorber
020-C-06
To OSBL
Receiver
Naphtha
Unstab. Naphtha
020-C-01
Absorber
020-C-02
Sour Gas
KOD
Fuel Gas
Fuel Gas
KOD
Lean Amine
Lean Oil Pump
Lean Oil Cooler
Lean Oil/Rich Oil
Exchanger
Rich Amine
Lean Oil
Debutanizer-I OVHD
Condenser
Debutanizer-I OVHD
Trim Cooler
Debutanizer-I
Receiver
Debutanizer-I
To LPG
reating Unit
LPG
Stripper Charge
Pump
To Storage
Gasoline
1. Some amount of liquid from 19V-105 is pumped back to column 19C-1 as reflux to control the 19C-1
top temperature and balance amount of net overhead liquid is pumped out to 20C-1.
18
Interstage
Aircooler
Interstage
Trim Cooler
WGC Interstage
Receiver
Fat Oil pump
HP Aircooler
From Main Column
Receiver
OVHD Vap
HP steam
Turbine drive
HP Trim
Cooler
Stripper
020-C-03
WGC WGC
WGC Suction
KOD
1
st
STG 2
nd
STG
WGC HP
Receiver
Stripper Charge
Preheater-I/II
30
1
Rich Oil
1
20
1
36
1
20
Reflux Pump Debutanizer-I
OVHD pump
Debutanizer-II OVHD
Condenser
Debutanizer-
II Receiver
T
Debutanizer-II OVHD
Trim Cooler
Debutanizer-II
Reflux Pump Debutanizer-II
OVHD pump
From Main Column Primary Absorber
Off Gas Cooler
Sponge
Amine Absorber
020-C-06
To OSBL
Receiver
Naphtha
Unstab. Naphtha
020-C-01
Absorber
020-C-02
Sour Gas
KOD
Fuel Gas
Fuel Gas
KOD
Lean Amine
Lean Oil Pump
Lean Oil Cooler
Lean Oil/Rich Oil
Exchanger
Rich Amine
Lean Oil
Debutanizer-I OVHD
Condenser
Debutanizer-I OVHD
Trim Cooler
Debutanizer-I
Receiver
Debutanizer-I
To LPG
reating Unit
LPG
Stripper Charge
Pump
To Storage
Gasoline
1. Some amount of liquid from 19V-105 is pumped back to column 19C-1 as reflux to control the 19C-1
top temperature and balance amount of net overhead liquid is pumped out to 20C-1.
18
Interstage
Aircooler
Interstage
Trim Cooler
WGC Interstage
Receiver
Fat Oil pump
HP Aircooler
From Main Column
Receiver
OVHD Vap
HP steam
Turbine drive
HP Trim
Cooler
Stripper
020-C-03
WGC WGC
WGC Suction
KOD
1
st
STG 2
nd
STG
WGC HP
Receiver
Stripper Charge
Preheater-I/II
30
1
Rich Oil
1
20
1
36
1
20
Reflux Pump Debutanizer-I
OVHD pump
Debutanizer-II OVHD
Condenser
Debutanizer-
II Receiver
T
Debutanizer-II OVHD
Trim Cooler
Debutanizer-II
Reflux Pump Debutanizer-II
OVHD pump
2. Uncondensed vapor from 19V-5 sucked and compressed by Wet Gas Compressor (WGC), cooled and
liquid is collected in HP Receiver20V-203.
3. WGC is a two-stage wet gas compressor system driven by HP Steam turbine. A spillback from each
stage of the compressor is provided to prevent the compressor from surging during start-up and unit
upsets. The compressor speed is varied to control the FCC main column overhead receiver pressure.
The hot gases discharged from the first stage of the compressor is mixed with wash water and cooled
in inter stage air cooler 020-EM-218 followed by a trim cooler 020-E-201A/B. The partially condensed
stream is separated into net gas, hydrocarbon condensate and sour water in WGC inter stage
knockout drum 020-V-201. The sour water is pumped to the upstream of 020-E-202.
4. The uncondensed vapours from the WGC inter stage knockout drum is compressed by the second
stage of the compressor and the compressed gas stream is recombined with wash water, inter stage
drum hydrocarbon condensate, primary absorber bottom liquid and stripper overhead gases before
being partially condensed in 020-E-202 (HP Receiver Air Cooler) & 020-E-203 A/B (HP Trim Cooler).
The cooled stream is routed to the HP separator 020-V-203. The uncondensed vapour, high pressure
distillate and sour water are separated out in this drum.
5. The uncondensed vapours from HP receiver are routed to the primary absorber 020-C-01 for C3 - C4
recovery. Some of the debutanizer bottom is recycled to the primary absorber to increase the C3 and
C4 recovery. Gases and H2S then passes through Sponge absorber for the recovery of Gasoline and
finally routed to refinery fuel gas system after H2S absorption in 20C-6
6. Liquid from 20V-203 is fed to stripper 20C-3 where it is heated in 20E-220 (Steam) & 20E-7 (LCO) to
strip out hydrogen sulfide, Methane and Ethane etc., before sending to debutanizers 20C-4/C-205 for
stabilization.
19
liquid is collected in HP Receiver20V-203.
3. WGC is a two-stage wet gas compressor system driven by HP Steam turbine. A spillback from each
stage of the compressor is provided to prevent the compressor from surging during start-up and unit
upsets. The compressor speed is varied to control the FCC main column overhead receiver pressure.
The hot gases discharged from the first stage of the compressor is mixed with wash water and cooled
in inter stage air cooler 020-EM-218 followed by a trim cooler 020-E-201A/B. The partially condensed
stream is separated into net gas, hydrocarbon condensate and sour water in WGC inter stage
knockout drum 020-V-201. The sour water is pumped to the upstream of 020-E-202.
4. The uncondensed vapours from the WGC inter stage knockout drum is compressed by the second
stage of the compressor and the compressed gas stream is recombined with wash water, inter stage
drum hydrocarbon condensate, primary absorber bottom liquid and stripper overhead gases before
being partially condensed in 020-E-202 (HP Receiver Air Cooler) & 020-E-203 A/B (HP Trim Cooler).
The cooled stream is routed to the HP separator 020-V-203. The uncondensed vapour, high pressure
distillate and sour water are separated out in this drum.
5. The uncondensed vapours from HP receiver are routed to the primary absorber 020-C-01 for C3 - C4
recovery. Some of the debutanizer bottom is recycled to the primary absorber to increase the C3 and
C4 recovery. Gases and H2S then passes through Sponge absorber for the recovery of Gasoline and
finally routed to refinery fuel gas system after H2S absorption in 20C-6
6. Liquid from 20V-203 is fed to stripper 20C-3 where it is heated in 20E-220 (Steam) & 20E-7 (LCO) to
strip out hydrogen sulfide, Methane and Ethane etc., before sending to debutanizers 20C-4/C-205 for
stabilization.
19
2. Stripped gases from 20C-3 top combines with WGC discharges, 20C-1 bottom liquid & 20V-201
bottom stream cooled down to recover LPG.
3. 20C-3 bottom material is fed to 20-C-4 & 20C-205 where it is separated into LPG & Gasoline.
4. LPG is routed to LPG Treater Unit (LPGTU) for H2S and mercaptan removal. MDEA is used in 24N-C201
for removal of H2S. Light mercaptan is removed by two stage caustic wash. Residual caustic is treated
by water wash & finally LPG is sent to storage or propylene recovery unit after passing through sand
filter. LPG is also treated with MEA solution for COS removal.
5. Gasoline ex 20C-4/C-205 is routed to SHU of Prime-G unit. After selective hydrogenation, gasoline
stream is separated into LCN, Heart cut & HCN streams in gasoline splitter column 20C-107.
6. Gasoline splitter is reboiled with MP steam in Reboiler (020-E-22). The splitter overhead is partially
condensed & flows to the gasoline Splitter Receiver (020-V-120 M) where the vapor phase and liquid
phase are separated. The vapor phase (excess hydrogen and light ends) is routed to the light ends
booster compression section (in Prime-G) for light ends recovery. The liquid phase from 020-V-120 M
is pumped to column top by reflux pumps (020-P-16 A/B). The LCN stream is withdrawn from tray 5
and then pumped by LCN Product Pumps (020-P-19 A/B). The heart cut (C6 cut) as side-draw (tray
25), is sent to Heart Cut Side Stripper (020-C-08). Heart cut is routed to MSQU by 020-P-15 A/B.
Heart cut stripper is reboiled with LP steam in the Stripper Reboiler (020-E-23). HCN stream is
pumped by HDS Feed Pumps (020-P-18 A/B N) and sent to the HDS section. HCN after desulfurization
is routed to storage along with LCN.
7. 20V3 has been taken in line after revival for SR LPG water washing. The SR LPG from Merox unit 24
after caustic wash in being received in 20v3 for water washing and after that again goes to Merox
unit.
20
bottom stream cooled down to recover LPG.
3. 20C-3 bottom material is fed to 20-C-4 & 20C-205 where it is separated into LPG & Gasoline.
4. LPG is routed to LPG Treater Unit (LPGTU) for H2S and mercaptan removal. MDEA is used in 24N-C201
for removal of H2S. Light mercaptan is removed by two stage caustic wash. Residual caustic is treated
by water wash & finally LPG is sent to storage or propylene recovery unit after passing through sand
filter. LPG is also treated with MEA solution for COS removal.
5. Gasoline ex 20C-4/C-205 is routed to SHU of Prime-G unit. After selective hydrogenation, gasoline
stream is separated into LCN, Heart cut & HCN streams in gasoline splitter column 20C-107.
6. Gasoline splitter is reboiled with MP steam in Reboiler (020-E-22). The splitter overhead is partially
condensed & flows to the gasoline Splitter Receiver (020-V-120 M) where the vapor phase and liquid
phase are separated. The vapor phase (excess hydrogen and light ends) is routed to the light ends
booster compression section (in Prime-G) for light ends recovery. The liquid phase from 020-V-120 M
is pumped to column top by reflux pumps (020-P-16 A/B). The LCN stream is withdrawn from tray 5
and then pumped by LCN Product Pumps (020-P-19 A/B). The heart cut (C6 cut) as side-draw (tray
25), is sent to Heart Cut Side Stripper (020-C-08). Heart cut is routed to MSQU by 020-P-15 A/B.
Heart cut stripper is reboiled with LP steam in the Stripper Reboiler (020-E-23). HCN stream is
pumped by HDS Feed Pumps (020-P-18 A/B N) and sent to the HDS section. HCN after desulfurization
is routed to storage along with LCN.
7. 20V3 has been taken in line after revival for SR LPG water washing. The SR LPG from Merox unit 24
after caustic wash in being received in 20v3 for water washing and after that again goes to Merox
unit.
20
5.0 MAJOR OPERATING PARAMETERS
21
Rg Superficial Velocity 0.936 M/Sec
Rx Cyclone Inlet / outlet
Velocity 1
st
Stage
17.6 / 23.7 M/Sec
Rx Cyclone Inlet / outlet
Velocity 2
nd
stage
24.0 / 37.4 M/Sec
Rg Cyclone Inlet / Outlet
Velocity 1
st
Stage
19.9 / 22.4 M/Sec
Rg Cyclone Inlet / Outlet
Velocity 2
nd
Stage
22.5 / 33.1 M/Sec
Catalyst Circulation Rate 22.8 MT / min
Catalyst / Oil Ratio 7.48 wt/wt
Catalyst Addition Rate 0.8 MT/Day
ZSM-5 Addition Rate 40 Kg/Day
COP Addition Rate 1-2 Kg/Day
Carbon on Rg Cat. (CRC) 0.02 wt%
Carbon on Sp Cat. (CSC) 0.63 wt%
Catalyst Activity, MAT 69.0
Riser Outlet Temp. 547
0
C
Regenerator dense bed 700
0
C
Dilute Phase 707
0
C
Air to Regenerator 112700 Kg/hr
Stripping Steam 3000 Kg/Hr
Dome Steam 500 Kg/Hr
Fresh Feed 205 M
3
Hr
Slurry recycle 3 M
3
/Hr
SRN/VBN/LCO/HCO
recycle
As per Requirement
Feed/Slurry/HCO steam 5150 /278 /400 Kg/Hr
Y steam / Riser steam 135 / 220 Kg/Hr
19F-1 coil out let 330
0
C
Reactor Pressure 2.81 Kg/cm
2
Regenerator Pressure 3.23 Kg/cm
2
RCSV / SCSV delta P 0.4/0.304 Kg/cm
2
21
Rg Superficial Velocity 0.936 M/Sec
Rx Cyclone Inlet / outlet
Velocity 1
st
Stage
17.6 / 23.7 M/Sec
Rx Cyclone Inlet / outlet
Velocity 2
nd
stage
24.0 / 37.4 M/Sec
Rg Cyclone Inlet / Outlet
Velocity 1
st
Stage
19.9 / 22.4 M/Sec
Rg Cyclone Inlet / Outlet
Velocity 2
nd
Stage
22.5 / 33.1 M/Sec
Catalyst Circulation Rate 22.8 MT / min
Catalyst / Oil Ratio 7.48 wt/wt
Catalyst Addition Rate 0.8 MT/Day
ZSM-5 Addition Rate 40 Kg/Day
COP Addition Rate 1-2 Kg/Day
Carbon on Rg Cat. (CRC) 0.02 wt%
Carbon on Sp Cat. (CSC) 0.63 wt%
Catalyst Activity, MAT 69.0
Riser Outlet Temp. 547
0
C
Regenerator dense bed 700
0
C
Dilute Phase 707
0
C
Air to Regenerator 112700 Kg/hr
Stripping Steam 3000 Kg/Hr
Dome Steam 500 Kg/Hr
Fresh Feed 205 M
3
Hr
Slurry recycle 3 M
3
/Hr
SRN/VBN/LCO/HCO
recycle
As per Requirement
Feed/Slurry/HCO steam 5150 /278 /400 Kg/Hr
Y steam / Riser steam 135 / 220 Kg/Hr
19F-1 coil out let 330
0
C
Reactor Pressure 2.81 Kg/cm
2
Regenerator Pressure 3.23 Kg/cm
2
RCSV / SCSV delta P 0.4/0.304 Kg/cm
2
Fractionator operating parameters
19C-1 Top/Reflux return
0
C 119 / 40
Hy Naphtha Draw/Return
0
C 166 / 123.3
LCO Draw/Return
0
C 238.6 / 159.4
HCO Draw/Return
0
C 292.1 / 241.4
MCB Draw/Return
0
C 361.6 / 260.3
19C-1 36
th
tray temp
0
C 390
19C-1 O/H Ex Air cooler
0
C 58.3
19C-1 O/H Ex Trim cooler
0
C 40
19V-105 Pressure Kg/cm
2
1.7
WGC Suction flow Kg/hr 79693
Top Reflux flow m
3
/hr 90.7
HN CR Flow m
3
/hr 197.9
LCO CR Flow m
3
/hr 159.2
HCO CR Flow m
3
/hr 342.2
MCB CR Flow m
3
/hr 337.1
22
19C-1 Top/Reflux return
0
C 119 / 40
Hy Naphtha Draw/Return
0
C 166 / 123.3
LCO Draw/Return
0
C 238.6 / 159.4
HCO Draw/Return
0
C 292.1 / 241.4
MCB Draw/Return
0
C 361.6 / 260.3
19C-1 36
th
tray temp
0
C 390
19C-1 O/H Ex Air cooler
0
C 58.3
19C-1 O/H Ex Trim cooler
0
C 40
19V-105 Pressure Kg/cm
2
1.7
WGC Suction flow Kg/hr 79693
Top Reflux flow m
3
/hr 90.7
HN CR Flow m
3
/hr 197.9
LCO CR Flow m
3
/hr 159.2
HCO CR Flow m
3
/hr 342.2
MCB CR Flow m
3
/hr 337.1
22
6.0 PROCESS VARIABLES
Variable changed
Conversion
Kg/hr
Carbon
CRC
%
Catalyst
Circulation
Rate
Cat
Oil
ratio
%
O2 in
Flue
Gas
Regenerator
Temperature
Variable Constant
Feed rate
D | | | D D D Reactor temp & hold up
| D D D | | | Pre-Heat air rate
Reactor hold up
| | | D D D | Reactor temp & feed rate
D D D | | | D Air rate & Pre-Heat
Reactor temp
| | | | | D D Reactor holdup & feed rate
D D D D D | | Air rate & Pre-Heat
Feed Pre-Heat
D D D D D | | Reactor temp & holdup
| | | | | D D Feed rate & Air rate
O2 in flue gas
| D D D D | | Reactor temp & holdup
D | | | D D D Feed rate & Pre-Heat
23
Variable changed
Conversion
Kg/hr
Carbon
CRC
%
Catalyst
Circulation
Rate
Cat
Oil
ratio
%
O2 in
Flue
Gas
Regenerator
Temperature
Variable Constant
Feed rate
D | | | D D D Reactor temp & hold up
| D D D | | | Pre-Heat air rate
Reactor hold up
| | | D D D | Reactor temp & feed rate
D D D | | | D Air rate & Pre-Heat
Reactor temp
| | | | | D D Reactor holdup & feed rate
D D D D D | | Air rate & Pre-Heat
Feed Pre-Heat
D D D D D | | Reactor temp & holdup
| | | | | D D Feed rate & Air rate
O2 in flue gas
| D D D D | | Reactor temp & holdup
D | | | D D D Feed rate & Pre-Heat
23
7.0 START UP PROCEDURE
STAGE – 1 REACTOR TO COLUMN VAPOUR LINE BLIND IS IN POSITION:
FRATIONATOR :
1. Starts steaming of 19C-1, 19C-2, 19C-3, 19V-105, 19V-4, feed circuit Furnace coils, reflux lines & other
connected circuits.
2. Keep CW to O/H coolers isolated and high vent & drain valves open to drain out water in tubes.
3. During steaming drain condensate from all column, vessels & pump drain.
4. Continue steaming for 3 to 4 hours to make the system air free.
5. Reduce steam just keep snuffing steam coming out from all the vents.
6. Close all the vents and charge FG to 19C-2.
7. Isolate steam. Ensure that always system pressure is > than atmospheric pressure.
8. Drain condensate from all low point drains at frequent intervals.
9. Don’t leave any drain open unattended after gas backing up.
10.Fix cap end blind to all the vent points.
11. Start cold circulation. Receive flushing oil in 19V-4, Run 19P-2 A/B/C and charge oil in feed circuit
19F-1 coils 19C-1 bottom & other draw off trays through start up manifold.
12. When level in 19C-1 is visible(keep higher level initially, as exchanger and other process lines are
empty) start 19P-3 and establish circulation in MCB circuit.
13. Backup steam in 19E-4 to raise the column bottom temperature.
14. Displace FLO with HVGO after MCB temperature reaches 120
0
C . Establish HVGO circulation in feed
& slurry circuits through control valves 19FRC-138/147/5102/149 & quench lines.
15. Ensure some continuous flow to run down through 19FRC-126 and make up to column to maintain
column level.
16. Release some gas to flare to 19PIC-202, maintain column pressure 0.8Kg/cm2g. This will ensure that
any air that might still remain in the system is purged out to the flare.
24
STAGE – 1 REACTOR TO COLUMN VAPOUR LINE BLIND IS IN POSITION:
FRATIONATOR :
1. Starts steaming of 19C-1, 19C-2, 19C-3, 19V-105, 19V-4, feed circuit Furnace coils, reflux lines & other
connected circuits.
2. Keep CW to O/H coolers isolated and high vent & drain valves open to drain out water in tubes.
3. During steaming drain condensate from all column, vessels & pump drain.
4. Continue steaming for 3 to 4 hours to make the system air free.
5. Reduce steam just keep snuffing steam coming out from all the vents.
6. Close all the vents and charge FG to 19C-2.
7. Isolate steam. Ensure that always system pressure is > than atmospheric pressure.
8. Drain condensate from all low point drains at frequent intervals.
9. Don’t leave any drain open unattended after gas backing up.
10.Fix cap end blind to all the vent points.
11. Start cold circulation. Receive flushing oil in 19V-4, Run 19P-2 A/B/C and charge oil in feed circuit
19F-1 coils 19C-1 bottom & other draw off trays through start up manifold.
12. When level in 19C-1 is visible(keep higher level initially, as exchanger and other process lines are
empty) start 19P-3 and establish circulation in MCB circuit.
13. Backup steam in 19E-4 to raise the column bottom temperature.
14. Displace FLO with HVGO after MCB temperature reaches 120
0
C . Establish HVGO circulation in feed
& slurry circuits through control valves 19FRC-138/147/5102/149 & quench lines.
15. Ensure some continuous flow to run down through 19FRC-126 and make up to column to maintain
column level.
16. Release some gas to flare to 19PIC-202, maintain column pressure 0.8Kg/cm2g. This will ensure that
any air that might still remain in the system is purged out to the flare.
24
REACTOR / REGERATOR
1. Charge steam to reactor riser through emergency control valve(Drain condensate before charging
steam).
2. Keep the following valves close
Feed to riser B/V blind at u/s.
Riser feed nozzle B/Vs.
HCO injection nozzles B/Vs.
Slurry injection nozzles B/Vs.
Naphtha injection nozzles B/V.
3. Charge atomizing steam to feed nozzles, HCO nozzles, Slurry nozzles, Naphtha Nozzles, Y steam
(Drain condensate before charging steam). Charge stripping & dome steam to reactor stripper. Open
stripper bottom drain valve for condensate draining.
4. Open Rx top vent silencer for Rx vessel purging.
5. Keep reactor warm up line B/Vs Full open.
6. Start DDSV hydraulic oil pump. Keep hydraulic oil to LRC & TRC cylinders isolated.
7. Starts MAB (19K-1) and starts air through regenerator. Keep air flow around 40000 Nm3/hr.
8. Go for Rg Man way flange pressure testing
9. Light up DFAH (19F-2), raise air temperature @ 40-50 deg C/hr. Hot bolting at 350 deg C.
10.Again raise temp @ 50degC/hr up to 600 deg C. Hot bolting at 600 deg C. Ensure DFAH air
temperature should not exceed more than 650 deg C.
11. Cooling up to 150 deg C @ 100 deg C/hr. Heating/cooling to be changed as per refractory drying
schedule if repairs are done.
12. Keep reactor pressure on just slightly positive (0.05-0.1 Kg/cm2) than regenerator. (19DPIC0404-1
indication - ve).
25
1. Charge steam to reactor riser through emergency control valve(Drain condensate before charging
steam).
2. Keep the following valves close
Feed to riser B/V blind at u/s.
Riser feed nozzle B/Vs.
HCO injection nozzles B/Vs.
Slurry injection nozzles B/Vs.
Naphtha injection nozzles B/V.
3. Charge atomizing steam to feed nozzles, HCO nozzles, Slurry nozzles, Naphtha Nozzles, Y steam
(Drain condensate before charging steam). Charge stripping & dome steam to reactor stripper. Open
stripper bottom drain valve for condensate draining.
4. Open Rx top vent silencer for Rx vessel purging.
5. Keep reactor warm up line B/Vs Full open.
6. Start DDSV hydraulic oil pump. Keep hydraulic oil to LRC & TRC cylinders isolated.
7. Starts MAB (19K-1) and starts air through regenerator. Keep air flow around 40000 Nm3/hr.
8. Go for Rg Man way flange pressure testing
9. Light up DFAH (19F-2), raise air temperature @ 40-50 deg C/hr. Hot bolting at 350 deg C.
10.Again raise temp @ 50degC/hr up to 600 deg C. Hot bolting at 600 deg C. Ensure DFAH air
temperature should not exceed more than 650 deg C.
11. Cooling up to 150 deg C @ 100 deg C/hr. Heating/cooling to be changed as per refractory drying
schedule if repairs are done.
12. Keep reactor pressure on just slightly positive (0.05-0.1 Kg/cm2) than regenerator. (19DPIC0404-1
indication - ve).
25
GAS CONCENTRATION UNIT
1. Do the steaming of system to purge out air.
2. Keep gas concentration unit isolated from Fractionator & run down. Close following C/Vs and their
Block valves.
20 LIC-0065
19 FIC-0213
20 FIC-0085A&B
20 PIC-0063
20 FIC0803N
20LIC0044
3. After steaming proceed for flare back up from 20PIC-0063 U/S flare line. Then take FG backup
through 20PIC-0063.
4. Before the flare / Gas backup isolate vents & drains, keep watch on 20 C-2 & 20C-4 pressure to avoid
vacuum condition.
STAGE-2: REACTOR TO COLUMN VAPOUR LINE BLIND REMOVAL :
1. Cut off firing in 19F-2.
2. Isolates steam to structure B/Vs at pipe rack (3 nos.). Riser steam to continue.
3. Reduce MAB rpm gradually & stop the blower (normal S/D from Woodward panel). Do not stop
blower by ESD.
4. Stop 19P3 after pump loosing the suction. Isolate FLO to 19P103 seal, LT, LG, and flow transmitters.
Wait for around 15-20 minutes and for any increase in level of column. In case of level increases due
to draining from inside the column, empty out it again. Isolate B/Vs to 19E-21 & 19E-D at 19P-3
discharge manifold.
5. TRC & LRC slide valves should be tightly shut on hand wheel.
6. Check isolation of 20LCV-44, 20LC-65
26
1. Do the steaming of system to purge out air.
2. Keep gas concentration unit isolated from Fractionator & run down. Close following C/Vs and their
Block valves.
20 LIC-0065
19 FIC-0213
20 FIC-0085A&B
20 PIC-0063
20 FIC0803N
20LIC0044
3. After steaming proceed for flare back up from 20PIC-0063 U/S flare line. Then take FG backup
through 20PIC-0063.
4. Before the flare / Gas backup isolate vents & drains, keep watch on 20 C-2 & 20C-4 pressure to avoid
vacuum condition.
STAGE-2: REACTOR TO COLUMN VAPOUR LINE BLIND REMOVAL :
1. Cut off firing in 19F-2.
2. Isolates steam to structure B/Vs at pipe rack (3 nos.). Riser steam to continue.
3. Reduce MAB rpm gradually & stop the blower (normal S/D from Woodward panel). Do not stop
blower by ESD.
4. Stop 19P3 after pump loosing the suction. Isolate FLO to 19P103 seal, LT, LG, and flow transmitters.
Wait for around 15-20 minutes and for any increase in level of column. In case of level increases due
to draining from inside the column, empty out it again. Isolate B/Vs to 19E-21 & 19E-D at 19P-3
discharge manifold.
5. TRC & LRC slide valves should be tightly shut on hand wheel.
6. Check isolation of 20LCV-44, 20LC-65
26
7. Stop gas back up to 19C-2.
8. Open 19PIC-202 fully to de-pressurize main column 19C-1 to flare. Keep open 19PIC-202 & ensure
pressure is zero. (Note 19PIC202 valve is not to be CLOSED as NRV is provided to prevent backflow of
other unit flare release to FCCU flare header.
9. Charge steam into the main Fractionator side strippers and establish steam purge in 19C-1 bottom
using the try lines.
10. Reduce riser steam to minimum. Just before opening flange isolate riser steam. Close steam to 19C-2
& 19C-3 C/Vs. Slight amount of steam should go through column bottom try line.
11. Inform Fire and safety to be present with fire tender before the execution of the job
12. Check wind direction and accordingly place the working people for job. Air hose must be on.
13.Give clearance to M/M for blind removal.
14.A soon as M/M inserts spacer ring and puts back few bolts, reintroduce steam to avoid air ingress.
15. Close warm up line B/Vs and insert blind.
16. After vapor line deblind & warm up line blind, increase steam to riser. Charge other steams at
following rate : Emergency steam: 5.5-6 t/hr, Feed nozzle steam: 4.5 t/hr, HCO nozzle steam:350
kg/hr, Slurry nozzle steam: 320kg /hr, Pre stripping steam: 100Kg/hr, Stripping steam :1.5 t/hr
17. Line up 19PIC-0081 C/V for R-R section instrument blow back & stand pipe blast . Always ensure
condensate is drained.
18. Open gas back up to 19C-2. Establish circulation by running 19 P-103.
11.Restart blower and 19F-2.
12. Maintain reactor pressure slightly higher than regenerator pressure (0.05 -0.1 Kg/cm2)
27
8. Open 19PIC-202 fully to de-pressurize main column 19C-1 to flare. Keep open 19PIC-202 & ensure
pressure is zero. (Note 19PIC202 valve is not to be CLOSED as NRV is provided to prevent backflow of
other unit flare release to FCCU flare header.
9. Charge steam into the main Fractionator side strippers and establish steam purge in 19C-1 bottom
using the try lines.
10. Reduce riser steam to minimum. Just before opening flange isolate riser steam. Close steam to 19C-2
& 19C-3 C/Vs. Slight amount of steam should go through column bottom try line.
11. Inform Fire and safety to be present with fire tender before the execution of the job
12. Check wind direction and accordingly place the working people for job. Air hose must be on.
13.Give clearance to M/M for blind removal.
14.A soon as M/M inserts spacer ring and puts back few bolts, reintroduce steam to avoid air ingress.
15. Close warm up line B/Vs and insert blind.
16. After vapor line deblind & warm up line blind, increase steam to riser. Charge other steams at
following rate : Emergency steam: 5.5-6 t/hr, Feed nozzle steam: 4.5 t/hr, HCO nozzle steam:350
kg/hr, Slurry nozzle steam: 320kg /hr, Pre stripping steam: 100Kg/hr, Stripping steam :1.5 t/hr
17. Line up 19PIC-0081 C/V for R-R section instrument blow back & stand pipe blast . Always ensure
condensate is drained.
18. Open gas back up to 19C-2. Establish circulation by running 19 P-103.
11.Restart blower and 19F-2.
12. Maintain reactor pressure slightly higher than regenerator pressure (0.05 -0.1 Kg/cm2)
27
STAGE-3: REACTOR FLOATING WITH COLUMN :
1. Keep HC circulation on and raise 19C-1 bottom temperature up to 160-170 deg C by backing steam in
19E-4.
2. Raise 19F-2 temperature to get regenerator temperature 450 deg C.
3. Starts Equilibrium catalyst loading in regenerator.
4. Adjust air flow 25000-30000 NM3/hr and regenerator pressure 0.6 – 0.9 Kg/cm2 to avoid catalyst
carry over from Regenerator cyclone. Check FDH level.
5. Adjust column pressure (>1.2 Kg/cm
2
) to keep reactor pressure higher than regenerator pressure.
6. Change purges from Nitrogen to steam.
7. When catalyst level in regenerator is achieved up to 30% and regenerator temp is 425 deg C inject
torch oil and raise Rg temp 625-650
0
C, reduce 19F-2 firing.
8. Load required inventory of E-CAT (Rg level 90-95%).
9. Start hydraulic oil pump circulation to TRC & LRC slide valves. Put both the slide valves on cylinder
operation. Start Cat. Circulation. Adjust cat. Circulation. Adjust regenerator pressure to get safe
operating conditions/pressure balance as,
Delta P across TRC +ive (>.17 Kg/cm2)
Delta P across LRC +ive (>.17 Kg/cm2)
11. Warm up 20 K-201 and roll the turbine and keep running at governor min RPM. Enusre 19V-105
pressure is >1.2 Kg/cm
2
to avoid WGC tripping.
12. Raise reactor temperature up to 525
0
C.
13. Put 19 TIC-0501,19 LIC-0061, 19 DPIC-0060 on auto mode & observe their action /performance.
14. Light up pilot burners in 19F-1.
15. Remove water from 19 P-9, 19P-10 suction ,and drain condensate from all Fractionator rundown
and reflux pumps.
28
1. Keep HC circulation on and raise 19C-1 bottom temperature up to 160-170 deg C by backing steam in
19E-4.
2. Raise 19F-2 temperature to get regenerator temperature 450 deg C.
3. Starts Equilibrium catalyst loading in regenerator.
4. Adjust air flow 25000-30000 NM3/hr and regenerator pressure 0.6 – 0.9 Kg/cm2 to avoid catalyst
carry over from Regenerator cyclone. Check FDH level.
5. Adjust column pressure (>1.2 Kg/cm
2
) to keep reactor pressure higher than regenerator pressure.
6. Change purges from Nitrogen to steam.
7. When catalyst level in regenerator is achieved up to 30% and regenerator temp is 425 deg C inject
torch oil and raise Rg temp 625-650
0
C, reduce 19F-2 firing.
8. Load required inventory of E-CAT (Rg level 90-95%).
9. Start hydraulic oil pump circulation to TRC & LRC slide valves. Put both the slide valves on cylinder
operation. Start Cat. Circulation. Adjust cat. Circulation. Adjust regenerator pressure to get safe
operating conditions/pressure balance as,
Delta P across TRC +ive (>.17 Kg/cm2)
Delta P across LRC +ive (>.17 Kg/cm2)
11. Warm up 20 K-201 and roll the turbine and keep running at governor min RPM. Enusre 19V-105
pressure is >1.2 Kg/cm
2
to avoid WGC tripping.
12. Raise reactor temperature up to 525
0
C.
13. Put 19 TIC-0501,19 LIC-0061, 19 DPIC-0060 on auto mode & observe their action /performance.
14. Light up pilot burners in 19F-1.
15. Remove water from 19 P-9, 19P-10 suction ,and drain condensate from all Fractionator rundown
and reflux pumps.
28
16. Check the final conditions for feed cut.
Rx temp - 525
0
C
Regen temp - 625-650
0
C
19 DPIC-0060 - >0.25 - 0.4 Kg/cm2
19TIC-0501 & LIC-0061 - Are on auto mode.
20K-201 - is running with spill back open at governor min. speed.
Gas concentration Pr. - 3.5 Kg/cm2 (Equal to FG Pr.)
Feed (HVGO) - Off site feed pump is in running condition.
Blind - Feed to riser blind in removed.
Riser steam - Flow 6000 Kg/hr.
Atomizing steam to feed - 4500 Kg/hr.
nozzle
Stripping steam - 3000 Kg/hr
O/H air coolers - are in service
C/W & steam flow/pr. - are quite normal.
17. Take 2 nos. opposite feed nozzles in line and proceed for feed cut in.
18. After feed cut in raise feed in steps 5-10 M3/hr, keep watch on slide valves differential.
19. Raise air to regenerator to burn the coke on Catalyst.
20. Gradually reduce torch oil/ DFAH firing to regenerator.
21. Stabilize 19C-1, watch 19V-5 water level. Check sour water for oil carry over.
22. Starts routing liquid feed to 20C-1.
23. Load 20K-1 stop flaring fully and stabilize Gas Con. Section.
29
Rx temp - 525
0
C
Regen temp - 625-650
0
C
19 DPIC-0060 - >0.25 - 0.4 Kg/cm2
19TIC-0501 & LIC-0061 - Are on auto mode.
20K-201 - is running with spill back open at governor min. speed.
Gas concentration Pr. - 3.5 Kg/cm2 (Equal to FG Pr.)
Feed (HVGO) - Off site feed pump is in running condition.
Blind - Feed to riser blind in removed.
Riser steam - Flow 6000 Kg/hr.
Atomizing steam to feed - 4500 Kg/hr.
nozzle
Stripping steam - 3000 Kg/hr
O/H air coolers - are in service
C/W & steam flow/pr. - are quite normal.
17. Take 2 nos. opposite feed nozzles in line and proceed for feed cut in.
18. After feed cut in raise feed in steps 5-10 M3/hr, keep watch on slide valves differential.
19. Raise air to regenerator to burn the coke on Catalyst.
20. Gradually reduce torch oil/ DFAH firing to regenerator.
21. Stabilize 19C-1, watch 19V-5 water level. Check sour water for oil carry over.
22. Starts routing liquid feed to 20C-1.
23. Load 20K-1 stop flaring fully and stabilize Gas Con. Section.
29
CHECK LIST FOR FCC START UP (AFTER M&I SHUTDOWN)
GENERAL:
• ALL THE FIRE FIGHTING EQUIPMENTS ARE PLACED AND FIRE FIGHTING EQUIPMENTS ARE IN
SERVICE.
• ALL RELIEF VALVES ARE LINED UP TO THEIR RESPECTIVE SYSTEMS.
• ENSURE THAT BLINDS INSTALLED FOR UNIT SHUT DOWN HAVE BEEN REMOVED (EXCLUDING
BATTERY LIMIT BLINDS AND STATUS RECORDED IN THE BLIND REGISTER).
• INFORM TPS FOR STEAM, POWER, AND BOILER FEED WATER CONSUMPTION. INFORM WATER
BLOCK FOR COOLING WATER CONSUMPTION.
• INFORM OFFSITE FOR LINING SLOP OIL TANKS.
• ENSURE FUEL GAS HEADER PRESSURE AND ISBL, OSBL FLARE COMMISSIONED.
• ALL UTILITY LINES LIKE SERVICE WATER, INSTRUMENT AIR, SERVICE AIR, NITROGEN, LP STEAM
(EXCEPT FUEL GAS) ETC ARE CHARGED.
• ALL ROTARY EQUIPMENTS LIKE PUMPS, COMPRESSORS, CENTRIFUGES ARE ENERGIZED AND
READY FOR START UP.
• OWS SYSTEM IS LINED UP TO THE REFINERY NETWORK AND UNIT CBD SYSTEM IS READY.
• START UP CLEARANCE FORMAT HAS BEEN SIGNED BY ALL THE CONCERNED DEPARTMENTS.
• CHECK PROCESS INTERLOCK OF MAB, WGC, COB, FCC
• CHECK THE SPRINKLERS OF HOT SERVICE PUMPS AND OTHER SERVICES BEFORE START UP.
30
GENERAL:
• ALL THE FIRE FIGHTING EQUIPMENTS ARE PLACED AND FIRE FIGHTING EQUIPMENTS ARE IN
SERVICE.
• ALL RELIEF VALVES ARE LINED UP TO THEIR RESPECTIVE SYSTEMS.
• ENSURE THAT BLINDS INSTALLED FOR UNIT SHUT DOWN HAVE BEEN REMOVED (EXCLUDING
BATTERY LIMIT BLINDS AND STATUS RECORDED IN THE BLIND REGISTER).
• INFORM TPS FOR STEAM, POWER, AND BOILER FEED WATER CONSUMPTION. INFORM WATER
BLOCK FOR COOLING WATER CONSUMPTION.
• INFORM OFFSITE FOR LINING SLOP OIL TANKS.
• ENSURE FUEL GAS HEADER PRESSURE AND ISBL, OSBL FLARE COMMISSIONED.
• ALL UTILITY LINES LIKE SERVICE WATER, INSTRUMENT AIR, SERVICE AIR, NITROGEN, LP STEAM
(EXCEPT FUEL GAS) ETC ARE CHARGED.
• ALL ROTARY EQUIPMENTS LIKE PUMPS, COMPRESSORS, CENTRIFUGES ARE ENERGIZED AND
READY FOR START UP.
• OWS SYSTEM IS LINED UP TO THE REFINERY NETWORK AND UNIT CBD SYSTEM IS READY.
• START UP CLEARANCE FORMAT HAS BEEN SIGNED BY ALL THE CONCERNED DEPARTMENTS.
• CHECK PROCESS INTERLOCK OF MAB, WGC, COB, FCC
• CHECK THE SPRINKLERS OF HOT SERVICE PUMPS AND OTHER SERVICES BEFORE START UP.
30
CHECK LIST FOR FCC START UP - REACTOR – REGENERATOR
SL.NO STEPS START
TIME
COMP
TIME
SIGN REMARKS
REACTOR- REGENERATOR
1 FOLLOWING LINES SHOULD BE ISOLATED WITH BLINDS:
- REACTOR VAPOUR LINE
- FEED TO RISER
- SLURRY TO RISER
- HCO TO RISER
- NAPHTHA LINE TO RISER
- FG TO RISER (ALWAYS KEPT BLINDED)
2 FOLLOWING LINES SHOULD BE ISOLATED BY BLINDS:
- FUEL GAS TO 19F-2
- TORCH OIL TO REGENERATOR (NEAR CONTROL
VALVE)
3 LINE UP THE PURGE CONNECTION FOR INSTRUMENT
TAPS, KEEPING LAST ISOLATION VALVE CLOSED
4 LINE WYE STEAM & EMERGENCY STEAM KEEPING
19FIC466 CLOSED
5 LINE UP STRIPPING STEAM AND PRE STRIPPING STEAM
TO REACTOR KEEPING 19 FIC0501/ 19FIC0502 CLOSED.
6 LINE UP EMERGENCY PLANT AIR TO BLOWER
DISCHARGE.
7 LINE UP THE AERATION CONNECTION FOR STANDS
PIPES AND THERE EXPANSION JOINTS.
8 LINE UP FLUE GAS LINE TO STACK BYPASSING CO
BOILER.
31
SL.NO STEPS START
TIME
COMP
TIME
SIGN REMARKS
REACTOR- REGENERATOR
1 FOLLOWING LINES SHOULD BE ISOLATED WITH BLINDS:
- REACTOR VAPOUR LINE
- FEED TO RISER
- SLURRY TO RISER
- HCO TO RISER
- NAPHTHA LINE TO RISER
- FG TO RISER (ALWAYS KEPT BLINDED)
2 FOLLOWING LINES SHOULD BE ISOLATED BY BLINDS:
- FUEL GAS TO 19F-2
- TORCH OIL TO REGENERATOR (NEAR CONTROL
VALVE)
3 LINE UP THE PURGE CONNECTION FOR INSTRUMENT
TAPS, KEEPING LAST ISOLATION VALVE CLOSED
4 LINE WYE STEAM & EMERGENCY STEAM KEEPING
19FIC466 CLOSED
5 LINE UP STRIPPING STEAM AND PRE STRIPPING STEAM
TO REACTOR KEEPING 19 FIC0501/ 19FIC0502 CLOSED.
6 LINE UP EMERGENCY PLANT AIR TO BLOWER
DISCHARGE.
7 LINE UP THE AERATION CONNECTION FOR STANDS
PIPES AND THERE EXPANSION JOINTS.
8 LINE UP FLUE GAS LINE TO STACK BYPASSING CO
BOILER.
31
9 FLUSH THE REACTOR INSTRUMENT POINTS WITH
NITROGEN AND THEN LINE UP.
10 KEEP SCSV AND RCSV CLOSE FULLY.
11 CHECK THE WARM UP LINE OF REACTOR TO OPEN
POSITION
12 START STEAMING TO REACTOR RISER AS
FOLLOWING RATES
EMERGENCY STEAM: 5.5-6 T/HR
FEED NOZZLE STEAM: 4500 KG/HR
HCO NOZZLE STEAM: 350 KG/HR
SLURRY NOZZLE STEAM: 320KG /HR
DOME STEAM : 90KG/HR
STRIPPING STEAM : 1.5 T/HR
KEEP OPEN RX TOP VENT LINE TO SILENCER.
DRAIN CONDENSATE FROM RISER BOTTOM
13 DRAIN SCSV CONE, BLAST AND SAMPLE POINT FOR
DRAINING CONDENSATE FROM STANDPIPE.
14 DRAIN RCSV STANDPIPE AND SAMPLE POINT FOR
DRAINING CONDENSATE FROM STANDPIPE
15 DRAIN CONDENSATE FROM THE BOTTOM OF THE
RISER AND STANDPIPES.
16 ENSURE MAB ANTI-SURGE IN OPEN CONDITION.
17 FLUE GAS SLIDE VALVE (DDSV) IN FULL OPEN
CONDITION.
32
NITROGEN AND THEN LINE UP.
10 KEEP SCSV AND RCSV CLOSE FULLY.
11 CHECK THE WARM UP LINE OF REACTOR TO OPEN
POSITION
12 START STEAMING TO REACTOR RISER AS
FOLLOWING RATES
EMERGENCY STEAM: 5.5-6 T/HR
FEED NOZZLE STEAM: 4500 KG/HR
HCO NOZZLE STEAM: 350 KG/HR
SLURRY NOZZLE STEAM: 320KG /HR
DOME STEAM : 90KG/HR
STRIPPING STEAM : 1.5 T/HR
KEEP OPEN RX TOP VENT LINE TO SILENCER.
DRAIN CONDENSATE FROM RISER BOTTOM
13 DRAIN SCSV CONE, BLAST AND SAMPLE POINT FOR
DRAINING CONDENSATE FROM STANDPIPE.
14 DRAIN RCSV STANDPIPE AND SAMPLE POINT FOR
DRAINING CONDENSATE FROM STANDPIPE
15 DRAIN CONDENSATE FROM THE BOTTOM OF THE
RISER AND STANDPIPES.
16 ENSURE MAB ANTI-SURGE IN OPEN CONDITION.
17 FLUE GAS SLIDE VALVE (DDSV) IN FULL OPEN
CONDITION.
32
18 START MAB AND KEEP WATCH ON REGENERATOR PRESSURE AND
IT SHOULD BE MAINTAINED SLIGHTLY BELOW REACTOR PRESSURE
TO AVOID AIR INGRESS TO REACTOR (ABOUT –0.05KG/CM2). REF.
MAB START UP CHECK LIST.
19 OPEN THE SPECTACLE BLIND IN THE FUEL GAS TO DFAH.
20 CHECK FOR CONDENSATE AT FG KNOCK OUT DRUM AT B/L AND
UPSTREAM DRAIN OF FG CONTROL VALVE
21 VERIFY THE DFAH DAMPER IN DESIRED CONDITION TO FACILITATE
REGULATED AIR FLOW TO BURNERS.
22 OPEN AIR PURGES TO THE SITE GLASSES
23 LIGHT UP PILOT BURNER.
24 COMMISSION THE MAIN BURNER AND MONITOR THE FLAMES
THOUGH THE SITE GLASSES. (REF. DFAH LIGHT UP)
25 BEGIN TO HEAT UP REGENERATOR AT A MAXIMUM RATE OF 50
0
C
/HR TO TARGET TEMPERATURE OF 540
0
C. HOT BOLTING OF RG
MANHOLES AT 200 & 500 DEGC.
26 START ATOMIZING STEAM & NOZZLE COOLING STEAM WHEN
REGENERATOR TEMPERATURE IS 250
0
C
27 DRY OUT THE REFRACTORY OF REGENERATOR AS PER
PROCEDURE.
28 STOP MAB AFTER REFRACTORY DRY OUT
29 REMOVE VAPOR LINE BLIND (REFER CHECK LIST)
30 CLOSE BOTH WARM UP VALVES AFTER VAPOUR LINE
DEBLINDING.(INSERT BLIND BETWEEN BOTH VALVES)
32 NORMALIZE STEAM INJECTION TO REACTOR AND RISER WITH
PRIOR FLOW RATES
33
IT SHOULD BE MAINTAINED SLIGHTLY BELOW REACTOR PRESSURE
TO AVOID AIR INGRESS TO REACTOR (ABOUT –0.05KG/CM2). REF.
MAB START UP CHECK LIST.
19 OPEN THE SPECTACLE BLIND IN THE FUEL GAS TO DFAH.
20 CHECK FOR CONDENSATE AT FG KNOCK OUT DRUM AT B/L AND
UPSTREAM DRAIN OF FG CONTROL VALVE
21 VERIFY THE DFAH DAMPER IN DESIRED CONDITION TO FACILITATE
REGULATED AIR FLOW TO BURNERS.
22 OPEN AIR PURGES TO THE SITE GLASSES
23 LIGHT UP PILOT BURNER.
24 COMMISSION THE MAIN BURNER AND MONITOR THE FLAMES
THOUGH THE SITE GLASSES. (REF. DFAH LIGHT UP)
25 BEGIN TO HEAT UP REGENERATOR AT A MAXIMUM RATE OF 50
0
C
/HR TO TARGET TEMPERATURE OF 540
0
C. HOT BOLTING OF RG
MANHOLES AT 200 & 500 DEGC.
26 START ATOMIZING STEAM & NOZZLE COOLING STEAM WHEN
REGENERATOR TEMPERATURE IS 250
0
C
27 DRY OUT THE REFRACTORY OF REGENERATOR AS PER
PROCEDURE.
28 STOP MAB AFTER REFRACTORY DRY OUT
29 REMOVE VAPOR LINE BLIND (REFER CHECK LIST)
30 CLOSE BOTH WARM UP VALVES AFTER VAPOUR LINE
DEBLINDING.(INSERT BLIND BETWEEN BOTH VALVES)
32 NORMALIZE STEAM INJECTION TO REACTOR AND RISER WITH
PRIOR FLOW RATES
33
33 START MAB AFTER VAPOR LINE BLIND REMOVAL
34 DIFFERENTIAL PRESSURE ACROSS Rx – Rg MUST BE MAINTAIN NEGATIVE(-
0.05-KG/CM
2
), TO AVOID AIR INGRESS TO REACTOR.
35 AGAIN LIGHT UP DFAH AND HEAT UP REGENERATOR
36 LOAD CATALYST TO REGENERATOR TO ABOUT 90% OF REGENERATOR
LEVEL INDICATION AFTER REGENERATOR TEMPERATURE REACH 540
O
C
37 HEAT THE CATALYST INVENTORY @ 110
O
C/HR
38 LINE UP TORCH OIL C/V ENSURE FLOW UP TO C/V UPSTREAM.
39 START TORCH OIL INJECTION WHEN REGENERATOR DENSE BED
TEMPERATURE IS ABOVE 450 DEG C.
ENSURE AUTO IGNITION OF TORCH OIL BY WATCHING RAISE IN RG DENSE
BED TEMPERATURE.
MONITOR CATALYST HEAT UP RATE AND SHOULD NOT EXCEED BEYOND
110 DEG C / HR AFTER TORCH OIL INJECTION. ADJUST TORCH OIL
INJECTION RATE TO ACHIEVE CATALYST HEAT UP RATE.
37 START CATALYST CIRCULATION AFTER ATTAINING REGENERATOR DENSE
BED TEMPERATURE OF 650 DEG C.
- OPEN RCSV SLOWLY TO 10 –12 % AND TAKE CATALYST LEVEL IN
REACTOR.
- KEEP WATCH ON REGENERATOR LEVEL IT SHOULD NOT DROP VERY
FAST.
- ONCE CATALYST LEVEL IN REACTOR IS BUILD UP TO 30-40 % OPEN
SCSV SLIDE VALVE SLOWLY AND MAINTAIN REACTOR LEVEL AROUND
60 %.
- RAISE REGENERATOR PRESSURE SLOWLY AND MAINTAIN
REGENERATOR – REACTOR DIFFERENTIAL PRESSURE POSITIVE(AT THIS
TIME SEALING AT SCSV IS AVAILABLE).
34
34 DIFFERENTIAL PRESSURE ACROSS Rx – Rg MUST BE MAINTAIN NEGATIVE(-
0.05-KG/CM
2
), TO AVOID AIR INGRESS TO REACTOR.
35 AGAIN LIGHT UP DFAH AND HEAT UP REGENERATOR
36 LOAD CATALYST TO REGENERATOR TO ABOUT 90% OF REGENERATOR
LEVEL INDICATION AFTER REGENERATOR TEMPERATURE REACH 540
O
C
37 HEAT THE CATALYST INVENTORY @ 110
O
C/HR
38 LINE UP TORCH OIL C/V ENSURE FLOW UP TO C/V UPSTREAM.
39 START TORCH OIL INJECTION WHEN REGENERATOR DENSE BED
TEMPERATURE IS ABOVE 450 DEG C.
ENSURE AUTO IGNITION OF TORCH OIL BY WATCHING RAISE IN RG DENSE
BED TEMPERATURE.
MONITOR CATALYST HEAT UP RATE AND SHOULD NOT EXCEED BEYOND
110 DEG C / HR AFTER TORCH OIL INJECTION. ADJUST TORCH OIL
INJECTION RATE TO ACHIEVE CATALYST HEAT UP RATE.
37 START CATALYST CIRCULATION AFTER ATTAINING REGENERATOR DENSE
BED TEMPERATURE OF 650 DEG C.
- OPEN RCSV SLOWLY TO 10 –12 % AND TAKE CATALYST LEVEL IN
REACTOR.
- KEEP WATCH ON REGENERATOR LEVEL IT SHOULD NOT DROP VERY
FAST.
- ONCE CATALYST LEVEL IN REACTOR IS BUILD UP TO 30-40 % OPEN
SCSV SLIDE VALVE SLOWLY AND MAINTAIN REACTOR LEVEL AROUND
60 %.
- RAISE REGENERATOR PRESSURE SLOWLY AND MAINTAIN
REGENERATOR – REACTOR DIFFERENTIAL PRESSURE POSITIVE(AT THIS
TIME SEALING AT SCSV IS AVAILABLE).
34
CHECK LIST FOR FCC START UP - FRACTIONATOR
SL.NO STEPS START
TIME
COMP
TIME
SIGN REMARKS
FRACTIONATOR
1 FOLLOWING LINE SHOULD BE ISOLATED BY BLINDS:
- FUEL GAS AND PILOT GAS LINE TO 19-F-1.
- PURGE STEAM TO COLUMN AND VESSELS
2 LINE UP THE WHOLE SYSTEM-KEEPING PRODUCT R/D
B/VS AT BATTERY LIMIT CLOSED.
3 ESTABLISH TRACING STEAM TO VARIOUS LINES.
4 KEEP OPEN 19-C-1 TOP VENT AND ITS VALVE FEW
ROUNDS.
5 START STEAMING AFTER REMOVING PURGE STEAM
BLINDS
- TOP CIRCUIT
- HY NAPHTHA CIRCUIT
- LCO CIRCUIT
- HCO CIRCUIT
- BOTTOM CIRCUIT.
ENSURE VENTS AND LPD’S ARE OPEN BEFORE
STARTUP OF STEAMING
6 DO NOT RUN FRACTIONATOR OVERHEAD FIN COOLERS
AND CLOSE TRIM COOLERS COOLING WATER VALVES
AND DRAIN THE WATER SIDE. (KEEP DRAINS AND VENTS
OPEN OF CW SIDE TO AVOID HAMMERING)
35
SL.NO STEPS START
TIME
COMP
TIME
SIGN REMARKS
FRACTIONATOR
1 FOLLOWING LINE SHOULD BE ISOLATED BY BLINDS:
- FUEL GAS AND PILOT GAS LINE TO 19-F-1.
- PURGE STEAM TO COLUMN AND VESSELS
2 LINE UP THE WHOLE SYSTEM-KEEPING PRODUCT R/D
B/VS AT BATTERY LIMIT CLOSED.
3 ESTABLISH TRACING STEAM TO VARIOUS LINES.
4 KEEP OPEN 19-C-1 TOP VENT AND ITS VALVE FEW
ROUNDS.
5 START STEAMING AFTER REMOVING PURGE STEAM
BLINDS
- TOP CIRCUIT
- HY NAPHTHA CIRCUIT
- LCO CIRCUIT
- HCO CIRCUIT
- BOTTOM CIRCUIT.
ENSURE VENTS AND LPD’S ARE OPEN BEFORE
STARTUP OF STEAMING
6 DO NOT RUN FRACTIONATOR OVERHEAD FIN COOLERS
AND CLOSE TRIM COOLERS COOLING WATER VALVES
AND DRAIN THE WATER SIDE. (KEEP DRAINS AND VENTS
OPEN OF CW SIDE TO AVOID HAMMERING)
35
7 PUMP OUT CONDENSATE IN 19-V-5 BOOTS TO SRU BY RUNNING
19-P-12. DRAINING IN OWS IS TO BE DONE CAREFULLY IF
REQUIRED.
8 KEEP STEAMING FOR 2 HOURS AND DRAIN CONDENSATE FROM
LPD.
9 RAISE SYSTEM PRESSURE TO 0.5 KG/CM
2
(G) BY THROTTLING
VENT AND LPD AND CHECK THE SYSTEM FOR ANY LEAKAGE.
10 CLOSE ALL VENTS AND INTRODUCE FUEL GAS IN THE SYSTEM
THROUGH 19C-2.
11 CONTINUE WATER DRAINING FROM THE LPD. LPD SHOULD NOT
BE LEFT OPEN AND UNATTENDED ONCE FUEL GAS BACK UP IN
THE SYSTEM.
12 KEEP 19PC202 5-10% TO FLARE. THIS WILL ENSURE THAT ANY
AIR THAT MIGHT STILL REMAIN IN THE SYSTEM IS PURGED OUT
TO THE FLARE.
13 START FIN FAN COOLERS.
14 MAINTAIN 19C-1 TOP TEMPERATURE 110
0
C TO MINIMIZE
STEAM CONDENSATION IN THE COLUMN.
16 ONCE THERE IS INVENTORY IN 19C1 START 19P3 WITH FLO
,ENSURE FLOW THROUGH CLO AND SLURRY RECYCLE CIRCUIT
17 START COLD CIRCULATION.
FILL THE LCO/HCO CIRCUITS AND COLUMN BOTTOM WITH FLO
AND CONTINUE TO CHECK FOR WATER AT THE LOW POINT
DRAINS THROUGH OUT THE BOTTOMS AND THE FEED PRE-
HEAT SYSTEM. ONCE THE DRAINING IS COMPLETE CAP ALL THE
LPD’S
36
19-P-12. DRAINING IN OWS IS TO BE DONE CAREFULLY IF
REQUIRED.
8 KEEP STEAMING FOR 2 HOURS AND DRAIN CONDENSATE FROM
LPD.
9 RAISE SYSTEM PRESSURE TO 0.5 KG/CM
2
(G) BY THROTTLING
VENT AND LPD AND CHECK THE SYSTEM FOR ANY LEAKAGE.
10 CLOSE ALL VENTS AND INTRODUCE FUEL GAS IN THE SYSTEM
THROUGH 19C-2.
11 CONTINUE WATER DRAINING FROM THE LPD. LPD SHOULD NOT
BE LEFT OPEN AND UNATTENDED ONCE FUEL GAS BACK UP IN
THE SYSTEM.
12 KEEP 19PC202 5-10% TO FLARE. THIS WILL ENSURE THAT ANY
AIR THAT MIGHT STILL REMAIN IN THE SYSTEM IS PURGED OUT
TO THE FLARE.
13 START FIN FAN COOLERS.
14 MAINTAIN 19C-1 TOP TEMPERATURE 110
0
C TO MINIMIZE
STEAM CONDENSATION IN THE COLUMN.
16 ONCE THERE IS INVENTORY IN 19C1 START 19P3 WITH FLO
,ENSURE FLOW THROUGH CLO AND SLURRY RECYCLE CIRCUIT
17 START COLD CIRCULATION.
FILL THE LCO/HCO CIRCUITS AND COLUMN BOTTOM WITH FLO
AND CONTINUE TO CHECK FOR WATER AT THE LOW POINT
DRAINS THROUGH OUT THE BOTTOMS AND THE FEED PRE-
HEAT SYSTEM. ONCE THE DRAINING IS COMPLETE CAP ALL THE
LPD’S
36
18 TAKE MP STEAM BACK UP IN 19 E4 AND HEAT COLUMN
BOTTOM CIRCUIT SLOWLY.
19 TAKE A PILOT BURNER IN 19 F1
20 DISPLACE FLO WITH HVGO AFTER MCB TEMPERATURE REACH
AT 120
0
C
21 INCREASE MCB TEMPERATURE TO 150
0
C AND CONTINUE
CIRCULATION.
22 STOP CIRCULATION KEEPING PILOT BURNERS ON. CLOSE FUEL
GAS MAKE UP VALVE IN 19-C-2.
23 REMOVE VAPOUR LINE BLIND.
(REFER CHECKLIST)
24 INTRODUCE FUEL GAS IN 19-C-2 AND RAISE SYSTEM PRESSURE
OF 0.7 KG/CM
2
(G). KEEP 19-PIC-0202 IN AUTO.
25 START CIRCULATION WITH HVGO.
26 LINE OUT THE MAIN COLUMN.
37
BOTTOM CIRCUIT SLOWLY.
19 TAKE A PILOT BURNER IN 19 F1
20 DISPLACE FLO WITH HVGO AFTER MCB TEMPERATURE REACH
AT 120
0
C
21 INCREASE MCB TEMPERATURE TO 150
0
C AND CONTINUE
CIRCULATION.
22 STOP CIRCULATION KEEPING PILOT BURNERS ON. CLOSE FUEL
GAS MAKE UP VALVE IN 19-C-2.
23 REMOVE VAPOUR LINE BLIND.
(REFER CHECKLIST)
24 INTRODUCE FUEL GAS IN 19-C-2 AND RAISE SYSTEM PRESSURE
OF 0.7 KG/CM
2
(G). KEEP 19-PIC-0202 IN AUTO.
25 START CIRCULATION WITH HVGO.
26 LINE OUT THE MAIN COLUMN.
37
CHECK LIST FOR FCC START UP – GAS CONCENTRATION
SL.NO STEPS START
TIME
COMP
TIME
SIGN REMARKS
GAS CONCENTRATION
1 REMOVE ALL THE BLINDS.
2 LINE UP THE WHOLE SYSTEM-KEEPING PRODUCT R/D
B/VS AT BATTERY LIMIT CLOSED.
3 PURGE WGC WITH NITROGEN.
4 KEEP WGC 1
ST
STAGE SUCTION AND 2
ND
STAGE
DISCHARGE VALVE CLOSED AND ANTI SURGE IN OPEN
CONDITION
5 START GCU STEAMING THROUGH STEAM OUT POINTS.
ENSURE THAT DRAINS AND VENTS ARE OPEN BEFORE
START OF STEAMING
6 OPEN WGC KOD DRAIN LPD.
7 CLOSE COOLING WATER VALVES IN 19E13A/B/C AND
DRAIN THE WATERSIDE.
OPEN THE DRAIN AND VENTS OF CW SIDE.
8 KEEP STEAMING FOR 2 HOURS AND DRAIN
CONDENSATE FROM LPD.
PRESSURE TEST ALL THE FLANGES FOR ANY LEAK BY
RAISING PRESSURE OF SYSTEM
9 ROLL WGC. KEEP 2
ND
STAGE DISCHARGE VALVE CLOSED.
(REFER CHECK LIST)
10 START PRESSURIZING GCU BY FG.
11 CLOSE ALL THE DRAINS AND VENTS 38
SL.NO STEPS START
TIME
COMP
TIME
SIGN REMARKS
GAS CONCENTRATION
1 REMOVE ALL THE BLINDS.
2 LINE UP THE WHOLE SYSTEM-KEEPING PRODUCT R/D
B/VS AT BATTERY LIMIT CLOSED.
3 PURGE WGC WITH NITROGEN.
4 KEEP WGC 1
ST
STAGE SUCTION AND 2
ND
STAGE
DISCHARGE VALVE CLOSED AND ANTI SURGE IN OPEN
CONDITION
5 START GCU STEAMING THROUGH STEAM OUT POINTS.
ENSURE THAT DRAINS AND VENTS ARE OPEN BEFORE
START OF STEAMING
6 OPEN WGC KOD DRAIN LPD.
7 CLOSE COOLING WATER VALVES IN 19E13A/B/C AND
DRAIN THE WATERSIDE.
OPEN THE DRAIN AND VENTS OF CW SIDE.
8 KEEP STEAMING FOR 2 HOURS AND DRAIN
CONDENSATE FROM LPD.
PRESSURE TEST ALL THE FLANGES FOR ANY LEAK BY
RAISING PRESSURE OF SYSTEM
9 ROLL WGC. KEEP 2
ND
STAGE DISCHARGE VALVE CLOSED.
(REFER CHECK LIST)
10 START PRESSURIZING GCU BY FG.
11 CLOSE ALL THE DRAINS AND VENTS 38
FEED CUT IN
1 FEED TO BE CUT TO REACTOR WHEN REACTOR TEMPERATURE
REACHES 530
O
C WITH THE HELP OF CATALYST CIRCULATION.
2 FOLLOW THE START UP PROCEDURE AND STABILIZE THE UNIT.
3 START GSU AND PRU AS PER PROCEDURE AFTER GAS-CON
SECTION IS STABILIZED
39
1 FEED TO BE CUT TO REACTOR WHEN REACTOR TEMPERATURE
REACHES 530
O
C WITH THE HELP OF CATALYST CIRCULATION.
2 FOLLOW THE START UP PROCEDURE AND STABILIZE THE UNIT.
3 START GSU AND PRU AS PER PROCEDURE AFTER GAS-CON
SECTION IS STABILIZED
39
8.0 SHUT DOWN PROCEDURE
While shutting down the unit following points & sequence of action may be followed :
1. Two hours before the schedule shutdown time increase CLO yield to maximum by dropping LCO to
have the slurry as light as possible.
2. Inform TPS and RSM & divert CO to Stack.
3. Starts Catalyst unloading from regenerator to hopper. The aim is to reduce catalyst level in
Regenerator without affecting catalyst circulation.
4. Line up FLO ex AVU / OM&S
5. Starts reducing fresh feed to riser. Stop 19P-25 at feed flow <140M3/hr. Reduce 19F-1 coil O/L
temperature also.
6. Reduce Catalyst level in reactor.
7. Reduce reactor temperature in steps. This will reduce coke make. Adjust air to regenerator
accordingly.
8. In gas concentration unit, operate all vessels & column at min. level.
9. Reduce raw oil charge rate in steps of 5 M3/hr.
10. When fresh feed is 120 M3/hr divert feed to column (bypass riser). Close feed to riser isolation valve
11.Put 19Rx-1 reactor interlock in bypass mode to operate LRC & TRC. Continue catalyst circulation for 5
minutes and then close TRC. At 480
0
C close TRC & transfer reactor catalyst to Rg by opening LRC and
then close LRC.
12. Keep Rg-Rx Delta P negative value : -0.05 to -0.1 Kg/cm
2
after Rx level is zero
13. Shut down 19P-2 A/B and off site feed pump. Isolate 19FIC118 C/V, OHCU hot feed B/V
14. Open gas back up to 19C-2. Stop WGC from Woodward panel Normal S/D, commission 19PIC-202.
15. Start steam venting from 19F-1
16. Keep 19K-1 air blower running with 35000-40000 Nm3/hr flow. Continue Cat. Off loading .
40
While shutting down the unit following points & sequence of action may be followed :
1. Two hours before the schedule shutdown time increase CLO yield to maximum by dropping LCO to
have the slurry as light as possible.
2. Inform TPS and RSM & divert CO to Stack.
3. Starts Catalyst unloading from regenerator to hopper. The aim is to reduce catalyst level in
Regenerator without affecting catalyst circulation.
4. Line up FLO ex AVU / OM&S
5. Starts reducing fresh feed to riser. Stop 19P-25 at feed flow <140M3/hr. Reduce 19F-1 coil O/L
temperature also.
6. Reduce Catalyst level in reactor.
7. Reduce reactor temperature in steps. This will reduce coke make. Adjust air to regenerator
accordingly.
8. In gas concentration unit, operate all vessels & column at min. level.
9. Reduce raw oil charge rate in steps of 5 M3/hr.
10. When fresh feed is 120 M3/hr divert feed to column (bypass riser). Close feed to riser isolation valve
11.Put 19Rx-1 reactor interlock in bypass mode to operate LRC & TRC. Continue catalyst circulation for 5
minutes and then close TRC. At 480
0
C close TRC & transfer reactor catalyst to Rg by opening LRC and
then close LRC.
12. Keep Rg-Rx Delta P negative value : -0.05 to -0.1 Kg/cm
2
after Rx level is zero
13. Shut down 19P-2 A/B and off site feed pump. Isolate 19FIC118 C/V, OHCU hot feed B/V
14. Open gas back up to 19C-2. Stop WGC from Woodward panel Normal S/D, commission 19PIC-202.
15. Start steam venting from 19F-1
16. Keep 19K-1 air blower running with 35000-40000 Nm3/hr flow. Continue Cat. Off loading .
40
18. After feed out amount of riser steam to prevent plugging with catalyst
a) Emergency steam about 6 t/hr, b) Feed nozzle steam about 4 t/hr c) HCO nozzle steam about 250
kg/hr, d) Slurry nozzle steam about 250 kg/hr, e) Stripping steam about 1.5 t/hr, f) Pre stripping steam
about 90 Kg/hr
19. Start feed pump, reduce feed rate to 10% of design and continue sending MCB to storage . Charge
FLO in 19V-4 and continue slurry circuit dilution. Bottom circulation continues.
20. Check bottom sample, take FLO in HCO tray & flush HCO circuit by running 19P-106.
21. Close FG make up to 19C2. Depressurize 19C1 to flare.
22. Proceed for Rx vapor line blinding.
23. REACTOR TO COLUMN VAPOUR LINE BLIND :
A. Regenerator level should be zero.
B. Isolates steam to structure B/Vs at pipe rack (3 nos.)
C. Reduce MAB rpm gradually & stop the blower (normal S/D from Woodward panel). Do not stop
blower by ESD.
D. Stop feed pump after lowering 19-V-4 level to minimum.
E. Stop 19P103 after pump loosing the suction. Isolate FLO to 19P103 seal, LT, LG, and flow
transmitters. Wait for around 15-20 minutes and for any increase in level of column. In case of level
increase due to draining from inside the column, empty out it again. Isolate B/Vs to 19E-21 & 19E-D
at 19P-3 discharge manifold.
F. TRC & LRC slide valves should be tightly shut on hand wheel.
G. Check isolation of 20LIC-0044, 20LIC-0065
H. Stop gas back up to 19C-2.
I. Open 19PIC-202 fully to de-pressurize main column 19C-1 to flare. Keep open 19PIC-202 (Note
19PIC202 valve is not to be CLOSED as NRV is provided to prevent backflow of other unit flare
release to FCCU flare header.
41
a) Emergency steam about 6 t/hr, b) Feed nozzle steam about 4 t/hr c) HCO nozzle steam about 250
kg/hr, d) Slurry nozzle steam about 250 kg/hr, e) Stripping steam about 1.5 t/hr, f) Pre stripping steam
about 90 Kg/hr
19. Start feed pump, reduce feed rate to 10% of design and continue sending MCB to storage . Charge
FLO in 19V-4 and continue slurry circuit dilution. Bottom circulation continues.
20. Check bottom sample, take FLO in HCO tray & flush HCO circuit by running 19P-106.
21. Close FG make up to 19C2. Depressurize 19C1 to flare.
22. Proceed for Rx vapor line blinding.
23. REACTOR TO COLUMN VAPOUR LINE BLIND :
A. Regenerator level should be zero.
B. Isolates steam to structure B/Vs at pipe rack (3 nos.)
C. Reduce MAB rpm gradually & stop the blower (normal S/D from Woodward panel). Do not stop
blower by ESD.
D. Stop feed pump after lowering 19-V-4 level to minimum.
E. Stop 19P103 after pump loosing the suction. Isolate FLO to 19P103 seal, LT, LG, and flow
transmitters. Wait for around 15-20 minutes and for any increase in level of column. In case of level
increase due to draining from inside the column, empty out it again. Isolate B/Vs to 19E-21 & 19E-D
at 19P-3 discharge manifold.
F. TRC & LRC slide valves should be tightly shut on hand wheel.
G. Check isolation of 20LIC-0044, 20LIC-0065
H. Stop gas back up to 19C-2.
I. Open 19PIC-202 fully to de-pressurize main column 19C-1 to flare. Keep open 19PIC-202 (Note
19PIC202 valve is not to be CLOSED as NRV is provided to prevent backflow of other unit flare
release to FCCU flare header.
41
I. Charge steam into the main Fractionator side strippers and establish steam purge in 19C-1 bottom
using the try lines.
J. Reduce riser steam to minimum. Just before opening flange isolate riser steam. Close steam to 19C-2
& 19C-3 C/Vs. Slight amount of steam should go through column bottom try line.
K. Inform Fire and safety to be present with fire tender before the execution of the job
L. Check wind direction and accordingly place the working people for job. Air hose must be on.
M. Give clearance to M/M for blinding & Rx warm up line deblinding.
N. After vapor line blind & warm up line deblind, open warm up line, increase steam to riser at standard
rate, Start MAB for catalyst unloading & regenerator cooling. Continue cooling the regenerator using
MAB. Take FG in 19C-1.
24. Start coil purging steam to 19C1 bottom and stripping steam to 19C2/C3 and open 19C1 top vent.
Start 19V-105 steamin. Total steaming for ~10 hrs.
25. 19C-1 blinding except Rx bypass & top reflux
26. Take steam to 19C1/C2/C3 for 10 hrs. followed by Hot water wash, kmno4 wash, cold water wash
27. Top reflux & Rx bypass blinding
28. 19C-1 Manhole opening
GAS CONCENTRATION UNIT:
1. Isolate 20PIC-0063.
2. Isolate 20K-1 B/Vs and purge out inert gas.
3. Do the steaming of Columns/vessel/exchangers and lines to make HC free before handling over to
M&I shutdown.
42
using the try lines.
J. Reduce riser steam to minimum. Just before opening flange isolate riser steam. Close steam to 19C-2
& 19C-3 C/Vs. Slight amount of steam should go through column bottom try line.
K. Inform Fire and safety to be present with fire tender before the execution of the job
L. Check wind direction and accordingly place the working people for job. Air hose must be on.
M. Give clearance to M/M for blinding & Rx warm up line deblinding.
N. After vapor line blind & warm up line deblind, open warm up line, increase steam to riser at standard
rate, Start MAB for catalyst unloading & regenerator cooling. Continue cooling the regenerator using
MAB. Take FG in 19C-1.
24. Start coil purging steam to 19C1 bottom and stripping steam to 19C2/C3 and open 19C1 top vent.
Start 19V-105 steamin. Total steaming for ~10 hrs.
25. 19C-1 blinding except Rx bypass & top reflux
26. Take steam to 19C1/C2/C3 for 10 hrs. followed by Hot water wash, kmno4 wash, cold water wash
27. Top reflux & Rx bypass blinding
28. 19C-1 Manhole opening
GAS CONCENTRATION UNIT:
1. Isolate 20PIC-0063.
2. Isolate 20K-1 B/Vs and purge out inert gas.
3. Do the steaming of Columns/vessel/exchangers and lines to make HC free before handling over to
M&I shutdown.
42
43
CHECK LIST FOR FCC SHUT DOWN - REACTOR – REGENERATOR
SL.NO STEPS START COMP SIGN REMARKS
TIME TIME
REACTOR- REGENERATOR
1 SLOWLY REDUCE FEED TO 140-145 M
3
/HR .ADJUST
ALL NOZZLES AND EMERGENCY ,WYE,STRIPPING
STEAM ACCORDINGLY
2 SLOWLY REDUCE REACTOR TEMPERATURE TO 500
0
C
AND DIVERT CO TO CO STACK. SHUT DOWN CO
BOILER AFTER ABOUT HALF AN HOUR.
3 START UNLOADING CATALYST FROM REGENERATOR.
REDUCE REACTOR AND REGENERATOR LEVEL
MINIMUM WITHOUT AFFECTING CAT. CIRCULATION.
4 MAINTAIN REGENERATOR TEMPERATURE AS PER
CONDITION.
5 DIVERT FEED TO COLUMN (BYPASS RISER)
6 START LOWERING REACTOR PRESSURE TO INCREASE
VAPOUR VELOCITIES IN THE RISER AND THE
CYCLONES.
7 SLOWLY DECREASE THE REGENERATOR-REACTOR P
TO GET A SLIGHTLY HIGHER PRESSURE IN THE
REACTOR THAN IN THE REGENERATOR.
8 PUT RCSV IN MANUAL MODE WHEN 19C-01
OPERATION BECOME UNSTABLE AND CONTINUE
CATALYST CIRCULATION.
CHECK LIST FOR FCC SHUT DOWN - REACTOR – REGENERATOR
SL.NO STEPS START COMP SIGN REMARKS
TIME TIME
REACTOR- REGENERATOR
1 SLOWLY REDUCE FEED TO 140-145 M
3
/HR .ADJUST
ALL NOZZLES AND EMERGENCY ,WYE,STRIPPING
STEAM ACCORDINGLY
2 SLOWLY REDUCE REACTOR TEMPERATURE TO 500
0
C
AND DIVERT CO TO CO STACK. SHUT DOWN CO
BOILER AFTER ABOUT HALF AN HOUR.
3 START UNLOADING CATALYST FROM REGENERATOR.
REDUCE REACTOR AND REGENERATOR LEVEL
MINIMUM WITHOUT AFFECTING CAT. CIRCULATION.
4 MAINTAIN REGENERATOR TEMPERATURE AS PER
CONDITION.
5 DIVERT FEED TO COLUMN (BYPASS RISER)
6 START LOWERING REACTOR PRESSURE TO INCREASE
VAPOUR VELOCITIES IN THE RISER AND THE
CYCLONES.
7 SLOWLY DECREASE THE REGENERATOR-REACTOR P
TO GET A SLIGHTLY HIGHER PRESSURE IN THE
REACTOR THAN IN THE REGENERATOR.
8 PUT RCSV IN MANUAL MODE WHEN 19C-01
OPERATION BECOME UNSTABLE AND CONTINUE
CATALYST CIRCULATION.
9 INCREASE RISER STEAM (6MT/HR) TO MAINTAIN CATALYST
CIRCULATION.
10 MAINTAIN NEGATIVE P ((ABOUT –0.05 KG/CM2) BETWEEN
REGENERATOR AND REACTOR ALL THE TIME.
11 WHEN REGENERATOR TEMPERATURE REACHES 480
0
C, FULLY
CLOSE RCSV.
12 PUT SCSV IN MANUAL MODE AND TRANSFER ALL CATALYST
FROM REACTOR TO REGENERATOR.
13 CLOSE AND LOCK BOTH SCSV AND RCSV.
14 START CATALYST OFF LOADING WITH MAB RUNNING.
15 CONTINUE STEAM TO THE RISER.
16 STOP MAB, INSERT REACTOR VAPOR LINE BLIND.
17 STEAM TO RISER FOR ½ HR.
18 START MAB FOR CATALYST UNLOADING & REGENERATOR
COOLING
19 AERATION STREAMS TO STANDPIPES ARE ISOLATED AT C/V.
RCSV/SCSV/DDSV/TPSV GLAND STEAM TO BE CHANGED TO
N2/DRY AIR. CHANGES ARE CONFIRMED..
20 TPSV AND RG PURGES ARE CHANGED TO AIR AT DENSE BED
TEMP 350 DEG C. ISOLATE 19PV-0081. AIR IS CHARGED TO
TORCH OIL ATOMIZING STEAM LINE
21 CONTINUE CATALYST UNLOADING TO 19V2. WHEN ALL CATALYST
IS REMOVED FROM THE REGENERATOR, CLOSE THE UNLOADING
LINE. CONTINUE COOLING THE REGENERATOR USING MAB.
22 AFTER COOLING OPEN RX-RG MANHOLE COVER AND GIVE MAN
ENTRY AS PER PROCEDURES
44
CIRCULATION.
10 MAINTAIN NEGATIVE P ((ABOUT –0.05 KG/CM2) BETWEEN
REGENERATOR AND REACTOR ALL THE TIME.
11 WHEN REGENERATOR TEMPERATURE REACHES 480
0
C, FULLY
CLOSE RCSV.
12 PUT SCSV IN MANUAL MODE AND TRANSFER ALL CATALYST
FROM REACTOR TO REGENERATOR.
13 CLOSE AND LOCK BOTH SCSV AND RCSV.
14 START CATALYST OFF LOADING WITH MAB RUNNING.
15 CONTINUE STEAM TO THE RISER.
16 STOP MAB, INSERT REACTOR VAPOR LINE BLIND.
17 STEAM TO RISER FOR ½ HR.
18 START MAB FOR CATALYST UNLOADING & REGENERATOR
COOLING
19 AERATION STREAMS TO STANDPIPES ARE ISOLATED AT C/V.
RCSV/SCSV/DDSV/TPSV GLAND STEAM TO BE CHANGED TO
N2/DRY AIR. CHANGES ARE CONFIRMED..
20 TPSV AND RG PURGES ARE CHANGED TO AIR AT DENSE BED
TEMP 350 DEG C. ISOLATE 19PV-0081. AIR IS CHARGED TO
TORCH OIL ATOMIZING STEAM LINE
21 CONTINUE CATALYST UNLOADING TO 19V2. WHEN ALL CATALYST
IS REMOVED FROM THE REGENERATOR, CLOSE THE UNLOADING
LINE. CONTINUE COOLING THE REGENERATOR USING MAB.
22 AFTER COOLING OPEN RX-RG MANHOLE COVER AND GIVE MAN
ENTRY AS PER PROCEDURES
44
CHECK LIST FOR FCC SHUT DOWN - FRACTIONATOR
SL.NO STEPS START
TIME
COMP
TIME
SIGN REMARKS
FRACTIONATOR
1 REDUCE DRAWING HEAVY NAPHTHA, LCO, AND
HCO. THIS WILL MAKE MCB MATERIAL LIGHTER.
2 MAINTAIN MCB LEVEL 20 TO 30%. REDUCE FEED
RATE TO 140-145 M
3
/HR CUT OUT FEED FROM
RISER AND DIVERT TO COLUMN
3 INFORM OM&S ABOUT HIGHER GENERATION OF
CLO
4 LINE FLO THROUGH AVU FOR FLUSHING AND
GLAND SEAL SOURCE
5 LOWER THE 19V5 PRESSURE TO MAINTAIN P
BETWEEN REGENERATOR AND REACTOR.
6 AFTER FEED CUT OFF START MAKE UP OF FG IN 19-
C-2 & 20V-210 TO MAINTAIN 19-C-1 PRESSURE
CONTROL.
7 PUT OFF 19-F-1 AND PURGE IT WITH STEAM. OPEN
STEAM VENT. BLIND FUEL GAS LINE INTO IT. KEEP
DAMPER 100% OPEN.
8 REDUCE FEED RATE TO 10% OF DESIGN AND
CONTINUE SENDING MCB TO STORAGE. ISOLATE
CLO TO VBU LINE.
45
SL.NO STEPS START
TIME
COMP
TIME
SIGN REMARKS
FRACTIONATOR
1 REDUCE DRAWING HEAVY NAPHTHA, LCO, AND
HCO. THIS WILL MAKE MCB MATERIAL LIGHTER.
2 MAINTAIN MCB LEVEL 20 TO 30%. REDUCE FEED
RATE TO 140-145 M
3
/HR CUT OUT FEED FROM
RISER AND DIVERT TO COLUMN
3 INFORM OM&S ABOUT HIGHER GENERATION OF
CLO
4 LINE FLO THROUGH AVU FOR FLUSHING AND
GLAND SEAL SOURCE
5 LOWER THE 19V5 PRESSURE TO MAINTAIN P
BETWEEN REGENERATOR AND REACTOR.
6 AFTER FEED CUT OFF START MAKE UP OF FG IN 19-
C-2 & 20V-210 TO MAINTAIN 19-C-1 PRESSURE
CONTROL.
7 PUT OFF 19-F-1 AND PURGE IT WITH STEAM. OPEN
STEAM VENT. BLIND FUEL GAS LINE INTO IT. KEEP
DAMPER 100% OPEN.
8 REDUCE FEED RATE TO 10% OF DESIGN AND
CONTINUE SENDING MCB TO STORAGE. ISOLATE
CLO TO VBU LINE.
45
9 STOP WITHDRAWAL HEAVY NAPHTHA AND LCO TO THE
STRIPPER.
10 START BOTTOM CIRCULATION.
11 WHEN MCB TEMPERATURE IS 150
0
C, PUMP OUT 19C2/3.
12 TAKE FLO IN 19V4 AND 19C1 AT MCB TEMP. BELOW 120 DEG C
AND START CIRCULATION. DILUTE HCO CIRCUIT WITH FLO.
CHECK BOTTOM SAMPLE.
13 MAINTAIN MCB TEMPERATURE AT 120
0
C. CLOSE FG MAKE UP
TO 19C2.
14 CONTINUE BOTTOM CIRCUIT CIRCULATION WITH FLO
15 DEPRESSURIZE 19C1 TO FLARE.
16 INSERT REACTOR VAPOR LINE BLIND
17 START COIL PURGING STEAM TO 19C1 BOTTOM AND STRIPPING
STEAM TO 19C2/C3 AND OPEN 19C1 TOP VENT. STEAMING FOR
~10 HRS.
18 19C-1 BLINDING EXCEPT RX BYPASS & TOP REFLUX
19 TAKE STEAM TO 19C1/C2/C3 FOR 10 HRS.
20 HOT WATER WASH, KMNO4 WASH, COLD WATER WASH
21 TOP REFLUX & RX BYPASS BLIND
22 MANHOLE OPENING
46
STRIPPER.
10 START BOTTOM CIRCULATION.
11 WHEN MCB TEMPERATURE IS 150
0
C, PUMP OUT 19C2/3.
12 TAKE FLO IN 19V4 AND 19C1 AT MCB TEMP. BELOW 120 DEG C
AND START CIRCULATION. DILUTE HCO CIRCUIT WITH FLO.
CHECK BOTTOM SAMPLE.
13 MAINTAIN MCB TEMPERATURE AT 120
0
C. CLOSE FG MAKE UP
TO 19C2.
14 CONTINUE BOTTOM CIRCUIT CIRCULATION WITH FLO
15 DEPRESSURIZE 19C1 TO FLARE.
16 INSERT REACTOR VAPOR LINE BLIND
17 START COIL PURGING STEAM TO 19C1 BOTTOM AND STRIPPING
STEAM TO 19C2/C3 AND OPEN 19C1 TOP VENT. STEAMING FOR
~10 HRS.
18 19C-1 BLINDING EXCEPT RX BYPASS & TOP REFLUX
19 TAKE STEAM TO 19C1/C2/C3 FOR 10 HRS.
20 HOT WATER WASH, KMNO4 WASH, COLD WATER WASH
21 TOP REFLUX & RX BYPASS BLIND
22 MANHOLE OPENING
46
CHECK LIST FOR FCC SHUT DOWN - GAS CONCENTRATION SECTION
SL.NO STEPS START
TIME
COMP
TIME
SIGN REMARKS
GAS CONCENTRATION
1 SHUTDOWN GSU AND PRU AS PER PROCEDURE
2 INFORM MEROX ABOUT OFF-SPEC LPG AND
GASOLINE GENERATION
3 SHUT DOWN WGC AND PURGE IT WITH NITROGEN
AFTER CLOSING ALL THE I/V OF WGC.( REFER
CHAPTER 34 FOR CHECKLIST)
4 CHECK THAT THE SPILL BACK VALVES OF WGC(S)
REMAIN OPEN
5 INSTALL BLIND AS PER STANDARD LIST. CLOSE
20PIC63, 20LIC44.
6 PUMP OUT 19V5 TO 20C1
7 PUMP OUT ALL LIQUID OF THE COLUMNS.
DEPRESSURIZE THE COLUMNS TO FG SYSTEM AND
THEN FLARE.
8 WHEN COLUMNS ARE EMPTY, STEAM OUT THE
UNIT (ALL COLUMN, VESSELS AND CONNECTED
LINES).OPEN THE LPD’S AND VENTS AS REQUIRED.
9 DRAIN CONDENSATE FROM LPD OF EQUIPMENTS.
10 GIVE CLEARANCE TO OPEN MANHOLE AND GIVE
CLEARANCE FOR MAN ENTRY AS PER PROCEDURE
47
SL.NO STEPS START
TIME
COMP
TIME
SIGN REMARKS
GAS CONCENTRATION
1 SHUTDOWN GSU AND PRU AS PER PROCEDURE
2 INFORM MEROX ABOUT OFF-SPEC LPG AND
GASOLINE GENERATION
3 SHUT DOWN WGC AND PURGE IT WITH NITROGEN
AFTER CLOSING ALL THE I/V OF WGC.( REFER
CHAPTER 34 FOR CHECKLIST)
4 CHECK THAT THE SPILL BACK VALVES OF WGC(S)
REMAIN OPEN
5 INSTALL BLIND AS PER STANDARD LIST. CLOSE
20PIC63, 20LIC44.
6 PUMP OUT 19V5 TO 20C1
7 PUMP OUT ALL LIQUID OF THE COLUMNS.
DEPRESSURIZE THE COLUMNS TO FG SYSTEM AND
THEN FLARE.
8 WHEN COLUMNS ARE EMPTY, STEAM OUT THE
UNIT (ALL COLUMN, VESSELS AND CONNECTED
LINES).OPEN THE LPD’S AND VENTS AS REQUIRED.
9 DRAIN CONDENSATE FROM LPD OF EQUIPMENTS.
10 GIVE CLEARANCE TO OPEN MANHOLE AND GIVE
CLEARANCE FOR MAN ENTRY AS PER PROCEDURE
47
9.0 EMERGENCY SHUT DOWN PROCEDURE
In case of any unforeseen emergency following steps are to be taken for unit shut down to safe guard
the unit.
1. Cut in enough steam to riser to prevent catalyst slump and plugging of the riser.
2. Reduce raw oil charge and recycle to the riser to minimum.
3. Adjust gas compressor speed to match the comp load. Open spill back as necessary.
4. Adjust air to regeneration to avoid after burning.
5. Divert CO to Stack.
6. (a) Cut off feed to riser (b) Direct slurry to column (C) Stop HCO recycle (d) Cut off firing in
19F-1 & vent steam (E) Stop 19P-2/P-25 (f) Close feed to riser B/V (g) Charge emergency
steam to riser.
7. Steam to Rx after feed out - Emergency steam about 6 t/hr, b) feed nozzle steam about 4 t/hr c)
HCO nozzle steam about 250 kg/hr, d) slurry nozzle steam about 250 kg/hr, e) stripping steam
about 1.5 t/hr, f) pre stripping steam about 90 kg/hr
8. Continue atomizing steam to slurry, HCO and feed nozzles if steam pressure is available.
9. Use torch oil injection to hold the dense temp around 600 deg C.
10. Keep the catalyst circulation continue with steam.
11. Shut off product routine to on-spec tanks.
12. Continue slurry circuit circulation & follow for guidance from, board operator/field operator/Shift
PNE/SPNE/DMPN(FCC)/SPNM(FCC)/CPNM.
13. Give detailed information to RSM.
Check & ensure at shift beginning that following interlocks are in line :
1. 19I-01 (FCCU trip on MAB low flow)
2. 19HS-5203 (FCCU trip on MAB trip)
48
In case of any unforeseen emergency following steps are to be taken for unit shut down to safe guard
the unit.
1. Cut in enough steam to riser to prevent catalyst slump and plugging of the riser.
2. Reduce raw oil charge and recycle to the riser to minimum.
3. Adjust gas compressor speed to match the comp load. Open spill back as necessary.
4. Adjust air to regeneration to avoid after burning.
5. Divert CO to Stack.
6. (a) Cut off feed to riser (b) Direct slurry to column (C) Stop HCO recycle (d) Cut off firing in
19F-1 & vent steam (E) Stop 19P-2/P-25 (f) Close feed to riser B/V (g) Charge emergency
steam to riser.
7. Steam to Rx after feed out - Emergency steam about 6 t/hr, b) feed nozzle steam about 4 t/hr c)
HCO nozzle steam about 250 kg/hr, d) slurry nozzle steam about 250 kg/hr, e) stripping steam
about 1.5 t/hr, f) pre stripping steam about 90 kg/hr
8. Continue atomizing steam to slurry, HCO and feed nozzles if steam pressure is available.
9. Use torch oil injection to hold the dense temp around 600 deg C.
10. Keep the catalyst circulation continue with steam.
11. Shut off product routine to on-spec tanks.
12. Continue slurry circuit circulation & follow for guidance from, board operator/field operator/Shift
PNE/SPNE/DMPN(FCC)/SPNM(FCC)/CPNM.
13. Give detailed information to RSM.
Check & ensure at shift beginning that following interlocks are in line :
1. 19I-01 (FCCU trip on MAB low flow)
2. 19HS-5203 (FCCU trip on MAB trip)
48
3. Feed bypass switch is towards Riser
4. Shutdown push button HS-0502A & B
5. 19-I-101 (FCCU reactor interlock)
6. 19F-1 pass flow low (fuel cutoff)
7. 19-F-1 FG low press (0.2 kg/cm2).
8. 19PIC0202 C/V is in DCS mode
FEED BYPASS SECURITY
On bypassing feed only feed will get diverted to column. Following actions will take place on releasing
both shutdown push buttons (HS-0502A&B) due to interlock I-101 (interlock should always remain “in
line”). Similar action will be there in case of R
x stripper level high (90%), R
x temp very low (470
0
c), RCSV
& SCSV low delta-P (0.09 kg/cm2)
Feed to riser will bypass (19-HS-79 a will close and HS-79 B will open)
Slurry To Riser will close & divert To 19-C-1, HCO Recycle shutdown valve will close
Naphtha feed to riser will close, naphtha/VBN feed to coalescer will close (VBN to DHDT will open)
TRC, LRC slide valve will close
Riser emergency, atomizing steam to Feed/HCO/Slurry/Naphtha nozzle to open
TPSV will move to divert regenerator flue gas to stack through bypass duct.
19P-2 A/B will trip, 19P-25 A/B will also trip. (linked with 19P-2 tripping).
19F-1 will trip if on low pass flow (pass flow interlock should be in line)
Note :- Incase of MAB trip or MAB low flow (990 nm
3
/hr) all above actions will take place along with
19PIC0202 full open.
Incase of high Rx temp (552
0
C) feed bypass will always take place irrespective of interlock switch
position 49
4. Shutdown push button HS-0502A & B
5. 19-I-101 (FCCU reactor interlock)
6. 19F-1 pass flow low (fuel cutoff)
7. 19-F-1 FG low press (0.2 kg/cm2).
8. 19PIC0202 C/V is in DCS mode
FEED BYPASS SECURITY
On bypassing feed only feed will get diverted to column. Following actions will take place on releasing
both shutdown push buttons (HS-0502A&B) due to interlock I-101 (interlock should always remain “in
line”). Similar action will be there in case of R
x stripper level high (90%), R
x temp very low (470
0
c), RCSV
& SCSV low delta-P (0.09 kg/cm2)
Feed to riser will bypass (19-HS-79 a will close and HS-79 B will open)
Slurry To Riser will close & divert To 19-C-1, HCO Recycle shutdown valve will close
Naphtha feed to riser will close, naphtha/VBN feed to coalescer will close (VBN to DHDT will open)
TRC, LRC slide valve will close
Riser emergency, atomizing steam to Feed/HCO/Slurry/Naphtha nozzle to open
TPSV will move to divert regenerator flue gas to stack through bypass duct.
19P-2 A/B will trip, 19P-25 A/B will also trip. (linked with 19P-2 tripping).
19F-1 will trip if on low pass flow (pass flow interlock should be in line)
Note :- Incase of MAB trip or MAB low flow (990 nm
3
/hr) all above actions will take place along with
19PIC0202 full open.
Incase of high Rx temp (552
0
C) feed bypass will always take place irrespective of interlock switch
position 49
ACTIONS TO BE TAKEN AT FIELD DURING EMERGENCY SHUT DOWN
(MAB Failure / Feed cut off or any other emergency plant S/D)
STRUCTURE
1. Close feed to riser block valve
2. Check HC-79A & B Position
3. Check riser steam C/V 19FV0466 opened. Keep an eye on stack, in case of reversal (flame) open FV-
0466 C/V B/P immediately
4. Isolate all the four feed nozzle block valves
5. Isolate both slurry recycle nozzles after steam purging
6. Isolate both HCO recycle nozzles
7. Isolate naphtha nozzle B/V
8. Ensure LRC/TRC closed (do not take in JOG/Hand wheel as panel officer may need to open TRC/LRC
for empty out RX).
9. Later take TRC/LRC in JOG Control after informing shift in charge/panel operator.
10. Keep TPSV in jog control diverted towards stack (valve position - close)
FRACTIONATOR
1. Isolate fuel oil and fuel gas block valves at furnace firing floor
2. Isolate FG control valves, ensure C/V closing
3. Vent 19F-1 steam to atmosphere
4. Co-ordinate DCS Officer to keep 15 to 20 m3/hr of feed flow thru furnace coils by running 19-P-2.
5. Line up FLO from AVU. Ensure FLO pressure > 6 KG/cm2. Ensure FLO to both 19P-103A & B primary
seal.
50
(MAB Failure / Feed cut off or any other emergency plant S/D)
STRUCTURE
1. Close feed to riser block valve
2. Check HC-79A & B Position
3. Check riser steam C/V 19FV0466 opened. Keep an eye on stack, in case of reversal (flame) open FV-
0466 C/V B/P immediately
4. Isolate all the four feed nozzle block valves
5. Isolate both slurry recycle nozzles after steam purging
6. Isolate both HCO recycle nozzles
7. Isolate naphtha nozzle B/V
8. Ensure LRC/TRC closed (do not take in JOG/Hand wheel as panel officer may need to open TRC/LRC
for empty out RX).
9. Later take TRC/LRC in JOG Control after informing shift in charge/panel operator.
10. Keep TPSV in jog control diverted towards stack (valve position - close)
FRACTIONATOR
1. Isolate fuel oil and fuel gas block valves at furnace firing floor
2. Isolate FG control valves, ensure C/V closing
3. Vent 19F-1 steam to atmosphere
4. Co-ordinate DCS Officer to keep 15 to 20 m3/hr of feed flow thru furnace coils by running 19-P-2.
5. Line up FLO from AVU. Ensure FLO pressure > 6 KG/cm2. Ensure FLO to both 19P-103A & B primary
seal.
50
6. Open FG make up to 19-C-2 (If MAB is running)
7. Close FV-118, Hot feed ex AVU/OHCU
8. Flush IFO burners
9. Start IFO circulation in 19F-1. Inform panel to open PV0104 C/V
GASCON
1. Stop 19P-12 & start local draining, Stop 19P-9 & P-10
2. Stop 20P-7, Isolate 20-LIC-65 (20-C-2 Bottom) C/V D/S B/V
3. Isolate 20 LC - 44 B/V
4. Close gasoline to Prime-G B/V at 20E-9
5. Open gasoline to Merox B/V & SDV
6. Close MP steam to 20E-220 (20FV4201 C/V) isolation
7. Close LP steam 20E-231
NOTE : Never isolate 20PIC-0063 if WGC is running
GSU
1. Stop 20P-15
2. Keep P-19, P-16, P-18 Running. GSU will be under close circulation. Prime-G will mix LCN+HCN &
return to C-207.
3. Close MP steam B/V at SDV(UV0901), open drain B/VS
CO BOILER - Take COB shut down, Isolate steam MOV, Open start up vent
NLPGTU - Stop 20P-213/214 pumps as they lose suction, stop NLPGTU pumps
51
7. Close FV-118, Hot feed ex AVU/OHCU
8. Flush IFO burners
9. Start IFO circulation in 19F-1. Inform panel to open PV0104 C/V
GASCON
1. Stop 19P-12 & start local draining, Stop 19P-9 & P-10
2. Stop 20P-7, Isolate 20-LIC-65 (20-C-2 Bottom) C/V D/S B/V
3. Isolate 20 LC - 44 B/V
4. Close gasoline to Prime-G B/V at 20E-9
5. Open gasoline to Merox B/V & SDV
6. Close MP steam to 20E-220 (20FV4201 C/V) isolation
7. Close LP steam 20E-231
NOTE : Never isolate 20PIC-0063 if WGC is running
GSU
1. Stop 20P-15
2. Keep P-19, P-16, P-18 Running. GSU will be under close circulation. Prime-G will mix LCN+HCN &
return to C-207.
3. Close MP steam B/V at SDV(UV0901), open drain B/VS
CO BOILER - Take COB shut down, Isolate steam MOV, Open start up vent
NLPGTU - Stop 20P-213/214 pumps as they lose suction, stop NLPGTU pumps
51
9.1 FIRE IN UNIT
1. Inform fire control room (Tel No. 7333, 7777)
2. Identify the place and the reason for the fire.
3. Cut off feed to the reactor, cut off furnace firing.
4. Put emergency steam to riser.
5. Stop WGC.
6. Isolate gas concentration from the Fractionator.
7. Reduce the system pressure (Adjust the pressure balance between zone).
8. Try to cut off HC supply to leak / firing.
9. Stop pumps as required.
10. Inform electric sub-station to cut off supply to equipment as per requirement.
11. Starts water sprinkling.
9.2 FEED FAILURE
If one of the two feed pumps fail, t’put will come down to 100 m3/hr level. Start standby feed pump
&normalize unit. Incase both feed pump fails, following action will take place
1. Feed pre-heater 19F-1 shut down automatically.
2. Increase Slurry / HCO recycle to riser.
3. Reduce the Cat. Circulation, so that the reactor temperature does not go very high. Aim to
keep 515 Deg C.
4. Adjust air to regenerator to avoid after burning.
5. Adjust the gas compressor speed & open spill back to avoid surging and 19V-5 low pressure.
6. Maintain column bottom level. Drop LCO.
7. Try to restore feed.
8. If feed failure is for a long time, proceed for emergency, shutdown.
52
1. Inform fire control room (Tel No. 7333, 7777)
2. Identify the place and the reason for the fire.
3. Cut off feed to the reactor, cut off furnace firing.
4. Put emergency steam to riser.
5. Stop WGC.
6. Isolate gas concentration from the Fractionator.
7. Reduce the system pressure (Adjust the pressure balance between zone).
8. Try to cut off HC supply to leak / firing.
9. Stop pumps as required.
10. Inform electric sub-station to cut off supply to equipment as per requirement.
11. Starts water sprinkling.
9.2 FEED FAILURE
If one of the two feed pumps fail, t’put will come down to 100 m3/hr level. Start standby feed pump
&normalize unit. Incase both feed pump fails, following action will take place
1. Feed pre-heater 19F-1 shut down automatically.
2. Increase Slurry / HCO recycle to riser.
3. Reduce the Cat. Circulation, so that the reactor temperature does not go very high. Aim to
keep 515 Deg C.
4. Adjust air to regenerator to avoid after burning.
5. Adjust the gas compressor speed & open spill back to avoid surging and 19V-5 low pressure.
6. Maintain column bottom level. Drop LCO.
7. Try to restore feed.
8. If feed failure is for a long time, proceed for emergency, shutdown.
52
9.3 MAIN AIR BLOWER (MAB) FAILURE
Actions at DCS Panel : Board operator has to ensure that following actions have been taken place by
PLC and if any action has not taken place he has to take action from DCS PANEL.
1. Bypass the feed (rotate feed bypass selector switch to bypass position)
2. Release shut down push buttons (HS-0502A&B)
3. Depressurize 19C-1 using hardware switch (to open 19PIC-202).
4. Open fully emergency steam to riser C/V (100%), Feed /HCO /Slurry/ naphtha atomising C/Vs
5. Bypass CO to stack.
6. Close RCSV & SCSV
7. Open DDSV Fully.
8. Bypass slurry recycle to column
9. Close HCO recycle shutdown valve
10. Divert VBN to DHDT
11. Close SR Naphtha to coalescer C/V (FV-0504A)
12. Trip feed pump 19-P-2 A/B, this will in turn trip 19-P-25 A/B
13. Cut off 19F-1 firing (FG & FO C/Vs)
14. Stop WGC when 19C-1 Top press. is 1.1 KG/cm2 (g)
15. Change 19PIC-0202 hardwire switch to normal, open FG make up and regulate 19-C-1 top
press by operating 19-PIC-202 on DCS.
NOTE: Actions mentioned above at serial nos. 1 to 12 (except step no. 7) are taken by PLC when feed
bypass security interlock I-01 and I-101 is in line. These actions are to be taken by board operator and to
be ensured by check on DCS to strengthen the safety.
53
Actions at DCS Panel : Board operator has to ensure that following actions have been taken place by
PLC and if any action has not taken place he has to take action from DCS PANEL.
1. Bypass the feed (rotate feed bypass selector switch to bypass position)
2. Release shut down push buttons (HS-0502A&B)
3. Depressurize 19C-1 using hardware switch (to open 19PIC-202).
4. Open fully emergency steam to riser C/V (100%), Feed /HCO /Slurry/ naphtha atomising C/Vs
5. Bypass CO to stack.
6. Close RCSV & SCSV
7. Open DDSV Fully.
8. Bypass slurry recycle to column
9. Close HCO recycle shutdown valve
10. Divert VBN to DHDT
11. Close SR Naphtha to coalescer C/V (FV-0504A)
12. Trip feed pump 19-P-2 A/B, this will in turn trip 19-P-25 A/B
13. Cut off 19F-1 firing (FG & FO C/Vs)
14. Stop WGC when 19C-1 Top press. is 1.1 KG/cm2 (g)
15. Change 19PIC-0202 hardwire switch to normal, open FG make up and regulate 19-C-1 top
press by operating 19-PIC-202 on DCS.
NOTE: Actions mentioned above at serial nos. 1 to 12 (except step no. 7) are taken by PLC when feed
bypass security interlock I-01 and I-101 is in line. These actions are to be taken by board operator and to
be ensured by check on DCS to strengthen the safety.
53
9.4 WET GAS COMPRESSOR (WGC) FAILURE
Rx. pressure will increase, RCSV delta-p will come down. To maintain RCSV delta-p, 19PIC0202 will open
up to 30% by PLC action & become manual. After that control Rx pr. by operating 19PIC-0202 from DCS.
If 19PIC0202 does not open then open 19PIC-0202 hardware switch for quick release of Rx pressure.
Once Rx pressure is normal, keep PIC-0202 in DCS & operate from DCS.
GCU: At present condition, even after WGC trip 20C-3 pressure remains on higher side for almost 2
hours. Hence 20C320C-4/205 flow will continue. Reduce C-4/C-205 pressure if required (LPG offspec).
COMPRESSOR OPERATOR:
- Close start up device & lower start up lever
- Start HP steam venting
- Close gland steam C/V B/P B/V
- Engage barring at 0 RPM
- Check barring start permissive & start barring. Ensure shaft rotation
- Take DMW make up & ensure surface condenser level & main CEP running. Strictly maintain level to
avoid standby CEP.
-Stop 20P-203 & 20P-2, 20P-211
-Close 2
ND
stage discharge MOV
-Field operator to ensure in field: - 1
ST
/ 2
ND
stg discharge check valve closed, 1
ST
/ 2
ND
stg suction MOV
open, 1
ST
/ 2
ND
stg antisurge open, 1
ST
stg discharge MOV remain open, 2
ND
stg discharge MOV CLOSE
GASCON OPERATOR:
Stop running 20P-7A/B, Isolate 20LIC-0065 / 20LIC-0044
Check 20PIC-63 C/V closed
Close gasoline to Prime-G B/V at 20E-9, line up towards Merox.
Incase WGC is out for long time (>2 hrs.), divert 19FIC0213 outlet to gas-con bypass B/V to divert
gasoline to Merox. Open 2
nd
b/v in this line near 20P-06a. open SDV at Merox junction.
54
Rx. pressure will increase, RCSV delta-p will come down. To maintain RCSV delta-p, 19PIC0202 will open
up to 30% by PLC action & become manual. After that control Rx pr. by operating 19PIC-0202 from DCS.
If 19PIC0202 does not open then open 19PIC-0202 hardware switch for quick release of Rx pressure.
Once Rx pressure is normal, keep PIC-0202 in DCS & operate from DCS.
GCU: At present condition, even after WGC trip 20C-3 pressure remains on higher side for almost 2
hours. Hence 20C320C-4/205 flow will continue. Reduce C-4/C-205 pressure if required (LPG offspec).
COMPRESSOR OPERATOR:
- Close start up device & lower start up lever
- Start HP steam venting
- Close gland steam C/V B/P B/V
- Engage barring at 0 RPM
- Check barring start permissive & start barring. Ensure shaft rotation
- Take DMW make up & ensure surface condenser level & main CEP running. Strictly maintain level to
avoid standby CEP.
-Stop 20P-203 & 20P-2, 20P-211
-Close 2
ND
stage discharge MOV
-Field operator to ensure in field: - 1
ST
/ 2
ND
stg discharge check valve closed, 1
ST
/ 2
ND
stg suction MOV
open, 1
ST
/ 2
ND
stg antisurge open, 1
ST
stg discharge MOV remain open, 2
ND
stg discharge MOV CLOSE
GASCON OPERATOR:
Stop running 20P-7A/B, Isolate 20LIC-0065 / 20LIC-0044
Check 20PIC-63 C/V closed
Close gasoline to Prime-G B/V at 20E-9, line up towards Merox.
Incase WGC is out for long time (>2 hrs.), divert 19FIC0213 outlet to gas-con bypass B/V to divert
gasoline to Merox. Open 2
nd
b/v in this line near 20P-06a. open SDV at Merox junction.
54
Note : Incase of WGC suction flow faulty indication (20FT6601B, 6603B), anti-surge deviation value will
fluctuate which will open/close anti-surge valves rapidly. This will fluctuate 19V-105 & Rx pressure and
may disturb R-R pressure balance. In such cases, open spillback lock HIC6601 / 6603 gradually to reduce
fluctuation & continue running WGC with spillback wide open and flaring through 19PIV-0202. During
this period, if WGC trips due to surge count, then follow procedures mentioned in 9.4 section.
9.5 STEAM FAILURE
On HP steam failure first trip WGC when Pr. < 48 Kg/cm2. If pressure does not revive, trip MAB & go for
emergency shutdown (9.3 MAB FAILURE). No/Little steam will be available for catalyst fluidization in
riser. In such case unit have
To be brought down as quickly as possible. Take following actions.
1. Close both the regenerated cat & spent cat slide valves to prevent reversal.
2. If CO-BOILER remains unaffected, try to run the unit.
3. Check the blower discharge NRV is closed. Charge service air to MAB discharge line to check
catalyst back up.
4. Cut off feed and recycles to reactor riser.
5. Maintain 19C-1 bottom circulation.
6. Stop all process pumps. Start 19K-1 & 20K-1 Motor driven LOP, CEP pumps.
7. Bottle up gas concentration unit. Isolate from Fractionator.
8. Open 19PIC202 to float 19C-1 to flare
9. When steam pressure resumes, inject steam to riser & proceed for MAB start up.
10. Close reactor,19C-2,19C-3 stripping steam and isolate the control valves
11. Gascon and Gasoline splitter unit to be bottled up.
55
fluctuate which will open/close anti-surge valves rapidly. This will fluctuate 19V-105 & Rx pressure and
may disturb R-R pressure balance. In such cases, open spillback lock HIC6601 / 6603 gradually to reduce
fluctuation & continue running WGC with spillback wide open and flaring through 19PIV-0202. During
this period, if WGC trips due to surge count, then follow procedures mentioned in 9.4 section.
9.5 STEAM FAILURE
On HP steam failure first trip WGC when Pr. < 48 Kg/cm2. If pressure does not revive, trip MAB & go for
emergency shutdown (9.3 MAB FAILURE). No/Little steam will be available for catalyst fluidization in
riser. In such case unit have
To be brought down as quickly as possible. Take following actions.
1. Close both the regenerated cat & spent cat slide valves to prevent reversal.
2. If CO-BOILER remains unaffected, try to run the unit.
3. Check the blower discharge NRV is closed. Charge service air to MAB discharge line to check
catalyst back up.
4. Cut off feed and recycles to reactor riser.
5. Maintain 19C-1 bottom circulation.
6. Stop all process pumps. Start 19K-1 & 20K-1 Motor driven LOP, CEP pumps.
7. Bottle up gas concentration unit. Isolate from Fractionator.
8. Open 19PIC202 to float 19C-1 to flare
9. When steam pressure resumes, inject steam to riser & proceed for MAB start up.
10. Close reactor,19C-2,19C-3 stripping steam and isolate the control valves
11. Gascon and Gasoline splitter unit to be bottled up.
55
9.6 POWER FAILURE
MAB / WGC will continue to run but 19P-2, P-103 will stop. Proceed for feed bypass immediately.
1. Change Feed bypass selector switch to BYPASS position on hardware panel
2. Cut in steam to riser and regulate the flow.
3. Ensure that regenerator cat. & spent cat slide valves are closed.
4. Isolate fuel supply to 19F-1.
5. Continue running WGC with spillback fully open
6. DCS supply will be available from UPS for 30 minutes. If power does not resume, trip MAB.
9.7 INSTRUMENT AIR FAILURE
In the case of general instrument air failure, 20PI-3501 (GSU B/L) DCS Alarm will generate. Instrument
air receiver at Unit 99 will allow FCCU to run for few minutes. If air pressure does not revive
immediately, it will not be possible to run the unit. All the control valves will take action to be in fail safe
position. Before that take following actions.
1. MAB to be tripped as surface condenser level will not be maintained as there will be no control
valve operation. Same in WGC.
2. Take shut down as per MAB Failure (Chapter 9.3)
3. Slide valves are operated by hydraulic oil, hence operate normal. Be sure spent & regenerated
catalyst slide valves are closed.
4. All fire shut down valves will close, hence related pumps will also trip (e.g. 19P-103).
56
MAB / WGC will continue to run but 19P-2, P-103 will stop. Proceed for feed bypass immediately.
1. Change Feed bypass selector switch to BYPASS position on hardware panel
2. Cut in steam to riser and regulate the flow.
3. Ensure that regenerator cat. & spent cat slide valves are closed.
4. Isolate fuel supply to 19F-1.
5. Continue running WGC with spillback fully open
6. DCS supply will be available from UPS for 30 minutes. If power does not resume, trip MAB.
9.7 INSTRUMENT AIR FAILURE
In the case of general instrument air failure, 20PI-3501 (GSU B/L) DCS Alarm will generate. Instrument
air receiver at Unit 99 will allow FCCU to run for few minutes. If air pressure does not revive
immediately, it will not be possible to run the unit. All the control valves will take action to be in fail safe
position. Before that take following actions.
1. MAB to be tripped as surface condenser level will not be maintained as there will be no control
valve operation. Same in WGC.
2. Take shut down as per MAB Failure (Chapter 9.3)
3. Slide valves are operated by hydraulic oil, hence operate normal. Be sure spent & regenerated
catalyst slide valves are closed.
4. All fire shut down valves will close, hence related pumps will also trip (e.g. 19P-103).
56
9.8 COOLING WATER AIR FAILURE
FCCU CW distribution:-
Process Cooling Tower PCT (19FI-0215) : New WGC, Old MAB/WGC, 20E-203A/B, 19E-19
CRU Cooling Tower (20FI-0401) : 20E-14A/B/C/D, 19E-5/6/9/11
NPRU Cooling Tower (19PI-8105/06, 19FI-8101/8102) : New MAB, LPGTU, 20E-224A/B
Total Cooling water failure will affect MAB and WGC, as there will be no water for the lube oil coolers
and surface condensers, hence air blower and WGC have to be shut down. Follow the steps for unit
shutdown as in the case of air blower failure. Additionally,
1. Run all air coolers to avoid pressure build up
2. Reduce steam to riser, nozzles and Strippers to avoid pressure build up.
3. Depressurize 19C-1 through 19PIC202 , Gascon through flare interconnection in 20PIC-0063
and debutanizers through 20HC300 / 6901
4. Run air coolers if available.
5. Stop pumps where cooling water is required for bearing and pedestal
57
FCCU CW distribution:-
Process Cooling Tower PCT (19FI-0215) : New WGC, Old MAB/WGC, 20E-203A/B, 19E-19
CRU Cooling Tower (20FI-0401) : 20E-14A/B/C/D, 19E-5/6/9/11
NPRU Cooling Tower (19PI-8105/06, 19FI-8101/8102) : New MAB, LPGTU, 20E-224A/B
Total Cooling water failure will affect MAB and WGC, as there will be no water for the lube oil coolers
and surface condensers, hence air blower and WGC have to be shut down. Follow the steps for unit
shutdown as in the case of air blower failure. Additionally,
1. Run all air coolers to avoid pressure build up
2. Reduce steam to riser, nozzles and Strippers to avoid pressure build up.
3. Depressurize 19C-1 through 19PIC202 , Gascon through flare interconnection in 20PIC-0063
and debutanizers through 20HC300 / 6901
4. Run air coolers if available.
5. Stop pumps where cooling water is required for bearing and pedestal
57
9.9 HYDRAULIC OIL FAILURE
58
58
9.9 HYDRAULIC OIL FAILURE
A) PRIMARY HYDRAULIC PUMP P-20 FAILURE – ACTIONS TO BE TAKEN IN DCS & FIELD
1. Check HMI panel at the start of the shift. Running pump (normally P-20) should be Primary & P-
21 should be secondary. Running pump must be the primary pump. P-20, 21 & circulation pump
22 – all should be in ready condition at HMI panel
2. In case of P-20 failure, Secondary Hydraulic pump P-21 should start automatically if it is in ready
condition.
3. If P-21 does not start, pressure is provided to the system by main accumulator that enables the
slide valve to be fully stroked 1 cycle / 2 strokes (closed to open AND open to closed positions).
4. To preserve main accumulator pressure take 19TIC0510 (RCSV), 19LIC61 (SCSV) & 19DPIC60
(DDSV) in Manual mode. Try to minimize slide valve controller output till pump is started from
field. Keep watch on system pressure (PI-22) & main accumulator pressure (PI-10). Once system
pressure (PI-22) is more than 110 Kg/cm
2
, put all controllers back in Auto mode.
5. Incase P-21 does not start automatically, following actions to be taken at field
a) Put 19P-21 in Manual & start the pump
b) If P-20 pump seems to be ok, put P-20 in Manual & start the pump. Incase P-20 is
running normal then stop P-21 & release stop button.
c) Put P-21 in Auto mode
d) Put P-20 in Auto mode
e) Check primary / secondary status at HMI panel. P-20 should be primary pump running &
P-21 standby.
f) Field stop buttons of all pumps must be in released condition
Note :- ESD (Emergency shutdown) function will always be there from ESD accumulator irrespective of
main accumulator pressure. Even if main accumulator pressure is very low, slide valve will get closed in
case of activation of interlock (Feed out, MAB trip etc.)
59
A) PRIMARY HYDRAULIC PUMP P-20 FAILURE – ACTIONS TO BE TAKEN IN DCS & FIELD
1. Check HMI panel at the start of the shift. Running pump (normally P-20) should be Primary & P-
21 should be secondary. Running pump must be the primary pump. P-20, 21 & circulation pump
22 – all should be in ready condition at HMI panel
2. In case of P-20 failure, Secondary Hydraulic pump P-21 should start automatically if it is in ready
condition.
3. If P-21 does not start, pressure is provided to the system by main accumulator that enables the
slide valve to be fully stroked 1 cycle / 2 strokes (closed to open AND open to closed positions).
4. To preserve main accumulator pressure take 19TIC0510 (RCSV), 19LIC61 (SCSV) & 19DPIC60
(DDSV) in Manual mode. Try to minimize slide valve controller output till pump is started from
field. Keep watch on system pressure (PI-22) & main accumulator pressure (PI-10). Once system
pressure (PI-22) is more than 110 Kg/cm
2
, put all controllers back in Auto mode.
5. Incase P-21 does not start automatically, following actions to be taken at field
a) Put 19P-21 in Manual & start the pump
b) If P-20 pump seems to be ok, put P-20 in Manual & start the pump. Incase P-20 is
running normal then stop P-21 & release stop button.
c) Put P-21 in Auto mode
d) Put P-20 in Auto mode
e) Check primary / secondary status at HMI panel. P-20 should be primary pump running &
P-21 standby.
f) Field stop buttons of all pumps must be in released condition
Note :- ESD (Emergency shutdown) function will always be there from ESD accumulator irrespective of
main accumulator pressure. Even if main accumulator pressure is very low, slide valve will get closed in
case of activation of interlock (Feed out, MAB trip etc.)
59
B) JOG CONTROL DURING LOSS OF SLIDE VALVE AUTOMATIC CONTROL :-
1. Put concerned slide valve controller in manual mode at DCS
2. Put auto/manual selector valve HV3 (located on the field control panel) to LOCAL mode (SILVER
COLOUR SELECTOR SWITCH). This will block pilot oil flow to PCV1,2,3,4 & close them. Hence oil is
locked inside the cylinder (Lock in Place). Slide valve will be locked into the last position. Lock in
place will be detected by low pressure of PG-6 or PI-6 which is installed at the downstream of
SOL-1 and HV3. Normal control operation from DCS will be overridden.
3. Once HV3 is in LOCAL mode, movement of the slide valve by Jog control can be done from field
or from control room aux. console panel.
Option A - Manual directional control valve HV2 can be used to open or close slide valve from
field. Clockwise 45
0
rotation will close slide valve & counter clock wise 45
0
rotation will open valve.
HV2 valve handle has 3 natural positions – one to close the valve, one to open & the centered
position to lock the valve in position. The valve handle must be kept in true centered position
when in automatic operation. Very precise control of slide valve opening/closing is slightly difficult
to achieve with HV2.
Option B - Ensure concerned slide valve controller in manual mode at DCS. For a very precise
control of slide valve movement, put Auto/Local selector switch HS1 (BLACK SELECTOR SWITCH)
given in field control panel in Local mode (NO NEED TO DO ANYTHING IN HV-3 OR HV-1). Solenoid
SOL1 will deenergize (close). This will block pilot oil flow to PCV1,2,3,4 & close them. Hence oil is
locked inside the cylinder (Lock in Place). Slide valve will be locked into the last position.
Automatic control through servo valve will not be there. Then slide valve can be moved by
applying power to push button for jog control solenoids SOL4 (close) or SOL5 (open). This push
buttons are available in field control panel as well as control room aux. console. With a single push
0.2% movement of slide valve is achieved. Control room push button not to be used due to
reliability problem.
60
1. Put concerned slide valve controller in manual mode at DCS
2. Put auto/manual selector valve HV3 (located on the field control panel) to LOCAL mode (SILVER
COLOUR SELECTOR SWITCH). This will block pilot oil flow to PCV1,2,3,4 & close them. Hence oil is
locked inside the cylinder (Lock in Place). Slide valve will be locked into the last position. Lock in
place will be detected by low pressure of PG-6 or PI-6 which is installed at the downstream of
SOL-1 and HV3. Normal control operation from DCS will be overridden.
3. Once HV3 is in LOCAL mode, movement of the slide valve by Jog control can be done from field
or from control room aux. console panel.
Option A - Manual directional control valve HV2 can be used to open or close slide valve from
field. Clockwise 45
0
rotation will close slide valve & counter clock wise 45
0
rotation will open valve.
HV2 valve handle has 3 natural positions – one to close the valve, one to open & the centered
position to lock the valve in position. The valve handle must be kept in true centered position
when in automatic operation. Very precise control of slide valve opening/closing is slightly difficult
to achieve with HV2.
Option B - Ensure concerned slide valve controller in manual mode at DCS. For a very precise
control of slide valve movement, put Auto/Local selector switch HS1 (BLACK SELECTOR SWITCH)
given in field control panel in Local mode (NO NEED TO DO ANYTHING IN HV-3 OR HV-1). Solenoid
SOL1 will deenergize (close). This will block pilot oil flow to PCV1,2,3,4 & close them. Hence oil is
locked inside the cylinder (Lock in Place). Slide valve will be locked into the last position.
Automatic control through servo valve will not be there. Then slide valve can be moved by
applying power to push button for jog control solenoids SOL4 (close) or SOL5 (open). This push
buttons are available in field control panel as well as control room aux. console. With a single push
0.2% movement of slide valve is achieved. Control room push button not to be used due to
reliability problem.
60
Note : Before putting auto/manual selector valve HV3 in auto mode, match slide valve DCS controller
output with actual opening in field for bump less transfer. Bump less transfer means actuator should not
jump to DCS output when control is given from local (jog) to auto (DCS) i.e. if more than 3% difference
between ZI indication & DCS output is there, slide valve will be in locked in position. If this occurs, DCS
output must be changed to ZI value (within 3%) to unlock slide valve.
C) HANDWHEEL OPERATION:-
1. To operate the handwheel, Put auto/manual selector valve HV3, located on the local control
panel to LOCAL mode. This will alert panel operator that DCS control is not available. Then
keep Hand wheel bypass valve HV1 in bypass mode.
2. Engage handwheel by pushing engagement lever forward & rotating the pointer by 180
0
to
“lock” position. Slight rotation of the handwheel may be required for perfect locking.
3. Once engaged, the handwheel engagement lever needs to be pulled out to lock it from being
able to dis-engage. To dis-engage, reverse the above sequence.
Note :- Do not force the engagement handle lever. Only slight force will be required to rotate the
handle. No excessive force will ever be required to engage the handwheel.
D) LOSS OF SLIDE VALVE CONTROL :- Any functional failure (loss of input signal, loss of control power
etc.)will deenergize (close) solenoid SOL1 & slide valve will be Locked into the last position. Lock in
position will be indicated by low value of PI6. This condition will continue until remedial action (jog
control) is taken.
Note :- Lock in position does not override the emergency shutdown function which will remain active
even if the actuator system is locked in place.
61
output with actual opening in field for bump less transfer. Bump less transfer means actuator should not
jump to DCS output when control is given from local (jog) to auto (DCS) i.e. if more than 3% difference
between ZI indication & DCS output is there, slide valve will be in locked in position. If this occurs, DCS
output must be changed to ZI value (within 3%) to unlock slide valve.
C) HANDWHEEL OPERATION:-
1. To operate the handwheel, Put auto/manual selector valve HV3, located on the local control
panel to LOCAL mode. This will alert panel operator that DCS control is not available. Then
keep Hand wheel bypass valve HV1 in bypass mode.
2. Engage handwheel by pushing engagement lever forward & rotating the pointer by 180
0
to
“lock” position. Slight rotation of the handwheel may be required for perfect locking.
3. Once engaged, the handwheel engagement lever needs to be pulled out to lock it from being
able to dis-engage. To dis-engage, reverse the above sequence.
Note :- Do not force the engagement handle lever. Only slight force will be required to rotate the
handle. No excessive force will ever be required to engage the handwheel.
D) LOSS OF SLIDE VALVE CONTROL :- Any functional failure (loss of input signal, loss of control power
etc.)will deenergize (close) solenoid SOL1 & slide valve will be Locked into the last position. Lock in
position will be indicated by low value of PI6. This condition will continue until remedial action (jog
control) is taken.
Note :- Lock in position does not override the emergency shutdown function which will remain active
even if the actuator system is locked in place.
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9.10 CO BILER FAILURE
1. Divert regenerator flue gases to stack directly.
2. Inform power plant.
9.11 BEHIND IN BURNING
SIGNS OF BEHIND IN BURNING
A) Flue gas and dilute phase temperatures are lower than the dense phase temperatures.
B) Gap between the dilute phase & dense phase is less than usual.
C) Increase in dry gas yield & CLO.
CORRECTIVE ACTION
1. Increase the air rate to regenerator.
2. Charge feed of low density and carbon.
3. Increase reactor stripping steam.
4. Lower reactor temperature.
5. Reduce raw oil charge & recycle rates to the riser.
6. When coke is burnt & difference between dense phase and dilute phase is in increasing
trend, proceed to normalize the pre-conditions.
Note : Chance of behind in burning is very less in full combustion mode as excess air is supplied to Rg.
Since air to Rg is increased after behind in burning, dense bed temperature may increase rapidly
followed by increase in flue gas temperature (after burning).
62
1. Divert regenerator flue gases to stack directly.
2. Inform power plant.
9.11 BEHIND IN BURNING
SIGNS OF BEHIND IN BURNING
A) Flue gas and dilute phase temperatures are lower than the dense phase temperatures.
B) Gap between the dilute phase & dense phase is less than usual.
C) Increase in dry gas yield & CLO.
CORRECTIVE ACTION
1. Increase the air rate to regenerator.
2. Charge feed of low density and carbon.
3. Increase reactor stripping steam.
4. Lower reactor temperature.
5. Reduce raw oil charge & recycle rates to the riser.
6. When coke is burnt & difference between dense phase and dilute phase is in increasing
trend, proceed to normalize the pre-conditions.
Note : Chance of behind in burning is very less in full combustion mode as excess air is supplied to Rg.
Since air to Rg is increased after behind in burning, dense bed temperature may increase rapidly
followed by increase in flue gas temperature (after burning).
62
9.12 AFTER BURNING
1. Add CO - Promoter
2. Reduce ROT, Increase COT, reduce t’put to reduce cat circulation rate. This will increase
catalyst residence time in Rg.
3. Increase feed CCR (less UCO), increase slurry recycle.
4. If feed & recycle rates have been reduced due to behind in burning or due to any reason,
revert the rates to normal.
5. Restore reactor condition to normal if they have been altered due to behind in burning
condition.
6. Have a close watch on air rate and other unit conditions and ensure that unit does not go
back to in behind in burning condition again.
9.13 PRESSURE IMBALANCE
1. Disturbance in MAB or WGC can lead to a pressure imbalance and subsequently closure of
slide valves. If catalyst circulation is stopped immediately feed must be cut off. It should be
reintroduced only after establishing the pressure balance and catalyst circulation.
2. DDSV can be controlled by either 19DPIC-0060 or 19DPIC0404-1. Incase of faulty indications,,
standby controller can be taken in line. Incase of DDSV valve problem, individual disc
(19HIC0060A/B) can be taken in manual control.
3. Incase of WGC trip, 19PV-0202 will open to 30% & become “Manual” to maintain Rx-Rg
pressure balance. Take 19PV-0202 in auto mode after pressure balance is restored.
63
1. Add CO - Promoter
2. Reduce ROT, Increase COT, reduce t’put to reduce cat circulation rate. This will increase
catalyst residence time in Rg.
3. Increase feed CCR (less UCO), increase slurry recycle.
4. If feed & recycle rates have been reduced due to behind in burning or due to any reason,
revert the rates to normal.
5. Restore reactor condition to normal if they have been altered due to behind in burning
condition.
6. Have a close watch on air rate and other unit conditions and ensure that unit does not go
back to in behind in burning condition again.
9.13 PRESSURE IMBALANCE
1. Disturbance in MAB or WGC can lead to a pressure imbalance and subsequently closure of
slide valves. If catalyst circulation is stopped immediately feed must be cut off. It should be
reintroduced only after establishing the pressure balance and catalyst circulation.
2. DDSV can be controlled by either 19DPIC-0060 or 19DPIC0404-1. Incase of faulty indications,,
standby controller can be taken in line. Incase of DDSV valve problem, individual disc
(19HIC0060A/B) can be taken in manual control.
3. Incase of WGC trip, 19PV-0202 will open to 30% & become “Manual” to maintain Rx-Rg
pressure balance. Take 19PV-0202 in auto mode after pressure balance is restored.
63
9.14 LOSS OF SLIDE VALVE DIFFERENTIAL
Slide valve operation is so designed that the valve automatically close off & feed cut off takes place
when the differential across the valve drops below a certain value. This acts as a safety measure and
prevent flow reversal. Closure of slide valves will stop catalyst circulation. In such condition take
following actions.
1. Take emergency shut down.
2. Cut in emergency steam to riser to avoid plugging.
3. Transfer catalyst from Rx to Rg
4. Adjust air to regenerator & WGC load.
5. Cut in feed to reactor riser as soon as catalyst circulation is reestablished.
9.15 FEED PREHEATER 19F-1 FAILURE
Check and trace the reason for failure. Take the following actions.
1. If the failure is due to coil tube leak, cut off feed to reactor, inject steam to riser & proceed
for shut down. Start furnace box purging steam.
2. If the failure is due to fuel oil / Fuel gas supply, try to establish fuel supply & light up furnace
on available fuel.
3. Incase of FG failure, isolate all FG burners. Maintain COT by taking additional FO burners in
line. Take FG burners one by one after supply restoration.
4. If furnace remains off for a longer period. Vent steam as there will be no super heating.
5. Adjust feed to reactor riser & air rate to regenerator.
64
Slide valve operation is so designed that the valve automatically close off & feed cut off takes place
when the differential across the valve drops below a certain value. This acts as a safety measure and
prevent flow reversal. Closure of slide valves will stop catalyst circulation. In such condition take
following actions.
1. Take emergency shut down.
2. Cut in emergency steam to riser to avoid plugging.
3. Transfer catalyst from Rx to Rg
4. Adjust air to regenerator & WGC load.
5. Cut in feed to reactor riser as soon as catalyst circulation is reestablished.
9.15 FEED PREHEATER 19F-1 FAILURE
Check and trace the reason for failure. Take the following actions.
1. If the failure is due to coil tube leak, cut off feed to reactor, inject steam to riser & proceed
for shut down. Start furnace box purging steam.
2. If the failure is due to fuel oil / Fuel gas supply, try to establish fuel supply & light up furnace
on available fuel.
3. Incase of FG failure, isolate all FG burners. Maintain COT by taking additional FO burners in
line. Take FG burners one by one after supply restoration.
4. If furnace remains off for a longer period. Vent steam as there will be no super heating.
5. Adjust feed to reactor riser & air rate to regenerator.
64
9.16 PLUGGED REACTOR RISER
The plugging has to be broken from top of reactor to downward direction
1. Increase steam to slurry nozzle to maximum.
2. Increase steam to HCO nozzle to maximum.
3. Increase steam to Feed nozzle to maximum.
4. Increase steam to riser.
9.17 HIGH REACTOR TEMPERATURE
High reactor temperature may be due to
A). RCSV failure
B).Feed failure / Changes in feed compositions
C).Failures of recycles
D). Sudden increase in Rg pressure. Check DDSV opening
E).Check Torch oil injection ,if it’s on stop injection
Take following actions
1. Reduce catalyst circulation rate by manually closing the regenerated catalyst slide valve
2. Reduce furnace outlet temperature
3. While effecting any change in the reactor condition close watch has to be kept on the regenerator
section, as e.g. when catalyst circulation is reduced, the regenerator temperature will go up
4. If, however, reactor temperature does not fall, drastic measure like feed and air cut out are to be
taken after stopping catalyst circulation
Note : Reactor shell design temperature is 556
0
C. Feed cut off interlock due to high Rx temperature at
552
0
C.
65
The plugging has to be broken from top of reactor to downward direction
1. Increase steam to slurry nozzle to maximum.
2. Increase steam to HCO nozzle to maximum.
3. Increase steam to Feed nozzle to maximum.
4. Increase steam to riser.
9.17 HIGH REACTOR TEMPERATURE
High reactor temperature may be due to
A). RCSV failure
B).Feed failure / Changes in feed compositions
C).Failures of recycles
D). Sudden increase in Rg pressure. Check DDSV opening
E).Check Torch oil injection ,if it’s on stop injection
Take following actions
1. Reduce catalyst circulation rate by manually closing the regenerated catalyst slide valve
2. Reduce furnace outlet temperature
3. While effecting any change in the reactor condition close watch has to be kept on the regenerator
section, as e.g. when catalyst circulation is reduced, the regenerator temperature will go up
4. If, however, reactor temperature does not fall, drastic measure like feed and air cut out are to be
taken after stopping catalyst circulation
Note : Reactor shell design temperature is 556
0
C. Feed cut off interlock due to high Rx temperature at
552
0
C.
65
9.18 VERY HIGH REGENERATOR TEMPERATURE
Because of the after burning reaction, large temperature differences between the dense phase and
dilute phase will occur. If dilute phase temperature is high it can be lowered by.
1. Reduction in air rate.
2. Increasing feed CCR (less UCO)
3. Injection of torch oil
4. Increase reactor temperature.
5. Increase slurry and HCO to reactor riser.
9.19 SLURRY PUMP FAILURE
If the spare pump does not start cut off feed and proceed for “Feed failure”.
The slurry pump maintains the level in main column and on its failing superheated reactor effluent
vapors will lift the liquid material and would cause damage to trays.
Incase of pump cavitation problem, following actions to be taken:-
1. Check flushing steam B/V to pump suction line
2. Open casing vent to column line
3. Incase of low level, take feed to column bottom from start up manifold. Keep unit T’put closely under
observation during this operation.
4. Reduce ROT
5. Increase HCO CR, Close HCO recycle
6. Drop LCO as much as possible
66
Because of the after burning reaction, large temperature differences between the dense phase and
dilute phase will occur. If dilute phase temperature is high it can be lowered by.
1. Reduction in air rate.
2. Increasing feed CCR (less UCO)
3. Injection of torch oil
4. Increase reactor temperature.
5. Increase slurry and HCO to reactor riser.
9.19 SLURRY PUMP FAILURE
If the spare pump does not start cut off feed and proceed for “Feed failure”.
The slurry pump maintains the level in main column and on its failing superheated reactor effluent
vapors will lift the liquid material and would cause damage to trays.
Incase of pump cavitation problem, following actions to be taken:-
1. Check flushing steam B/V to pump suction line
2. Open casing vent to column line
3. Incase of low level, take feed to column bottom from start up manifold. Keep unit T’put closely under
observation during this operation.
4. Reduce ROT
5. Increase HCO CR, Close HCO recycle
6. Drop LCO as much as possible
66
9.20 HCO PUMP FAILURE
If the spare pump does not start, reduce ROT immediately & later reduce T’put. Maximize MCB CR flow.
Debutanizer reboiling will disturb, hence LPG & Gasoline will be off spec.
Incase of pump cavitation problem, following actions to be taken:-
1. Take feed to HCO tray from start up manifold. Keep unit T’put closely under observation during this
operation.
2. Crack open pump casing vent, throttle discharge valve
9.21 LEAKAGE OF CATALYST - REGENERATOR ZONE
Check the possibility of attending the leak as quickly as possible, if not possible take following actions
immediately
1. Cut off feed (Bypass feed from hardware panel)
2. Cordon off the area
3. Start offloading catalyst
4. Take appropriate action to reduce leakage of catalyst
5. Ask Fire & Safety to station fire tender if required
6. If required stop MAB
7. Take preparatory action (for vapor line blinding etc) to facilitate for attending the leak
67
If the spare pump does not start, reduce ROT immediately & later reduce T’put. Maximize MCB CR flow.
Debutanizer reboiling will disturb, hence LPG & Gasoline will be off spec.
Incase of pump cavitation problem, following actions to be taken:-
1. Take feed to HCO tray from start up manifold. Keep unit T’put closely under observation during this
operation.
2. Crack open pump casing vent, throttle discharge valve
9.21 LEAKAGE OF CATALYST - REGENERATOR ZONE
Check the possibility of attending the leak as quickly as possible, if not possible take following actions
immediately
1. Cut off feed (Bypass feed from hardware panel)
2. Cordon off the area
3. Start offloading catalyst
4. Take appropriate action to reduce leakage of catalyst
5. Ask Fire & Safety to station fire tender if required
6. If required stop MAB
7. Take preparatory action (for vapor line blinding etc) to facilitate for attending the leak
67
9.21 LEAKAGE OF CATALYST - REACTOR ZONE
Check the possibility of attending the leak as quickly as possible, if not possible take following actions
immediately
1. Cut off feed (Bypass feed from hardware panel)
2. Cordon off the area
3. Take appropriate action to reduce leakage of catalyst
4. Unload the total inventory to regenerator.
5. Ask Fire & Safety to station fire tender if required
6. Take preparatory action (for vapor line blinding etc) to facilitate for attending the leak
9.22 LEAKAGE OF HYDROCARBON(ABOVE AUTO IGNITION) E.G. MCB and HCO
Take following actions
1. Cut off feed (Bypass feed from hardware panel)
2. Isolate the circuit
3. Use DCP fire Extinguisher
4. Cool the surrounding area with water spray
5. Ask Fire& Safety to station fire tender if required
6. Take preparatory action for isolation and for attending the leak .
9.23 LEAKAGE OF HYDROCARBON(ABOVE AUTO IGNITION) E.G. MCB and HCO
Take following actions
1. Cut off feed (Bypass feed from hardware panel)
2. Isolate the circuit
3. Use DCP fire Extinguisher
4. Cool the surrounding area with water spray
5. Ask Fire& Safety to station fire tender if required
6. Take preparatory action for isolation and for attending the leak . 68
Check the possibility of attending the leak as quickly as possible, if not possible take following actions
immediately
1. Cut off feed (Bypass feed from hardware panel)
2. Cordon off the area
3. Take appropriate action to reduce leakage of catalyst
4. Unload the total inventory to regenerator.
5. Ask Fire & Safety to station fire tender if required
6. Take preparatory action (for vapor line blinding etc) to facilitate for attending the leak
9.22 LEAKAGE OF HYDROCARBON(ABOVE AUTO IGNITION) E.G. MCB and HCO
Take following actions
1. Cut off feed (Bypass feed from hardware panel)
2. Isolate the circuit
3. Use DCP fire Extinguisher
4. Cool the surrounding area with water spray
5. Ask Fire& Safety to station fire tender if required
6. Take preparatory action for isolation and for attending the leak .
9.23 LEAKAGE OF HYDROCARBON(ABOVE AUTO IGNITION) E.G. MCB and HCO
Take following actions
1. Cut off feed (Bypass feed from hardware panel)
2. Isolate the circuit
3. Use DCP fire Extinguisher
4. Cool the surrounding area with water spray
5. Ask Fire& Safety to station fire tender if required
6. Take preparatory action for isolation and for attending the leak . 68
9.24 EMERGENCY DUE TO WATER IN FEED OR STEAM TO REACTOR
Condensate carryover in steam to reactor or in feed can cause damage to the riser internals due to
thermal shock. Take following actions immediately.
1. Cut off feed (Bypass feed from hardware panel)
2. Ensure that furnace is cut off
3. Isolate Gascon from Fractionator section
4. Take action to maintain required pressure balance between reactor and regenerator
5. Check steam and take action for water removal. Open all the trap bypass drain
6. Inform water block /TPS Other steam producers
7. Check Water in Feed if found inform OM&S ,take actions to make feed water free
9.25 DCS FAILURE
The DCS failure may be of 2 types:
A) DCS POWER FAILURE
In case power failure the total DCS will fail. All of the OS will be blank. All signals to the control valve
would be zero i.e. the control valve would go on there ‘zero signal position’. A twelve point recorder is
provided to monitor the critical parameter.
019-DPIC-60, Reaction - Regenerator delta pressure
019-TIC-0501, Reactor Temperature controller
019-LI-0501A, Reaction stripper level.
019-DPI-0502, Differential pressure across RCSV
019-DPI-70, differential pressure across SCSV.
019-XI-221 ,Deviation from Surge line for MAB
019-LI-1102, Fines disposal hopper level
019-FI-288, Feed flow to reactor. 69
Condensate carryover in steam to reactor or in feed can cause damage to the riser internals due to
thermal shock. Take following actions immediately.
1. Cut off feed (Bypass feed from hardware panel)
2. Ensure that furnace is cut off
3. Isolate Gascon from Fractionator section
4. Take action to maintain required pressure balance between reactor and regenerator
5. Check steam and take action for water removal. Open all the trap bypass drain
6. Inform water block /TPS Other steam producers
7. Check Water in Feed if found inform OM&S ,take actions to make feed water free
9.25 DCS FAILURE
The DCS failure may be of 2 types:
A) DCS POWER FAILURE
In case power failure the total DCS will fail. All of the OS will be blank. All signals to the control valve
would be zero i.e. the control valve would go on there ‘zero signal position’. A twelve point recorder is
provided to monitor the critical parameter.
019-DPIC-60, Reaction - Regenerator delta pressure
019-TIC-0501, Reactor Temperature controller
019-LI-0501A, Reaction stripper level.
019-DPI-0502, Differential pressure across RCSV
019-DPI-70, differential pressure across SCSV.
019-XI-221 ,Deviation from Surge line for MAB
019-LI-1102, Fines disposal hopper level
019-FI-288, Feed flow to reactor. 69
019-TIC-99, 19-F-1 outlet Temperature.
019-PIC-202, overhead receiver pressure controller.
019-LI-157, Main column bottom level.
019-TI-159, main column bottom temperature.
With the help of this recorder, unit shall be tripped manually.
Take following actions.
1. Trip MAB, this will intern activate feed out interlock. Take emergency shutdown as per
procedure.
2. Ensure in field that RCSV, SCSV closed, 19FV-0466 (Riser steam) & PV-0202 opened fully.
3. Open 19FV-0466 C/V B/P, Open 19PV-0202 hardwire switch.
4. Trip feed pump, isolate feed to riser B/V, Trip WGC.
5. Isolate 19F-1 FG/FO, vent steam
6. Proceed for other shut down activities.
B) DCS SYSTEM FAILURE:
In DCS system failure the operator station will remain on, but no data shall be available from plant. All
signal to the control valve would be last value position but the moment system restores the signals will
be at zero i.e. valve would come in fail safe condition. A twelve point recorder is provided to monitor
the critical parameter. With the help of this recorder, unit shall be tripped manually as mentioned
above.
9.26 PLC FAILURE
PLC also stands for ESDS (Emergency shutdown system). During PLC failure all critical pump auto start
facility will be suspended, also the MAB and WGC would trip. All shutdown valves shall go to their fail
safe conditions because PLC will trigger to fail safe mode.
70
019-PIC-202, overhead receiver pressure controller.
019-LI-157, Main column bottom level.
019-TI-159, main column bottom temperature.
With the help of this recorder, unit shall be tripped manually.
Take following actions.
1. Trip MAB, this will intern activate feed out interlock. Take emergency shutdown as per
procedure.
2. Ensure in field that RCSV, SCSV closed, 19FV-0466 (Riser steam) & PV-0202 opened fully.
3. Open 19FV-0466 C/V B/P, Open 19PV-0202 hardwire switch.
4. Trip feed pump, isolate feed to riser B/V, Trip WGC.
5. Isolate 19F-1 FG/FO, vent steam
6. Proceed for other shut down activities.
B) DCS SYSTEM FAILURE:
In DCS system failure the operator station will remain on, but no data shall be available from plant. All
signal to the control valve would be last value position but the moment system restores the signals will
be at zero i.e. valve would come in fail safe condition. A twelve point recorder is provided to monitor
the critical parameter. With the help of this recorder, unit shall be tripped manually as mentioned
above.
9.26 PLC FAILURE
PLC also stands for ESDS (Emergency shutdown system). During PLC failure all critical pump auto start
facility will be suspended, also the MAB and WGC would trip. All shutdown valves shall go to their fail
safe conditions because PLC will trigger to fail safe mode.
70
10.0 CRITICAL EQUIPMENT
TURBINE SPECIFICATION 19 K-101 20 K-201
Out put KW (Design) 9316 4274
Normal Speed RPM 6710 6683
Speed range RPM 6039-7046 6132-7214
Critical speed Band RPM 2700-4600 2800-3500/4000-5000
Steam pressure (Kg/cm
2
) / Temp (
0
C) 60 / 420 60/420
Exhaust Pr. (ata) 0.12 0.14
Exhaust Temp (
0
C) 49.1 49.4
Steam flow (Kg/hr) 29400 18940
BLOWER / COMPRESSOR SPECIFICATION
Capacity Normal / Rated (Kg/hr) 112693/135232 83700 (1
st
Stg)/68725(2
nd
Stg)
Suction Temp
0
C 40 40
Suction pressure Kg/cm
2
(abs) 0.984 2.5 (1
st
Stg) / 6.0(2
nd
Stg)
Mol. Weight 28.63 45.58/43.29
Inlet volume Normal / Rated (m
3
/hr) 106214/130732 21489/7556
Discharge Pressure Kg/cm
2
(abs) 4.71 16.0
Discharge Temp
0
C 253 6.72
71
TURBINE SPECIFICATION 19 K-101 20 K-201
Out put KW (Design) 9316 4274
Normal Speed RPM 6710 6683
Speed range RPM 6039-7046 6132-7214
Critical speed Band RPM 2700-4600 2800-3500/4000-5000
Steam pressure (Kg/cm
2
) / Temp (
0
C) 60 / 420 60/420
Exhaust Pr. (ata) 0.12 0.14
Exhaust Temp (
0
C) 49.1 49.4
Steam flow (Kg/hr) 29400 18940
BLOWER / COMPRESSOR SPECIFICATION
Capacity Normal / Rated (Kg/hr) 112693/135232 83700 (1
st
Stg)/68725(2
nd
Stg)
Suction Temp
0
C 40 40
Suction pressure Kg/cm
2
(abs) 0.984 2.5 (1
st
Stg) / 6.0(2
nd
Stg)
Mol. Weight 28.63 45.58/43.29
Inlet volume Normal / Rated (m
3
/hr) 106214/130732 21489/7556
Discharge Pressure Kg/cm
2
(abs) 4.71 16.0
Discharge Temp
0
C 253 6.72
71
RISER
Total height : 42.1 M (21.54 Cold Riser, Balance internal)
ID lining : WYE section - 630 mm
Lower part of riser - 700 mm
Middle part of riser - 850 mm
Internal riser - 1062 mm
MOC : Internal riser - 11/2 Cr-1/2 Mo material to spec
A 387 Gr. 11
External riser - SA-516 Gr-70
The internal riser is Resco lined, External riser is cold-wall.
Design temperature of the external riser is 207
0
C
REACTOR VESSEL
Total tangential height : 11.6 meters,
I.D. : 4.5 meters
Shell Thickness : 18 mm + 3 cladding.
MOC : 11/4 Cr-1/2 Mo to spec. A 387 Gr. 11 with 3 mm of
cladding with 11-13% Cr alloy to spec. 405.
Conical bottom of the reactor and 1.2 meters of
bottom of shell is lined with hex-mesh and abrasion
resistant Refractory lining. (RESCO AA 22)
REACTOR STRIPPER
Inner diameter : 2.450 meters
Thickness of shell : 18 mm
Total height : 6.246 meters
Mod-grid height : 4.505 meters
Material of construction : A-387 Gr II Alloy steel.
72
Total height : 42.1 M (21.54 Cold Riser, Balance internal)
ID lining : WYE section - 630 mm
Lower part of riser - 700 mm
Middle part of riser - 850 mm
Internal riser - 1062 mm
MOC : Internal riser - 11/2 Cr-1/2 Mo material to spec
A 387 Gr. 11
External riser - SA-516 Gr-70
The internal riser is Resco lined, External riser is cold-wall.
Design temperature of the external riser is 207
0
C
REACTOR VESSEL
Total tangential height : 11.6 meters,
I.D. : 4.5 meters
Shell Thickness : 18 mm + 3 cladding.
MOC : 11/4 Cr-1/2 Mo to spec. A 387 Gr. 11 with 3 mm of
cladding with 11-13% Cr alloy to spec. 405.
Conical bottom of the reactor and 1.2 meters of
bottom of shell is lined with hex-mesh and abrasion
resistant Refractory lining. (RESCO AA 22)
REACTOR STRIPPER
Inner diameter : 2.450 meters
Thickness of shell : 18 mm
Total height : 6.246 meters
Mod-grid height : 4.505 meters
Material of construction : A-387 Gr II Alloy steel.
72
Reactor Stand-Pipe
MOC : Hot wall 780 mm I.D. lining 11/4 Cr-1/2 Mo alloy steel to spec. A
387 Gr.11. The full length of the standpipe including slide valve and
expansion joint is lined with hex-mesh and abrasion resistant
cement.
Regenerator
Height : 15 M (Tangential height)
Shell O.D. : 5.7 M
Wall thickness : Shell - 18 mm
Top hemispherical head - 25 mm
MOC : Carbon steel type A-516 gr. 70. The entire length of the vessel is
lined with 4” thick monolithic refractory lining.
Regenerator Stand-Pipe
Size : Cold wall 780 mm ID lining with 100 mm refractory, thickness 20
mm thick
MOC : 5 chrome, 0.5% Mo. Alloy as per ASTM spec. A 155 Gr/5.
DIRECT FIRED AIR HEATER
MOC : Carbon steel A-285 Grade G Fire box quality. Internally lined with 5”
thick heat resistant concrete
73
MOC : Hot wall 780 mm I.D. lining 11/4 Cr-1/2 Mo alloy steel to spec. A
387 Gr.11. The full length of the standpipe including slide valve and
expansion joint is lined with hex-mesh and abrasion resistant
cement.
Regenerator
Height : 15 M (Tangential height)
Shell O.D. : 5.7 M
Wall thickness : Shell - 18 mm
Top hemispherical head - 25 mm
MOC : Carbon steel type A-516 gr. 70. The entire length of the vessel is
lined with 4” thick monolithic refractory lining.
Regenerator Stand-Pipe
Size : Cold wall 780 mm ID lining with 100 mm refractory, thickness 20
mm thick
MOC : 5 chrome, 0.5% Mo. Alloy as per ASTM spec. A 155 Gr/5.
DIRECT FIRED AIR HEATER
MOC : Carbon steel A-285 Grade G Fire box quality. Internally lined with 5”
thick heat resistant concrete
73
74
COLUMN TRAY / PACKING DETAILS
19C-1
Naphtha Fractionation Bed Gempack-2.5A (5 layers)
Heavy Naphtha Pump Around Bed Gempack (3 layers 2.5B, 3 layers 1.5B)
LCO Trays (8
th
– 19
th
: 12 nos.) High Capacity Trays
HCO Pump Around Trays (20
th
– 24
th
, 5 nos.) High Capacity Trays
HCO Pump Around Bed Gempack 1.5B, 6 layers
MCB Pump Around Tray (29
th
– 30
th
, 2 nos.) High Capacity Trays
MCB Pump Around (31
st
– 36
th
, 6 nos.) Disc & Donut Tray
19C-2 HN Stripper Valve Trays (6 Nos.)
19C-3 LCO Stripper Valve Trays (6 Nos.)
20C-1 Primary Absorber Valve Trays (36 Nos.)
20C-2 Sponge Absorber Valve Trays (20 Nos.)
20C-3 Stripper High Capacity Trays (30 Nos.)
20C-4 Debutanizer I Valve Trays (36 Nos.)
20C-205 Debutanizer II Valve Trays (48 Nos.)
20C-6 Amine Absorber High Capacity Trays (20 Nos.)
24NC-201 LPG Amine Absorber Valve Trays (14 Nos.)
20C-107 Gasoline Splitter High Capacity Trays (72 Nos. Dual Pass)
20C-108 Sponge Absorber High Capacity Trays (15 Nos.)
COLUMN TRAY / PACKING DETAILS
19C-1
Naphtha Fractionation Bed Gempack-2.5A (5 layers)
Heavy Naphtha Pump Around Bed Gempack (3 layers 2.5B, 3 layers 1.5B)
LCO Trays (8
th
– 19
th
: 12 nos.) High Capacity Trays
HCO Pump Around Trays (20
th
– 24
th
, 5 nos.) High Capacity Trays
HCO Pump Around Bed Gempack 1.5B, 6 layers
MCB Pump Around Tray (29
th
– 30
th
, 2 nos.) High Capacity Trays
MCB Pump Around (31
st
– 36
th
, 6 nos.) Disc & Donut Tray
19C-2 HN Stripper Valve Trays (6 Nos.)
19C-3 LCO Stripper Valve Trays (6 Nos.)
20C-1 Primary Absorber Valve Trays (36 Nos.)
20C-2 Sponge Absorber Valve Trays (20 Nos.)
20C-3 Stripper High Capacity Trays (30 Nos.)
20C-4 Debutanizer I Valve Trays (36 Nos.)
20C-205 Debutanizer II Valve Trays (48 Nos.)
20C-6 Amine Absorber High Capacity Trays (20 Nos.)
24NC-201 LPG Amine Absorber Valve Trays (14 Nos.)
20C-107 Gasoline Splitter High Capacity Trays (72 Nos. Dual Pass)
20C-108 Sponge Absorber High Capacity Trays (15 Nos.)
START UP OF CRITICAL EQUIPMENT
Main Air Blower (MAB)
1. ENSURE T&T VALVE IS CLOSE (19ZSL0222). ANTISURGE VALVE FULLY OPEN (19ZSH0202).
2. TURBINE & T&T DRAINS TO BE KEPT OPENED (WEST SIDE 2 NOS., EAST SIDE 3 NOS.)
3. AFTER ADEQUATE WARM UP, OPEN HP STEAM B/V. HP STEAM TEMP & PRESSURE ATLEAST 390 DEG C
& 58 KG/CM2. KEEP VENT B/V TO SILENCER OPEN.
4. CHECK HEATER START PERMISSIVE, START CONSOLE HEATER
5. ENUSRE BARRIER SEAL AIR SUPPLY PRESSURE > 1 KG/CM2 AT LOCAL P.G. D/S OF PCV
6. CHECK LOP START PERMISSIVE. START LUBE OIL PUMP. KEEP LUBE OIL TEMP ~ 45 DEG C. TAKE LEVEL
IN O/H DRUM. OIL MUST OVERFLOW FROM O/H TANK. CLOSE BYPASS LINE TO O/H TANK
7. LOCK IN TURNING GEAR PLATE & AFTER TURNING GEAR MOTOR START PERMISSIVE IS HEALTHY,
START TURNING GEAR MOTOR. ENSURE ROTATION OF SHAFT.
8. TAKE MAKE UP WATER. ENSURE CEP START PERMISSIVE HEALTHY. START CEP & MAINTAIN
CONDENSER LEVEL.
9. CLOSE VACCUM BREAKER SDV U/S B/V
10. LINE UP STEAM TO HOGGER, THEN OPEN SURFACE CONDENSER TO EJECTOR SUCTION VALVE.
11. LINE UP STEAM TO PRIMARY & SECONDARY EJECTOR. LINE UP SURFACE CONDENSER TO EJECTOR
VALVES. ENSURE HEALTHY VACUUM (-0.88 Kg/cm2).
12. OPEN GLAND STEAM DRAINS. DO NOT OPEN B/Vs.
13. STOP TURNING GEAR MOTOR, LOCK OUT PLATE.
75
Main Air Blower (MAB)
1. ENSURE T&T VALVE IS CLOSE (19ZSL0222). ANTISURGE VALVE FULLY OPEN (19ZSH0202).
2. TURBINE & T&T DRAINS TO BE KEPT OPENED (WEST SIDE 2 NOS., EAST SIDE 3 NOS.)
3. AFTER ADEQUATE WARM UP, OPEN HP STEAM B/V. HP STEAM TEMP & PRESSURE ATLEAST 390 DEG C
& 58 KG/CM2. KEEP VENT B/V TO SILENCER OPEN.
4. CHECK HEATER START PERMISSIVE, START CONSOLE HEATER
5. ENUSRE BARRIER SEAL AIR SUPPLY PRESSURE > 1 KG/CM2 AT LOCAL P.G. D/S OF PCV
6. CHECK LOP START PERMISSIVE. START LUBE OIL PUMP. KEEP LUBE OIL TEMP ~ 45 DEG C. TAKE LEVEL
IN O/H DRUM. OIL MUST OVERFLOW FROM O/H TANK. CLOSE BYPASS LINE TO O/H TANK
7. LOCK IN TURNING GEAR PLATE & AFTER TURNING GEAR MOTOR START PERMISSIVE IS HEALTHY,
START TURNING GEAR MOTOR. ENSURE ROTATION OF SHAFT.
8. TAKE MAKE UP WATER. ENSURE CEP START PERMISSIVE HEALTHY. START CEP & MAINTAIN
CONDENSER LEVEL.
9. CLOSE VACCUM BREAKER SDV U/S B/V
10. LINE UP STEAM TO HOGGER, THEN OPEN SURFACE CONDENSER TO EJECTOR SUCTION VALVE.
11. LINE UP STEAM TO PRIMARY & SECONDARY EJECTOR. LINE UP SURFACE CONDENSER TO EJECTOR
VALVES. ENSURE HEALTHY VACUUM (-0.88 Kg/cm2).
12. OPEN GLAND STEAM DRAINS. DO NOT OPEN B/Vs.
13. STOP TURNING GEAR MOTOR, LOCK OUT PLATE.
75
14. PRESS TRIP RESET BUTTON AT LOCAL CONTROL PANEL. KEEP BUTTON PRESSED FOR SOMETIME.
15. CONTROL OIL PRESSURE WILL INCREASE TO ~ 9.5 AFTER TRIP RESET. CHECK OIL SUPPLY LINE FOR
ANY PRESSURE SHOCK/VIBRATION. VACUUM BREAKER VALVE WILL CLOSE
16. ENSURE STATOR VANE CLOSE AT BOTH PERFORMANCE CONTROLLER & FIELD (19ZSL0201), LUBE OIL
RUN DOWN TANK LEVEL (19LSL0221-21%) OK, LUBE OIL SUPPLY TEMPERATURE
(19TSH0228/19TSL0228->38
0C), PRESSURE (19PSL0224->0.92 KG/CM2) OK, CONTROL OIL SUPPLY
PRESSURE (19PSL0233>7.1 KG/CM2) OK, T&T VALVE CLOSE (19ZSL0222), ONLINE TESTING VALVE
POSITON FOR TRIP SOLENOID VALVE OPEN (19ZSH0245A/B), TRIP SOLENOID VALVE CLOSE
(19ZSL0246A/B), TURNING GEAR LOCK OUT POSITION (19ZS0232), VACUUM BREAKER VALVE CLOSE
(19ZSL0225), TURBINE LOCAL TRIP BUTTON CLOSE (19ZSL0247), PROCESS COMMON START PERMISSIVE
(19XS0296). SOME OF THESE FEEDBACK INDICATIONS MAY HAVE TO BE FORCED BY I/M DUE TO
INDICATION PROBLEM.
17. START PERMISSIVE LAMP WILL BE ON AFTER SUCCESSFUL TRIP REST
18. KEEP SWITCH IN IDLE POSITION AT LOCAL CONTROL PANEL (NOT TO BE KEPT IN RATED)
19. PRESS GOV NORMAL RUN BUTTON
20. OPEN T&T VALVE SLOWLY & INCREASE RPM UP TO 600 RPM (1ST LOW IDLE SPEED). HOLDING TIME
10 MIN (COLD) / 10 MIN (HOT) START UP. HOT START UP MEANS TURBINE START WITHIN 4 HRS. FROM
SHUT DOWN.
21. OPEN GLAND STEAM B/V & MAIN TAIN PR. 0.21 KG/CM2. OPEN GLAND CONDENSER EJECTOR B/V.
THROTTLE STEAM VALVE. MAINTAIN VACUUM -0.12 KG/CM2
22. GRADUALLY START CLOSING DRAINS, REDUCE HP STEAM VENT
23. MAINTAINING VACUUM HEALTHY, CLOSE SURFACE CONDENSER TO HOGGER B/V
24. INCREASE RPM @ 10 RPM PER SECOND UPTO 2200 RPM (2ND LOW IDLE SPEED) BY OPENING T&T
VALVE. HOLDING TIME 50 MIN (COLD) / 10 MIN (HOT) START UP
76
15. CONTROL OIL PRESSURE WILL INCREASE TO ~ 9.5 AFTER TRIP RESET. CHECK OIL SUPPLY LINE FOR
ANY PRESSURE SHOCK/VIBRATION. VACUUM BREAKER VALVE WILL CLOSE
16. ENSURE STATOR VANE CLOSE AT BOTH PERFORMANCE CONTROLLER & FIELD (19ZSL0201), LUBE OIL
RUN DOWN TANK LEVEL (19LSL0221-21%) OK, LUBE OIL SUPPLY TEMPERATURE
(19TSH0228/19TSL0228->38
0C), PRESSURE (19PSL0224->0.92 KG/CM2) OK, CONTROL OIL SUPPLY
PRESSURE (19PSL0233>7.1 KG/CM2) OK, T&T VALVE CLOSE (19ZSL0222), ONLINE TESTING VALVE
POSITON FOR TRIP SOLENOID VALVE OPEN (19ZSH0245A/B), TRIP SOLENOID VALVE CLOSE
(19ZSL0246A/B), TURNING GEAR LOCK OUT POSITION (19ZS0232), VACUUM BREAKER VALVE CLOSE
(19ZSL0225), TURBINE LOCAL TRIP BUTTON CLOSE (19ZSL0247), PROCESS COMMON START PERMISSIVE
(19XS0296). SOME OF THESE FEEDBACK INDICATIONS MAY HAVE TO BE FORCED BY I/M DUE TO
INDICATION PROBLEM.
17. START PERMISSIVE LAMP WILL BE ON AFTER SUCCESSFUL TRIP REST
18. KEEP SWITCH IN IDLE POSITION AT LOCAL CONTROL PANEL (NOT TO BE KEPT IN RATED)
19. PRESS GOV NORMAL RUN BUTTON
20. OPEN T&T VALVE SLOWLY & INCREASE RPM UP TO 600 RPM (1ST LOW IDLE SPEED). HOLDING TIME
10 MIN (COLD) / 10 MIN (HOT) START UP. HOT START UP MEANS TURBINE START WITHIN 4 HRS. FROM
SHUT DOWN.
21. OPEN GLAND STEAM B/V & MAIN TAIN PR. 0.21 KG/CM2. OPEN GLAND CONDENSER EJECTOR B/V.
THROTTLE STEAM VALVE. MAINTAIN VACUUM -0.12 KG/CM2
22. GRADUALLY START CLOSING DRAINS, REDUCE HP STEAM VENT
23. MAINTAINING VACUUM HEALTHY, CLOSE SURFACE CONDENSER TO HOGGER B/V
24. INCREASE RPM @ 10 RPM PER SECOND UPTO 2200 RPM (2ND LOW IDLE SPEED) BY OPENING T&T
VALVE. HOLDING TIME 50 MIN (COLD) / 10 MIN (HOT) START UP
76
25. KEEP SWITCH IDLE TO RATED AT LOCAL CONTROL PANEL .
26. INCREASE RPM @ 60 RPM PER SECOND UPTO 5100 RPM (1ST HIGH IDLE SPEED) BY OPENING T&T
VALVE. CROSS CRITICAL BAND- 2700-4600 RPM. HOLDING TIME 30 MIN (COLD) / 17 MIN (HOT) START
UP
27. OPEN T&T VALVE FULLY TO REACH MIN. GOV. SPEED 6039 RPM. GOVERNOR WILL NOW CONTROL
SPEED WITH T&T FULLY OPEN.
Wet Gas Compressor (WGC)
1. OPEN HP STEAM WARM UP B/V & VENT THRU SILENCER & LOCAL DRAIN TO RAISE TEMP ~390
0C,
PR. 58 KG/CM
2
2. 2ND STG DISCH. MOV SHOULD BE CLOSE
3. LOP TO BE STARTED ONCE BARRIER SEAL AIR PR. (PT7238)>1.5 KG/CM2
4. START CEP, OPEN DMW MAKE UP IF REQD.
5. START BARRING MOTOR AFTER GEAR ENGAGE (CHECK LAMP INDICATION AT LCP)
6. OPEN HP TO MP LINE & LINE UP 20PIC7336 C/V. IF REQD, OPEN C/V BYPASS & MAINTAIN 12.5
KG/CM2 PR. TAKE START UP EJECTOR IN LINE & TAKE VACUUM.
7. WGC SEAL - KEEP FOLLOWING PARAMETERS :
A). PRIMARY SEAL PRESSURE (20PT226A/B/C) >1.5 KG/CM2 (0.2 KG MORE THAN 19V-105 PR.)
B). SECONDARY SEAL GAS PR. - PRIMARY VENT TO FLARE DELTA-P (PDI7234,35) = 0.1 - 0.6 (ADJUST SEC.
SEAL NEEDLE VALVE IF REQD.)
C) SEC. SEAL GAS PR. D/S OF PCV (PI7240) <2.5 Kg/cm2
D) SEC. SEAL GAS PR. U/S OF FLOW METER (PI7242,43) = (0.8-1.5 KG/CM2) 77
26. INCREASE RPM @ 60 RPM PER SECOND UPTO 5100 RPM (1ST HIGH IDLE SPEED) BY OPENING T&T
VALVE. CROSS CRITICAL BAND- 2700-4600 RPM. HOLDING TIME 30 MIN (COLD) / 17 MIN (HOT) START
UP
27. OPEN T&T VALVE FULLY TO REACH MIN. GOV. SPEED 6039 RPM. GOVERNOR WILL NOW CONTROL
SPEED WITH T&T FULLY OPEN.
Wet Gas Compressor (WGC)
1. OPEN HP STEAM WARM UP B/V & VENT THRU SILENCER & LOCAL DRAIN TO RAISE TEMP ~390
0C,
PR. 58 KG/CM
2
2. 2ND STG DISCH. MOV SHOULD BE CLOSE
3. LOP TO BE STARTED ONCE BARRIER SEAL AIR PR. (PT7238)>1.5 KG/CM2
4. START CEP, OPEN DMW MAKE UP IF REQD.
5. START BARRING MOTOR AFTER GEAR ENGAGE (CHECK LAMP INDICATION AT LCP)
6. OPEN HP TO MP LINE & LINE UP 20PIC7336 C/V. IF REQD, OPEN C/V BYPASS & MAINTAIN 12.5
KG/CM2 PR. TAKE START UP EJECTOR IN LINE & TAKE VACUUM.
7. WGC SEAL - KEEP FOLLOWING PARAMETERS :
A). PRIMARY SEAL PRESSURE (20PT226A/B/C) >1.5 KG/CM2 (0.2 KG MORE THAN 19V-105 PR.)
B). SECONDARY SEAL GAS PR. - PRIMARY VENT TO FLARE DELTA-P (PDI7234,35) = 0.1 - 0.6 (ADJUST SEC.
SEAL NEEDLE VALVE IF REQD.)
C) SEC. SEAL GAS PR. D/S OF PCV (PI7240) <2.5 Kg/cm2
D) SEC. SEAL GAS PR. U/S OF FLOW METER (PI7242,43) = (0.8-1.5 KG/CM2) 77
E). BARRIER SEAL PR. D/S OF PCV & B/V (PI-7236,37) >0.4 KG/CM2 PREFERABLY 0.5-1.2 KG/CM2 E).
BARRIER SEAL FILTER DELTA-P (PDI7252) < 0.5 KG/CM2
F) PRI. SEAL VENT TO FLARE GAS PR. U/S OF R.O (PI7230,31) ~ 0.5,1.1 KG/CM2
G). PRI. SEAL GAS FILTER DELTA-P ~ 0.35 KG/CM2
H). PRI. SEAL GAS PR. - SEAL BALANCE LINE PR. ~ 0.35 KG/CM2
I). PRI. SEAL GAS PR. D/S OF FILTER (PI7227) > 2.0 KG/CM2
J). PRI. SEAL GAS PR. - SEAL BALANCE LINE PR. (PDT7223A) ~ 0.5-0.6 KG/CM2
8. TAKE PRI. & SEC. EJECTOR IN LINE
9. START SEALING STEAM 20PIC7328 @300-400 mmWC PR. KEEP 7328B C/V B/P IN 1 THREAD OPEN
CONDITION. IF REQD. OPEN PIC7328A C/V BYPASS.
10. OPEN MAIN HP STEAM B/V 2-3 THREAD
11. OPEN 1ST STG SUCTION MOV, 2ND STG SUCTION MOV, 1ST STG DISCH. MOV. ENSURE 2ND STG
DISCH. MOV CLOSE. ENSURE SPILL BACK C/Vs ARE IN LINE
12. OPEN COMPRESSOR CASING DRAIN & DRAIN LIQUID - IF ANY. NEVER OPEN CASING DRAIN &
SEAL DRAIN (4 NOS.) AT THE SAME TIME WHEN COMPRESSOR IS PRESSURIZED. THIS MAY INCREASE
PRI. SEAL VENT DELTA-P ABNORMALLY.
13. INCREASE SEALING STEAM PR. TO 1100-1200 mmWC. OPEN PIC7328B C/V & ITS BYPASS (1-2
THREAD)
14. DISENGAGE BARRING, MOTOR SHOULD STOP AFTER 30 SEC. ENSURE BARRING PISTON AT
BOTTOM (I.E. DISENGAGE).CHECK START PERMISSIVE & TRIP RESET WGC. CHECK WITH PANEL FOR
OPENING SOVs. CHECK HAND LEVER.
15. RESET AT BENTLEY AT LCP, REST AT WOODWARD, KEEP SPILLBACK IN LOCAL 100% OPEN, KEEP
PIC0203 0% IN PERFORMANCE CONTROLLER.
16. AFTER TRIP RESET, OPEN START UP DEVICE ANTICLOCKWISE SLOWLY TO OPEN ESV.
78
BARRIER SEAL FILTER DELTA-P (PDI7252) < 0.5 KG/CM2
F) PRI. SEAL VENT TO FLARE GAS PR. U/S OF R.O (PI7230,31) ~ 0.5,1.1 KG/CM2
G). PRI. SEAL GAS FILTER DELTA-P ~ 0.35 KG/CM2
H). PRI. SEAL GAS PR. - SEAL BALANCE LINE PR. ~ 0.35 KG/CM2
I). PRI. SEAL GAS PR. D/S OF FILTER (PI7227) > 2.0 KG/CM2
J). PRI. SEAL GAS PR. - SEAL BALANCE LINE PR. (PDT7223A) ~ 0.5-0.6 KG/CM2
8. TAKE PRI. & SEC. EJECTOR IN LINE
9. START SEALING STEAM 20PIC7328 @300-400 mmWC PR. KEEP 7328B C/V B/P IN 1 THREAD OPEN
CONDITION. IF REQD. OPEN PIC7328A C/V BYPASS.
10. OPEN MAIN HP STEAM B/V 2-3 THREAD
11. OPEN 1ST STG SUCTION MOV, 2ND STG SUCTION MOV, 1ST STG DISCH. MOV. ENSURE 2ND STG
DISCH. MOV CLOSE. ENSURE SPILL BACK C/Vs ARE IN LINE
12. OPEN COMPRESSOR CASING DRAIN & DRAIN LIQUID - IF ANY. NEVER OPEN CASING DRAIN &
SEAL DRAIN (4 NOS.) AT THE SAME TIME WHEN COMPRESSOR IS PRESSURIZED. THIS MAY INCREASE
PRI. SEAL VENT DELTA-P ABNORMALLY.
13. INCREASE SEALING STEAM PR. TO 1100-1200 mmWC. OPEN PIC7328B C/V & ITS BYPASS (1-2
THREAD)
14. DISENGAGE BARRING, MOTOR SHOULD STOP AFTER 30 SEC. ENSURE BARRING PISTON AT
BOTTOM (I.E. DISENGAGE).CHECK START PERMISSIVE & TRIP RESET WGC. CHECK WITH PANEL FOR
OPENING SOVs. CHECK HAND LEVER.
15. RESET AT BENTLEY AT LCP, REST AT WOODWARD, KEEP SPILLBACK IN LOCAL 100% OPEN, KEEP
PIC0203 0% IN PERFORMANCE CONTROLLER.
16. AFTER TRIP RESET, OPEN START UP DEVICE ANTICLOCKWISE SLOWLY TO OPEN ESV.
78
17. GIVE GOV. RUN SIGNAL FROM WOODWARD PANEL.
18. OPEN GLAND STEAM TO GLAND EJECTOR. KEEP GLAND CONDENSER B/V 3-4 THREAD OPEN.
19. OPEN HP MAIN B/V FULLY & CLOSE VENT & DRAIN B/V WHEN RPM IS 2000 (1ST HALT). PRESS
HALT AT WOODWARD GOV. PANEL FOR RPM HALT. HOLDING TIME 15 MIN (COLD), 6 MIN (HOT) START
UP.
20. AT 6000 RPM (2 ND HALT)CLOSE DMW MAKE UP COMPLETELY. ADJUST PIC7328A TO MAINTAIN
SEALING STEAM. KEEP PIC7328B >80% OPEN WITH B/P B/V ALSO OPEN (~2 THREAD). HOLDING TIME
10 MIN (COLD). NO HALT DURING HOT START UP. CRITICAL BAND 2800-3500, 4000-5000
21. GO TO MINIMUM GOVERNOR SPEED (6132)
22. OPEN 2ND STAGE DISCHARGE MOV & LOAD WGC.
23. WGC LOADING:- AT MIN. GOV. SPEED KEEP WOODWARD PANEL AT "REMOTE ENABLE" POSITION.
ENSURE DCS SS-7526 IN "DCS SEL" MODE. ALSO PUT 20SS6901 IN DCS IN "REMOTE". THIS WILL
ENABLE RPM CHANGE (020_HIC7526) FROM DCS. ENSURE BUMP LESS TRANSFER. AFTER THAT KEEP
SS-7526 EITHER IN DCS OR PERFORMANCE CONTROLLER. IF SS-7526 IS SELECTED IN "DCS" MODE,
RPM SET POINT TO BE GIVEN IN 20_HIC7526. INITIALLI KEEP SS-7526 IN “DCS” & CONTROL 19V-105
PRESSURE BY GIVING RPM SET POINT AT 020_HIC7526. PUT ANTISURGE CONTROLLERS UC-6601 &
UC6602 IN AUTO IN PERF. CONTROLLER PANEL & USE 020_HIC6601 & 020_HIC6602 (ANTISURGE
LOCK) IN DCS TO CONTROL ANTISURGE OPENING. ONCE 19V-105 PRESSURE IS STABLE, PUT SS-7526
IN "PERFM SEL". 20PT203 PRESSURE WILL GOVERN WGC RPM. 20PT0203 SET POINT CAN BE
CHANGED AT PERFORMANCE CONTROLLER PANEL. 20PT0203 CAN BE SELECTED ON AUTO OR
MANUAL MODE AT PERFM. CONTROLLER PANEL. KEEP 020PT203 IN AUTO.
79
18. OPEN GLAND STEAM TO GLAND EJECTOR. KEEP GLAND CONDENSER B/V 3-4 THREAD OPEN.
19. OPEN HP MAIN B/V FULLY & CLOSE VENT & DRAIN B/V WHEN RPM IS 2000 (1ST HALT). PRESS
HALT AT WOODWARD GOV. PANEL FOR RPM HALT. HOLDING TIME 15 MIN (COLD), 6 MIN (HOT) START
UP.
20. AT 6000 RPM (2 ND HALT)CLOSE DMW MAKE UP COMPLETELY. ADJUST PIC7328A TO MAINTAIN
SEALING STEAM. KEEP PIC7328B >80% OPEN WITH B/P B/V ALSO OPEN (~2 THREAD). HOLDING TIME
10 MIN (COLD). NO HALT DURING HOT START UP. CRITICAL BAND 2800-3500, 4000-5000
21. GO TO MINIMUM GOVERNOR SPEED (6132)
22. OPEN 2ND STAGE DISCHARGE MOV & LOAD WGC.
23. WGC LOADING:- AT MIN. GOV. SPEED KEEP WOODWARD PANEL AT "REMOTE ENABLE" POSITION.
ENSURE DCS SS-7526 IN "DCS SEL" MODE. ALSO PUT 20SS6901 IN DCS IN "REMOTE". THIS WILL
ENABLE RPM CHANGE (020_HIC7526) FROM DCS. ENSURE BUMP LESS TRANSFER. AFTER THAT KEEP
SS-7526 EITHER IN DCS OR PERFORMANCE CONTROLLER. IF SS-7526 IS SELECTED IN "DCS" MODE,
RPM SET POINT TO BE GIVEN IN 20_HIC7526. INITIALLI KEEP SS-7526 IN “DCS” & CONTROL 19V-105
PRESSURE BY GIVING RPM SET POINT AT 020_HIC7526. PUT ANTISURGE CONTROLLERS UC-6601 &
UC6602 IN AUTO IN PERF. CONTROLLER PANEL & USE 020_HIC6601 & 020_HIC6602 (ANTISURGE
LOCK) IN DCS TO CONTROL ANTISURGE OPENING. ONCE 19V-105 PRESSURE IS STABLE, PUT SS-7526
IN "PERFM SEL". 20PT203 PRESSURE WILL GOVERN WGC RPM. 20PT0203 SET POINT CAN BE
CHANGED AT PERFORMANCE CONTROLLER PANEL. 20PT0203 CAN BE SELECTED ON AUTO OR
MANUAL MODE AT PERFM. CONTROLLER PANEL. KEEP 020PT203 IN AUTO.
79
CHECKLIST FOR HANDING OVER OF 19P103A/B TO MECHANICAL MAINTENANCE
SL
No.
CHECK POINTS OBSERVATION TIME SIGN OF
OPERATOR
SIGN OF
SHIFT
OFFICER
01 Suction block valve is isolated
02 Discharge block valve is
isolated
03 HCO flushing line is isolated
04 Pump warm up line isolate
05 Steam Flushing line is isolated
06 Naturally cooled for 4-5 hours
07 Service water running hose is
kept at drain point
08 Draining is started through
casing drain valve at bottom
09 Pump is totally depressurised
10 Pump is handed over
80
SL
No.
CHECK POINTS OBSERVATION TIME SIGN OF
OPERATOR
SIGN OF
SHIFT
OFFICER
01 Suction block valve is isolated
02 Discharge block valve is
isolated
03 HCO flushing line is isolated
04 Pump warm up line isolate
05 Steam Flushing line is isolated
06 Naturally cooled for 4-5 hours
07 Service water running hose is
kept at drain point
08 Draining is started through
casing drain valve at bottom
09 Pump is totally depressurised
10 Pump is handed over
80
CHECKLIST FOR TAKING 19P103A/B ON LINE AFTER MAINTENANCE
SL
No.
CHECK POINTS OBSERVATION TIME SIGN OF
OPERATOR
SIGN OF
SHIFT
OFFICER
01 Pump suction line is flushed after
strainer opening
02 Steam to pump suction line is lined
up to drain
03 Line up Plan 32 (HCO flushing line )
but ensure FLO & HCO B/Vs are
closed
04 Line up FLO to Plan 32. Keep casing
local drain open. Start FLO & drain
condensate (if any). Then close
drain B/V, open casing vent B/V &
start FLO @ 1GPM & increase
slowly up to 4GPM.
05 Pump casing vent to local drain is
closed after FLO comes out
through casing vent
06 Keep pump suction line vent lined
up to local drain (near MCB sample
point).
07 Slowly open HCO to pump seal &
reduce FLO. Casing warm up to be
done @ 65
0
C/hr. Keep flushing oil
flow < 5 GPM
08 At 230
0
C keep flushing oil (HCO)
flow 5-6 GPM
09 Keep 6-7 GPM HCO flushing oil
flow when casing temp >300
0
C
10 Close suction drain after steam
flushing
11 Ensure HCO to seal flushing flow >
6 GPM
12 Open Steam flushing line (Plan 62)
13 Ensure bearing housing & seal pot
CW flow
14 Ensure seal pot level is healthy
(Plan 52)
15 After informing DCS operator Open
suction valve. Watch running pump
16 Open pump casing vent to 19C-1
Note: Pump casing & impeller should never be exposed to warm oil that has a temperature differential of more than 65
0
C 81
SL
No.
CHECK POINTS OBSERVATION TIME SIGN OF
OPERATOR
SIGN OF
SHIFT
OFFICER
01 Pump suction line is flushed after
strainer opening
02 Steam to pump suction line is lined
up to drain
03 Line up Plan 32 (HCO flushing line )
but ensure FLO & HCO B/Vs are
closed
04 Line up FLO to Plan 32. Keep casing
local drain open. Start FLO & drain
condensate (if any). Then close
drain B/V, open casing vent B/V &
start FLO @ 1GPM & increase
slowly up to 4GPM.
05 Pump casing vent to local drain is
closed after FLO comes out
through casing vent
06 Keep pump suction line vent lined
up to local drain (near MCB sample
point).
07 Slowly open HCO to pump seal &
reduce FLO. Casing warm up to be
done @ 65
0
C/hr. Keep flushing oil
flow < 5 GPM
08 At 230
0
C keep flushing oil (HCO)
flow 5-6 GPM
09 Keep 6-7 GPM HCO flushing oil
flow when casing temp >300
0
C
10 Close suction drain after steam
flushing
11 Ensure HCO to seal flushing flow >
6 GPM
12 Open Steam flushing line (Plan 62)
13 Ensure bearing housing & seal pot
CW flow
14 Ensure seal pot level is healthy
(Plan 52)
15 After informing DCS operator Open
suction valve. Watch running pump
16 Open pump casing vent to 19C-1
Note: Pump casing & impeller should never be exposed to warm oil that has a temperature differential of more than 65
0
C 81
CHECKLIST FOR HANDING OVER OF WGC L.O. FILTER TO MAINTENANCE
SL
No.
CHECK POINTS OBSERVATION TIME SIGN OF
OPERATOR
SIGN OF
SHIFT
OFFICER
01 Ensure filter vent B/Vs (2 nos.) are
isolated
02 Ensure filling line B/V is isolated
03 Inform Panel & crack open filter
drain B/V. Keep watching nearby
L.O. header PG. If drain oil pressure
is low open B/V fully. Also open
inlet line drain B/V
04 Ensure running filter vent line B/Vs
are in closed condition (To ensure
no fluctuation during running filter
vent line flange opening)
Note : During filter cleaning running filter vent flange (D/S of 1
st
B/V) has to be opened by
maintenance. Ensure running filter vent B/Vs are closed. Ensure no oil leakage during flange
opening.
82
SL
No.
CHECK POINTS OBSERVATION TIME SIGN OF
OPERATOR
SIGN OF
SHIFT
OFFICER
01 Ensure filter vent B/Vs (2 nos.) are
isolated
02 Ensure filling line B/V is isolated
03 Inform Panel & crack open filter
drain B/V. Keep watching nearby
L.O. header PG. If drain oil pressure
is low open B/V fully. Also open
inlet line drain B/V
04 Ensure running filter vent line B/Vs
are in closed condition (To ensure
no fluctuation during running filter
vent line flange opening)
Note : During filter cleaning running filter vent flange (D/S of 1
st
B/V) has to be opened by
maintenance. Ensure running filter vent B/Vs are closed. Ensure no oil leakage during flange
opening.
82
CHECKLIST FOR TAKING OVER WGC L.O. FILTER ON LINE
SL
No.
CHECK POINTS OBSERVATION TIME SIGN OF
OPERATOR
SIGN OF
SHIFT
OFFICER
01 Inform FCCU panel
02 Ensure standby filter drains are in
closed position
03 Open standby filter vent B/Vs (2
nos.) slowly. Open filling B/V.
04 Continue air venting to console for
at least 5 mins. Ensure air/oil flow
in vent line gauge glass
05 Close vent B/Vs
06 After informing DCS, change filter
by operating 3 way B/V lever
(towards east side or west side).
07 Inform DCS about completion of
filter C/O
Note: After filter C/O both control oil pressure & trip oil pressure may come down slightly
due to low delta-P across new filter.
83
SL
No.
CHECK POINTS OBSERVATION TIME SIGN OF
OPERATOR
SIGN OF
SHIFT
OFFICER
01 Inform FCCU panel
02 Ensure standby filter drains are in
closed position
03 Open standby filter vent B/Vs (2
nos.) slowly. Open filling B/V.
04 Continue air venting to console for
at least 5 mins. Ensure air/oil flow
in vent line gauge glass
05 Close vent B/Vs
06 After informing DCS, change filter
by operating 3 way B/V lever
(towards east side or west side).
07 Inform DCS about completion of
filter C/O
Note: After filter C/O both control oil pressure & trip oil pressure may come down slightly
due to low delta-P across new filter.
83
VAPOUR LINE BLIND CHECK LIST
STOP FEED PUMP AFTER LOWERING 19-V-4 LEVEL TO MINIMUM.
STOP 19P3 AFTER PUMP LOOSING THE SUCTION. ISOLATE FLO TO 19P3 GLAND, LT, LG, AND FLOW
TRANSMITTERS.
WAIT FOR AROUND 15-20 MINUTES AND FOR ANY INCREASE IN LEVEL OF COLUMN. IN CASE OF LEVEL
INCREASE DUE TO DRAINING FROM INSIDE THE COLUMN, EMPTY OUT IT AGAIN. ISOLATE B/VS TO 19E-21 &
19E-D AT 19P-3 DISCHARGE MANIFOLD.
STOP GAS BACK UP TO 19C-2.
ISOLATE 20LCV-44, 20LC-65
TRC & LRC SLIDE VALVES SHOULD BE TIGHTLY SHUT ON HAND WHEEL.
INFORM FIRE AND SAFETY TO BE PRESENT WITH FIRE TENDER BEFORE THE EXECUTION OF THE JOB
CHARGE STEAM INTO THE MAIN FRACTIONATOR SIDE STRIPPERS AND ESTABLISH STEAM PURGE IN 19C-1
BOTTOM USING THE TRY LINES.
OPEN 19PIC-202 FULLY TO DE-PRESSURIZE MAIN COLUMN 19C-1 TO FLARE. KEEP OPEN 19PIC-202 (NOTE
19PIC202 VALVE IS NOT BEING CLOSED AS NRV IS PROVIDED TO PREVENT BACKFLOW OF OTHER UNIT FLARE
RELEASE TO FCCU FLARE HEADER.
ISOLATES STEAM TO STRUCTURE B/VS AT PIPE RACK
STOP MAB BY REDUCING RPM SLOWLY
CHECK WIND DIRECTION AND ACCORDINGLY PLACE THE WORKING PEOPLE FOR JOB. AIR HOSE MUST BE ON.
REDUCE RISER STEAM TO MINIMUM. JUST BEFORE OPENING FLANGE ISOLATE RISER STEAM. CLOSE STEAM TO
19C-2 & 19C-3 C/VS. SLIGHT AMOUNT OF STEAM SHOULD GO THROUGH COLUMN BOTTOM TRY LINE
AFTER VAPOR LINE BLIND & WARM UP LINE DEBLIND, OPEN WARM UP LINE, INCREASE STEAM TO RISER AT
ABOVE RATE, START MAB FOR CATALYST UNLOADING & REGENERATOR COOLING. CONTINUE COOLING THE
REGENERATOR USING MAB. TAKE FG IN 19C-1.
84
STOP FEED PUMP AFTER LOWERING 19-V-4 LEVEL TO MINIMUM.
STOP 19P3 AFTER PUMP LOOSING THE SUCTION. ISOLATE FLO TO 19P3 GLAND, LT, LG, AND FLOW
TRANSMITTERS.
WAIT FOR AROUND 15-20 MINUTES AND FOR ANY INCREASE IN LEVEL OF COLUMN. IN CASE OF LEVEL
INCREASE DUE TO DRAINING FROM INSIDE THE COLUMN, EMPTY OUT IT AGAIN. ISOLATE B/VS TO 19E-21 &
19E-D AT 19P-3 DISCHARGE MANIFOLD.
STOP GAS BACK UP TO 19C-2.
ISOLATE 20LCV-44, 20LC-65
TRC & LRC SLIDE VALVES SHOULD BE TIGHTLY SHUT ON HAND WHEEL.
INFORM FIRE AND SAFETY TO BE PRESENT WITH FIRE TENDER BEFORE THE EXECUTION OF THE JOB
CHARGE STEAM INTO THE MAIN FRACTIONATOR SIDE STRIPPERS AND ESTABLISH STEAM PURGE IN 19C-1
BOTTOM USING THE TRY LINES.
OPEN 19PIC-202 FULLY TO DE-PRESSURIZE MAIN COLUMN 19C-1 TO FLARE. KEEP OPEN 19PIC-202 (NOTE
19PIC202 VALVE IS NOT BEING CLOSED AS NRV IS PROVIDED TO PREVENT BACKFLOW OF OTHER UNIT FLARE
RELEASE TO FCCU FLARE HEADER.
ISOLATES STEAM TO STRUCTURE B/VS AT PIPE RACK
STOP MAB BY REDUCING RPM SLOWLY
CHECK WIND DIRECTION AND ACCORDINGLY PLACE THE WORKING PEOPLE FOR JOB. AIR HOSE MUST BE ON.
REDUCE RISER STEAM TO MINIMUM. JUST BEFORE OPENING FLANGE ISOLATE RISER STEAM. CLOSE STEAM TO
19C-2 & 19C-3 C/VS. SLIGHT AMOUNT OF STEAM SHOULD GO THROUGH COLUMN BOTTOM TRY LINE
AFTER VAPOR LINE BLIND & WARM UP LINE DEBLIND, OPEN WARM UP LINE, INCREASE STEAM TO RISER AT
ABOVE RATE, START MAB FOR CATALYST UNLOADING & REGENERATOR COOLING. CONTINUE COOLING THE
REGENERATOR USING MAB. TAKE FG IN 19C-1.
84
VAPOUR LINE DEBLIND CHECK LIST
STOP REACTOR STEAMING (ALL STEAM VALVE TO BE CRACK OPENED)
STOP FG MAKE UP IN 19C2
ENSURE 20LIC44 AND ITS ISOLATION VALVES ARE CLOSED
ENSURE 20LIC65 AND ITS ISOLATION VALVES ARE CLOSED
WGC 2
ND
STAGE DISCHARGE AND BOTH SPILLBACK ISOLATION VALVES ARE CLOSED.
ENSURE 19 FRC213 AND ITS ISOLATION VALVES ARE CLOSED
FLOAT COLUMN WITH FLARE SYSTEM (ENSURE COLUMN PRESSURE INDICATION IS BELOW 0.1
KG/CM2).
EMPTY OUT MAIN COLUMN.
STOP STRIPPING STEAM TO LCO STRIPPER.
CRACK OPEN STRIPPING STEAM TO HEAVY NAPTHA STRIPPER
KEEP COLUMN UNDER PUFFING STEAM THROUGH TRY LINES
ENSURE VAPOUR LINE BLIND U/S AND D/S STEAM LINE & DRAIN LINE ARE OPENED AND PUFFING
STEAM FLOW IS ON.
85
STOP REACTOR STEAMING (ALL STEAM VALVE TO BE CRACK OPENED)
STOP FG MAKE UP IN 19C2
ENSURE 20LIC44 AND ITS ISOLATION VALVES ARE CLOSED
ENSURE 20LIC65 AND ITS ISOLATION VALVES ARE CLOSED
WGC 2
ND
STAGE DISCHARGE AND BOTH SPILLBACK ISOLATION VALVES ARE CLOSED.
ENSURE 19 FRC213 AND ITS ISOLATION VALVES ARE CLOSED
FLOAT COLUMN WITH FLARE SYSTEM (ENSURE COLUMN PRESSURE INDICATION IS BELOW 0.1
KG/CM2).
EMPTY OUT MAIN COLUMN.
STOP STRIPPING STEAM TO LCO STRIPPER.
CRACK OPEN STRIPPING STEAM TO HEAVY NAPTHA STRIPPER
KEEP COLUMN UNDER PUFFING STEAM THROUGH TRY LINES
ENSURE VAPOUR LINE BLIND U/S AND D/S STEAM LINE & DRAIN LINE ARE OPENED AND PUFFING
STEAM FLOW IS ON.
85
19F-3 (DFAH) LIGHT UP
19F-3 LIGHT UP AS PER BURNER MGMT SYSTEM:
LOCAL PANEL RESET SWITCH HS-0301 WILL INSERT IGNITER INSIDE 19F-2
PILOT GAS SDV (XV0302) WILL OPEN
IGNITER WILL GIVE SPARK FOR 20 SECONDS
FLAME DETECTOR WILL SENSE FLAME & OPEN MAIN FG SDV (XV0301) WITH OPEN C/V 19FIC0042
(10%). SINCE FLAME DETECTORS DO NOT WORK HENCE THIS SIGNAL IS FORCED AT THAT TIME & MAIN
FG SDV TO BE OPENED BY INSTRUMENT PERSON. THEN MAIN FG SDV D/S B/V TO BE OPENED & MAIN
GUN TO BE TAKEN IN LINE.
I-03 TO BE REMAINED IN BYPASSED CONDITION AS ONE OF THE INPUTS (FLAME DETECTORS) IS
UNHEALTHY
INCASE OF MAB TRIP OR ANY OTHER ABNORMALITY, I-03 TO BE TAKEN IN LINE FOR IMMEDIATE
CLOSING FG & PILOT SDVs (XV0301 & XV0302)
PROVIDED INTERLOCK I-03 IS IN LINE, IF DIFFERENCE BETWEEN FG/NG PRESSURE (19PI-0302) & MAB
DISCHARGE PRESSURE (19PI0301) IS LESS THAN 0.25 KG/CM
2
THEN FG PILOT GAS SDV (XV0302) &
MAIN GAS SDV (XV0301) WILL CLOSE & FIRING WILL CUT OFF AS PER INTERLOCK I-03.
86
19F-3 LIGHT UP AS PER BURNER MGMT SYSTEM:
LOCAL PANEL RESET SWITCH HS-0301 WILL INSERT IGNITER INSIDE 19F-2
PILOT GAS SDV (XV0302) WILL OPEN
IGNITER WILL GIVE SPARK FOR 20 SECONDS
FLAME DETECTOR WILL SENSE FLAME & OPEN MAIN FG SDV (XV0301) WITH OPEN C/V 19FIC0042
(10%). SINCE FLAME DETECTORS DO NOT WORK HENCE THIS SIGNAL IS FORCED AT THAT TIME & MAIN
FG SDV TO BE OPENED BY INSTRUMENT PERSON. THEN MAIN FG SDV D/S B/V TO BE OPENED & MAIN
GUN TO BE TAKEN IN LINE.
I-03 TO BE REMAINED IN BYPASSED CONDITION AS ONE OF THE INPUTS (FLAME DETECTORS) IS
UNHEALTHY
INCASE OF MAB TRIP OR ANY OTHER ABNORMALITY, I-03 TO BE TAKEN IN LINE FOR IMMEDIATE
CLOSING FG & PILOT SDVs (XV0301 & XV0302)
PROVIDED INTERLOCK I-03 IS IN LINE, IF DIFFERENCE BETWEEN FG/NG PRESSURE (19PI-0302) & MAB
DISCHARGE PRESSURE (19PI0301) IS LESS THAN 0.25 KG/CM
2
THEN FG PILOT GAS SDV (XV0302) &
MAIN GAS SDV (XV0301) WILL CLOSE & FIRING WILL CUT OFF AS PER INTERLOCK I-03.
86
CATALYST SAMPLING
IN FCCU, REGENERATED CATALYST SLIDE VALVE (RCSV) & SPENT CATALYST SLIDE VALVE (SCSV) ARE
CONFIGURED AS 19TV0502 & 19LV0061. THIS SLIDE VALVES ARE GOVERNED BY TWO CONTROLLERS BY
LSS (LOW SELECTOR SWITCH) PHILOSOPHY I.E THE SLIDE VALVE WILL FOLLOW THE LOWEST OUTPUT
OUT OF THE CONTROLLER.
DCS ACTIONS: CHANGE DIFFERENTIAL CONTROLLER 19DPIC0510 FROM AUTO TO MANUAL. CHANGE
19TIC0501 CONTROLLER MODE FROM AUTO TO MANUAL. CHANGE SLIDE VALVE 19TV0502 MODE
FROM CASCADE TO MANUAL.
AFTER CATALYST SAMPLE IS TAKEN & LINE UP NORMAL IN FIELD :- ENSURE DIFFERENTIAL CONTROLLER
19DPIC0510 VALUE IS MORE THAN 0.15 KG/CM
2
. IF IT IS LESS THAN 0.15 KG/CM
2
, ADJUST PLANT
CONDITIONS TO MAKE IT MORE THAN 0.15 KG/CM
2
. THEN CHANGE 19PDIC0510 MODE FROM MANUAL
TO AUTO AND GIVE SET POINT VALUE AS 0.15 KG/CM
2
. CONTROLLER OUTPUT WILL BECOME 100%.
CHECK & ENSURE 19TIC0501 OUTPUT & 19TV0502 VALVE OPENING (19ZI0502) SAME (DIFFERENCE IS
LESS THAN 3%). CHECK IN HMI PANEL FOR NO LOCK- IN PLACE. CHANGE SLIDE VALVE (19TV0502) MODE
FROM MANUAL TO CASCADE. PUT 19TIC0501 IN AUTO MODE.
REGENERATED CATALYST SAMPLING IN THE FIELD:-
AFTER CLEARANCE FROM PANEL, CLOSE STEAM B/V U/S OF R.O. FLANGE. CRACK OPEN SAMPLE POINT
B/V. START CATALYST DRAINING AT CONTROLLED RATE. COLLECT CATALYST IN THE METALLIC
CONTAINER. OPEN STEAM B/V U/S OF R.O. FLANGE. WAIT FOR STEAM/CONDENSATE FROM SAMPLE
POINT DRAIN LINE. WHEN CONTINUOUS STEAM APPEARS, THROTTLE SAMPLE POINT B/V. ENSURE
CONTINUOUS STEAM FROM DRAIN LINE.
FOLLOW SAME PROCEDURE FOR SPENT CATALYST SAMPLING.
NOTE : DURING NORMAL ROUND AT RX AREA, CHECK & ENSURE STEAM FROM CATALYST SAMPLE
POINT DRAIN LINE.
87
IN FCCU, REGENERATED CATALYST SLIDE VALVE (RCSV) & SPENT CATALYST SLIDE VALVE (SCSV) ARE
CONFIGURED AS 19TV0502 & 19LV0061. THIS SLIDE VALVES ARE GOVERNED BY TWO CONTROLLERS BY
LSS (LOW SELECTOR SWITCH) PHILOSOPHY I.E THE SLIDE VALVE WILL FOLLOW THE LOWEST OUTPUT
OUT OF THE CONTROLLER.
DCS ACTIONS: CHANGE DIFFERENTIAL CONTROLLER 19DPIC0510 FROM AUTO TO MANUAL. CHANGE
19TIC0501 CONTROLLER MODE FROM AUTO TO MANUAL. CHANGE SLIDE VALVE 19TV0502 MODE
FROM CASCADE TO MANUAL.
AFTER CATALYST SAMPLE IS TAKEN & LINE UP NORMAL IN FIELD :- ENSURE DIFFERENTIAL CONTROLLER
19DPIC0510 VALUE IS MORE THAN 0.15 KG/CM
2
. IF IT IS LESS THAN 0.15 KG/CM
2
, ADJUST PLANT
CONDITIONS TO MAKE IT MORE THAN 0.15 KG/CM
2
. THEN CHANGE 19PDIC0510 MODE FROM MANUAL
TO AUTO AND GIVE SET POINT VALUE AS 0.15 KG/CM
2
. CONTROLLER OUTPUT WILL BECOME 100%.
CHECK & ENSURE 19TIC0501 OUTPUT & 19TV0502 VALVE OPENING (19ZI0502) SAME (DIFFERENCE IS
LESS THAN 3%). CHECK IN HMI PANEL FOR NO LOCK- IN PLACE. CHANGE SLIDE VALVE (19TV0502) MODE
FROM MANUAL TO CASCADE. PUT 19TIC0501 IN AUTO MODE.
REGENERATED CATALYST SAMPLING IN THE FIELD:-
AFTER CLEARANCE FROM PANEL, CLOSE STEAM B/V U/S OF R.O. FLANGE. CRACK OPEN SAMPLE POINT
B/V. START CATALYST DRAINING AT CONTROLLED RATE. COLLECT CATALYST IN THE METALLIC
CONTAINER. OPEN STEAM B/V U/S OF R.O. FLANGE. WAIT FOR STEAM/CONDENSATE FROM SAMPLE
POINT DRAIN LINE. WHEN CONTINUOUS STEAM APPEARS, THROTTLE SAMPLE POINT B/V. ENSURE
CONTINUOUS STEAM FROM DRAIN LINE.
FOLLOW SAME PROCEDURE FOR SPENT CATALYST SAMPLING.
NOTE : DURING NORMAL ROUND AT RX AREA, CHECK & ENSURE STEAM FROM CATALYST SAMPLE
POINT DRAIN LINE.
87
PUMPS
11.0 DAILY ROUTINE CHECKS
Check bearing temperature.
Check motor ampere and sound, vibrations.
Check for pump discharge pressure.
Check lube oil /seal oil/bearing fluid level.
Checks for cooling water flow.
Check for seal quench steam/flushing oil flow.
Check for any leakage, special attention is to be given to 19P-3A/B, 19-106A/B, 19-108A/B, 19-
15A/B, 19-25A/B.
FURNANCE:
Check box condition inside furnace, flame length, color flame.
Check the condition of furnace coil for flame impingement & hot spot.
Check damper position, air register position, furnace draft, FG pressure, IFO pressure.
Check and ensure that furnace securities are in line.
Check furnace shell for hot spots.
Check O2 content in flue gases whenever burner firing is changed.
Rx-Rg-TSS:
Check for any catalyst leakage, inform immediately.
Check slide valve opening and cross check with control room readings.
Check & ensure slide valve stem purging lines are hot
Check & ensure stand pipe aeration rota meters are in line & showing values
Check & ensure slight steam flow at catalyst sample points drain lines at RCSV, SCSV.
Check stand pipes for any vibration, report immediately.
Check hydraulic pumps & HPU systems. Ensure pumps are running as primary & standby pumps
are in auto mode
88
11.0 DAILY ROUTINE CHECKS
Check bearing temperature.
Check motor ampere and sound, vibrations.
Check for pump discharge pressure.
Check lube oil /seal oil/bearing fluid level.
Checks for cooling water flow.
Check for seal quench steam/flushing oil flow.
Check for any leakage, special attention is to be given to 19P-3A/B, 19-106A/B, 19-108A/B, 19-
15A/B, 19-25A/B.
FURNANCE:
Check box condition inside furnace, flame length, color flame.
Check the condition of furnace coil for flame impingement & hot spot.
Check damper position, air register position, furnace draft, FG pressure, IFO pressure.
Check and ensure that furnace securities are in line.
Check furnace shell for hot spots.
Check O2 content in flue gases whenever burner firing is changed.
Rx-Rg-TSS:
Check for any catalyst leakage, inform immediately.
Check slide valve opening and cross check with control room readings.
Check & ensure slide valve stem purging lines are hot
Check & ensure stand pipe aeration rota meters are in line & showing values
Check & ensure slight steam flow at catalyst sample points drain lines at RCSV, SCSV.
Check stand pipes for any vibration, report immediately.
Check hydraulic pumps & HPU systems. Ensure pumps are running as primary & standby pumps
are in auto mode
88
Check slide valve hydraulic system (pumps, HV-1/2/3 lever position)
Check air/Nitrogen purge to Rx/Rg level and pressure instruments.
Check steam purge to torch oil guns.
Check TSS FDH air flow rota meters are in line & showing values
Check air booster operation (Booster operation should be intermittent)
Check FDH vent filter blow back solenoid valves opening
Check lift phone, alarms
AIR BLOWER & WET GAS COMPRESSER
Check lube oil console level
Check lube oil temp. (40-45 0C).
Check DP across lube oil filter & ensure availability of stand by filter.
Check lube oil pump discharge pressure and opening of PCV.
Check Lube oil O/H drum level (continuously over flowing).
Check seal gas DP in field and cross check with DCS reading. Check secondary seal pressure
Check standby lube oil pump, condensate pump are on remote at local control panel.
Check ejector system & surface condenser pressure.
Check HP, MP steam pressure & temp.
Check 19K-101 DP across suction hood, check anti surge & stator vane opening.
Check 19K-101 & 20K-201 vibration & axial displacement in LCR VMS.
Check 20V-210, 201 level in LG & cross check with level indication.
Ensure proper gland steam to turbine, barrier seal pressure in MAB/WGC.
OTHERS CHECKS:
All vessels & column transmitter (LT) reading to be cross checked with level gauge readings.
Interface level in boot drum 19V-105 & 20V-203 to be checked.
Check and transfer water from 20E-4 boot, 20V-9, 19V-23.
89
Check air/Nitrogen purge to Rx/Rg level and pressure instruments.
Check steam purge to torch oil guns.
Check TSS FDH air flow rota meters are in line & showing values
Check air booster operation (Booster operation should be intermittent)
Check FDH vent filter blow back solenoid valves opening
Check lift phone, alarms
AIR BLOWER & WET GAS COMPRESSER
Check lube oil console level
Check lube oil temp. (40-45 0C).
Check DP across lube oil filter & ensure availability of stand by filter.
Check lube oil pump discharge pressure and opening of PCV.
Check Lube oil O/H drum level (continuously over flowing).
Check seal gas DP in field and cross check with DCS reading. Check secondary seal pressure
Check standby lube oil pump, condensate pump are on remote at local control panel.
Check ejector system & surface condenser pressure.
Check HP, MP steam pressure & temp.
Check 19K-101 DP across suction hood, check anti surge & stator vane opening.
Check 19K-101 & 20K-201 vibration & axial displacement in LCR VMS.
Check 20V-210, 201 level in LG & cross check with level indication.
Ensure proper gland steam to turbine, barrier seal pressure in MAB/WGC.
OTHERS CHECKS:
All vessels & column transmitter (LT) reading to be cross checked with level gauge readings.
Interface level in boot drum 19V-105 & 20V-203 to be checked.
Check and transfer water from 20E-4 boot, 20V-9, 19V-23.
89
Check for passing of any drain of KOD.
Check air cooler sound & vibration.
Check colors of run down products.
Check all sample points.
Check injection rate of corrosion inhibitor.
Check exchangers for any leakage.
Check level of 19C-1 and cross check with try lines.
Check hanging support for reactor regenerator section.
90
Check air cooler sound & vibration.
Check colors of run down products.
Check all sample points.
Check injection rate of corrosion inhibitor.
Check exchangers for any leakage.
Check level of 19C-1 and cross check with try lines.
Check hanging support for reactor regenerator section.
90
Fractionator :
12.0 STANDING INSTRUCTION
Always keep overhead pressure relief valve 19PIC-202 on auto with setting 0.4Kg/cm2 higher than
19C-1 operating pressure.
Maintain 19C-1 level 50-60% and counter check 19C-1 level in gauge glass & try lines.
In furnace and Fractionator section restrict following temperatures in operation.
• 19F-1 fire box temperature = 750
0
C max
• 19F-1 tube skin temperature = 640
0
C max
• 19F-1 coil outlet temperature = 380
0
C max
• MCB = 362
0
C max
• 36th tray = <395
0
C
• HCO draw off tray temperature = <320
0
C max
Pull out feed in 19C-1 level could not be brought down even after feed reduction for two hrs.
Maintain the following flow in operation –
• Through 19E-3 FIC-138 = >340 M3/hr min
• Through 19E-4 FIC-147/5102 = >45 M3/hr min
• CLO flow through 19E-5 = >6 M3/hr
One set
Always keep Rx bypass line manifold valve in 19C-1 bottom in open position.
Keep 19V-105 liquid temperature around 35
0
C to 45
0
C.
Check and transfer liquid from 20V-210.
Maintain inhibitor injection to 19C-1 vapor line at the rate of 2.5 – 3.0 lit/hr. If solution strength is
1:2 (one part inhibitor and two part gasoline.)
Check local level indications for 19E-4 & 19E-7 once in shift.
91
12.0 STANDING INSTRUCTION
Always keep overhead pressure relief valve 19PIC-202 on auto with setting 0.4Kg/cm2 higher than
19C-1 operating pressure.
Maintain 19C-1 level 50-60% and counter check 19C-1 level in gauge glass & try lines.
In furnace and Fractionator section restrict following temperatures in operation.
• 19F-1 fire box temperature = 750
0
C max
• 19F-1 tube skin temperature = 640
0
C max
• 19F-1 coil outlet temperature = 380
0
C max
• MCB = 362
0
C max
• 36th tray = <395
0
C
• HCO draw off tray temperature = <320
0
C max
Pull out feed in 19C-1 level could not be brought down even after feed reduction for two hrs.
Maintain the following flow in operation –
• Through 19E-3 FIC-138 = >340 M3/hr min
• Through 19E-4 FIC-147/5102 = >45 M3/hr min
• CLO flow through 19E-5 = >6 M3/hr
One set
Always keep Rx bypass line manifold valve in 19C-1 bottom in open position.
Keep 19V-105 liquid temperature around 35
0
C to 45
0
C.
Check and transfer liquid from 20V-210.
Maintain inhibitor injection to 19C-1 vapor line at the rate of 2.5 – 3.0 lit/hr. If solution strength is
1:2 (one part inhibitor and two part gasoline.)
Check local level indications for 19E-4 & 19E-7 once in shift.
91
Keep adequately open FG to 19C-2 to allow PIC-202 opening 5% min. while catalyst circulation is
on with steam.
Maintain wash water flow 5.5 – 6.0 % by volume of feed with max of 13 M3/hr.
19K-101 & 20K-201
Check trip logic of MAB & WGC before rolling the turbine.
Always keep MAB anti-surge on auto mode.
Pull out feed if steam pressure falls down 42.0 Kg/cm2.
Trip blower if steam pressure falls below 40.0 Kg/cm2.
Do barring of 19K-101 & 20K-201 at every startup and shutdown.
Trip 19K-101 & 20K-201 for loss of both condensate pumps.
Trip air blower in case of the DDSV and anti-surge fail to open.
Cut off feed at once on loss of air blower and take the following steps.
• Close RCSV & SCSV .
• Inject steam to riser.
• Isolate feed to riser.
• Divert CO to CO stack.
• Release excess pressure to flare.
• Ensure slurry shut off valve close and slurry is diverted to column.
• Close feed nozzles valves.
Always ensure lube oil is moisture free.
Check L.G. & drain 20K-201 suction in each shift.
Trip WGC if –
• If it surges for any reason or steam pressure falls below 40.0 Kg/cm2.
• Loss of both the condensate pumps.
92
on with steam.
Maintain wash water flow 5.5 – 6.0 % by volume of feed with max of 13 M3/hr.
19K-101 & 20K-201
Check trip logic of MAB & WGC before rolling the turbine.
Always keep MAB anti-surge on auto mode.
Pull out feed if steam pressure falls down 42.0 Kg/cm2.
Trip blower if steam pressure falls below 40.0 Kg/cm2.
Do barring of 19K-101 & 20K-201 at every startup and shutdown.
Trip 19K-101 & 20K-201 for loss of both condensate pumps.
Trip air blower in case of the DDSV and anti-surge fail to open.
Cut off feed at once on loss of air blower and take the following steps.
• Close RCSV & SCSV .
• Inject steam to riser.
• Isolate feed to riser.
• Divert CO to CO stack.
• Release excess pressure to flare.
• Ensure slurry shut off valve close and slurry is diverted to column.
• Close feed nozzles valves.
Always ensure lube oil is moisture free.
Check L.G. & drain 20K-201 suction in each shift.
Trip WGC if –
• If it surges for any reason or steam pressure falls below 40.0 Kg/cm2.
• Loss of both the condensate pumps.
92
Purge WGC casing with nitrogen before charging gas.
Keep seal gas charged if WGC suction is lined up to 19V-5.
Rx-Rg
If both hydraulic oil pumps are lost, pull out feed, and inject steam to riser. Close RSSV & SCSV by
ESD cylinder.
Prior to lighting 19F-2 —
• Check igniter spark properly.
• Drain condensate from FG header KOD.
• Open service air to slight glass.
Maintain air flow to Regen. 30000 – 35000 M3/hr & pressure 0.8 – 1.0 Kg/cm2 while loading
catalyst.
Keep delta P over ride controller of RCSV & SCSV always on auto mode.
In case RCSV & SCSV are not closing after loss of delta P, pull out feed, trip 19K-1 & 20K-1.
Depressurize the reactor & regenerator. Put blanketing steam to riser.
During DFAH firing If any reason MAB trips cut off fuel gas to 19F-2. Isolate all B/Vs.
Keep FG line blinded when 19F-2 is not in service.
Catalyst loading in regenerator shall be done when Regen. Temp. is above 475
0
C.
Inject torch oil when Regen. Temp. is above 425
0
C. Always flush torch oil line with LCO.
Maintain negative differential pressure of 0.05 to 0.1 Kg/cm2 in RG-RX before starting catalyst
circulation.
Check all standpipe purge points for thoroughness.
Keep slide valve gland steam pressure 6.0 Kg/cm2.
During catalyst circulation to minimize catalyst loss ensure airflow to regenerator approx. 30000
NM
3
and pressure above 0.6 Kg/cm2.
93
Keep seal gas charged if WGC suction is lined up to 19V-5.
Rx-Rg
If both hydraulic oil pumps are lost, pull out feed, and inject steam to riser. Close RSSV & SCSV by
ESD cylinder.
Prior to lighting 19F-2 —
• Check igniter spark properly.
• Drain condensate from FG header KOD.
• Open service air to slight glass.
Maintain air flow to Regen. 30000 – 35000 M3/hr & pressure 0.8 – 1.0 Kg/cm2 while loading
catalyst.
Keep delta P over ride controller of RCSV & SCSV always on auto mode.
In case RCSV & SCSV are not closing after loss of delta P, pull out feed, trip 19K-1 & 20K-1.
Depressurize the reactor & regenerator. Put blanketing steam to riser.
During DFAH firing If any reason MAB trips cut off fuel gas to 19F-2. Isolate all B/Vs.
Keep FG line blinded when 19F-2 is not in service.
Catalyst loading in regenerator shall be done when Regen. Temp. is above 475
0
C.
Inject torch oil when Regen. Temp. is above 425
0
C. Always flush torch oil line with LCO.
Maintain negative differential pressure of 0.05 to 0.1 Kg/cm2 in RG-RX before starting catalyst
circulation.
Check all standpipe purge points for thoroughness.
Keep slide valve gland steam pressure 6.0 Kg/cm2.
During catalyst circulation to minimize catalyst loss ensure airflow to regenerator approx. 30000
NM
3
and pressure above 0.6 Kg/cm2.
93
Limit the temperatures of the following in operation as follows –
• Regenerator flue gas = <750
0
C.
• Flue gas below DDSV = <750
0
C.
• Orifice chamber = <750
0
C.
• Reactor = 550
0
C.
If any reason the unit could not be achieved the above condition for continuous 30 min. pull out the
feed.
Observe for any hot spots on regenerator U/S & D/S of DDSV, orifice chamber, riser, stand pipes in
every night shift. If any such spot is noticed put MP steam on the surface and alert
RSM/DMPN/IPM.
Any catalyst leak/loss must be arrested immediately, in case of unmanageable hot catalyst leak put
out feed & stop blower.
If the Reactor level goes above 95% and regenerator level below 20% pull out feed and try to
normalize the level.
When there is no catalyst circulation off load all catalyst from Reactor to regenerator.
Ensure Hydraulic cylinder jog & handwheel operation handle is in neutral position.
When diverting CO to CO boiler hydraulic supply to TPSV to be keep throttled and take min 45
minutes for routing.
Always keep vessel level >15% while draining caustic, MEA in LPGTU.
In case of feed cut off to riser following actions are to be taken–
• Start riser steam to riser.
• Close B/V on feed to riser.
• Close SCSV & RCSV from control room.
• Isolate feed, slurry, HCO, naphtha nozzles B/Vs.
94
• Regenerator flue gas = <750
0
C.
• Flue gas below DDSV = <750
0
C.
• Orifice chamber = <750
0
C.
• Reactor = 550
0
C.
If any reason the unit could not be achieved the above condition for continuous 30 min. pull out the
feed.
Observe for any hot spots on regenerator U/S & D/S of DDSV, orifice chamber, riser, stand pipes in
every night shift. If any such spot is noticed put MP steam on the surface and alert
RSM/DMPN/IPM.
Any catalyst leak/loss must be arrested immediately, in case of unmanageable hot catalyst leak put
out feed & stop blower.
If the Reactor level goes above 95% and regenerator level below 20% pull out feed and try to
normalize the level.
When there is no catalyst circulation off load all catalyst from Reactor to regenerator.
Ensure Hydraulic cylinder jog & handwheel operation handle is in neutral position.
When diverting CO to CO boiler hydraulic supply to TPSV to be keep throttled and take min 45
minutes for routing.
Always keep vessel level >15% while draining caustic, MEA in LPGTU.
In case of feed cut off to riser following actions are to be taken–
• Start riser steam to riser.
• Close B/V on feed to riser.
• Close SCSV & RCSV from control room.
• Isolate feed, slurry, HCO, naphtha nozzles B/Vs.
94
• Do not isolate atomizing steam to feed, slurry, HCO, naphtha nozzles.
• Commission torch oil to regenerator if blower is running.
• Unload and stop 20K-201.
• Open make up gas to 19C-2 to maintain the pressure of 19C-1.
• Close 20PIC-0063 to avoid depressurization of gas conc. Unit.
• Isolate hot feed B/Vs ex AVU & OHCU.
• Stop booster pumps.
• Cut off firing to 19F-1 as soon as possible and isolate FG and FO supply & burner valves.
• Vent 19F-1 steam to vent.
• Do not stop amine circulation to 20C-6.
• Isolate all the R/D isolation valves, consult board operator.
• Take RCSV, SCSV on jog control after informing panel.
• Start barring only if lube oil pumps of 19K-101 & 20K-201 are in running condition.
GENERAL:
Never leave the place if open draining is going on.
Keep all the selector switches on auto start for standby pumps and keep all the running
pumps on manual mode.
Keeps all the interlocks (trip securities) in line.
Before startup check all the auto start equipments by shutting off the running equipment.
Don’t leave sour water drain open.
Amine shall never be drained to OWS.
Inform shift supervisor if any vibration indication and bearing temperatures are abnormal in
pumps.
95
• Commission torch oil to regenerator if blower is running.
• Unload and stop 20K-201.
• Open make up gas to 19C-2 to maintain the pressure of 19C-1.
• Close 20PIC-0063 to avoid depressurization of gas conc. Unit.
• Isolate hot feed B/Vs ex AVU & OHCU.
• Stop booster pumps.
• Cut off firing to 19F-1 as soon as possible and isolate FG and FO supply & burner valves.
• Vent 19F-1 steam to vent.
• Do not stop amine circulation to 20C-6.
• Isolate all the R/D isolation valves, consult board operator.
• Take RCSV, SCSV on jog control after informing panel.
• Start barring only if lube oil pumps of 19K-101 & 20K-201 are in running condition.
GENERAL:
Never leave the place if open draining is going on.
Keep all the selector switches on auto start for standby pumps and keep all the running
pumps on manual mode.
Keeps all the interlocks (trip securities) in line.
Before startup check all the auto start equipments by shutting off the running equipment.
Don’t leave sour water drain open.
Amine shall never be drained to OWS.
Inform shift supervisor if any vibration indication and bearing temperatures are abnormal in
pumps.
95
GCU:
Ensure no condensate accumulation on 19V-23.
Drain water from pump casing drains before starting to avoid tripping.
Ensure no condensate accumulation in 20V-9.
Don’t route unstabilized gasoline to Prime-G.
Ensure in operation & during startup no water carry over from 19V-105 to 20C-1 and 20V-
203 to 20C-3.
Ensure no water accumulation in 20E-4 boot.
Keep stripped gas flow rate ex 20C-3 min 15000 MN3/hr and bottom temp./Top temp. 100
0
C
and 62
0
C respectively.
NLPGTU:
Always ensure sand filter & vessel draining is done keeping level in vessel to maintain seal.
Check air cooler vibration and sound in every shift & report abnormalities.
Use safety goggles during caustic, amine sampling
96
Ensure no condensate accumulation on 19V-23.
Drain water from pump casing drains before starting to avoid tripping.
Ensure no condensate accumulation in 20V-9.
Don’t route unstabilized gasoline to Prime-G.
Ensure in operation & during startup no water carry over from 19V-105 to 20C-1 and 20V-
203 to 20C-3.
Ensure no water accumulation in 20E-4 boot.
Keep stripped gas flow rate ex 20C-3 min 15000 MN3/hr and bottom temp./Top temp. 100
0
C
and 62
0
C respectively.
NLPGTU:
Always ensure sand filter & vessel draining is done keeping level in vessel to maintain seal.
Check air cooler vibration and sound in every shift & report abnormalities.
Use safety goggles during caustic, amine sampling
96
13.0 INTERLOCKS & TRIPS INSTRUCTION
1. MAB DISCHARGE FLOW RATE TO REGENERATOR (I-01)
2. DFAH BURNER INTERLOCK (I-03)
3. NAPHTHA FEED COALESCER BOOT LEVEL INTERLOCK (I-04)
4. METAL TEMPERATURE OF 2” CATALYST MAKEUP LINE INTERLOCK (I-06)
5. METAL TEMPERATURE OF 1.5” CATALYST MAKE UP LINE INTERLOCK (I-07)
6. RR SECTION TRIP INTERLOCK (I-101)
7. RAW OIL CHARGE PUMP TRIP INTERLOCK (I-42)
8. LCO PA AIR COOLER TRIP INTERLOCK (I-41A/B)
9. FIRE SHUT DOWN VALVE AT MAIN COLUMN BOTTOM (I-51)
10. SPONGE ABSORBER LEAN OIL PUMP TRIP INTERLOCK (I-56)
11. MAIN COLUMN OVERHEAD AIR CONDENSER TRIP INTERLOCK (I-66A-R)
12. FIRE SHUT DOWN VALVE AT MAIN COLUMN RECEIVER (I-71)
13. MAIN CLOUMN REFLUX & NET OVERHEAD PUMPS TRIP INTERLOCK (I-72)
14. CHARGE HEATER PASS-1 FLOW CONTROL (I-90)
15. FUEL GAS SUPPLY TO CHARGE HEATER INTERLOCK (I-92)
16. CBD DRUM LVEL INTERLOCK (I-81)
97
1. MAB DISCHARGE FLOW RATE TO REGENERATOR (I-01)
2. DFAH BURNER INTERLOCK (I-03)
3. NAPHTHA FEED COALESCER BOOT LEVEL INTERLOCK (I-04)
4. METAL TEMPERATURE OF 2” CATALYST MAKEUP LINE INTERLOCK (I-06)
5. METAL TEMPERATURE OF 1.5” CATALYST MAKE UP LINE INTERLOCK (I-07)
6. RR SECTION TRIP INTERLOCK (I-101)
7. RAW OIL CHARGE PUMP TRIP INTERLOCK (I-42)
8. LCO PA AIR COOLER TRIP INTERLOCK (I-41A/B)
9. FIRE SHUT DOWN VALVE AT MAIN COLUMN BOTTOM (I-51)
10. SPONGE ABSORBER LEAN OIL PUMP TRIP INTERLOCK (I-56)
11. MAIN COLUMN OVERHEAD AIR CONDENSER TRIP INTERLOCK (I-66A-R)
12. FIRE SHUT DOWN VALVE AT MAIN COLUMN RECEIVER (I-71)
13. MAIN CLOUMN REFLUX & NET OVERHEAD PUMPS TRIP INTERLOCK (I-72)
14. CHARGE HEATER PASS-1 FLOW CONTROL (I-90)
15. FUEL GAS SUPPLY TO CHARGE HEATER INTERLOCK (I-92)
16. CBD DRUM LVEL INTERLOCK (I-81)
97
1. MAB DISCHARGE FLOWRATE TO REGENERATOR (I-01)
When MAB discharge air Flow rate to regenerator is very low and I-01 is not in Bypassed (HS-0203 in
position-2), FSLL-0301 (2oo3) signal shall:
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS
SWITCH
MAB TRIP SIGNAL CLOSE SPECIAL CHECK VALVES (SP-01 & HS-5203
FROM MAB PLC SP-02).
I-101 FEED OUT AT MAB SET THE OUTPUT OF PV-202 TO 100%. 990 HS-0203
DISCHAREG AIR ACTUATE DFAH BURNER TRIP NM
3
/HR
FLOW INTERLOCK (019-I-03).
19FI0301A/B/C ACTUATE RR-SECTION TRIP INTERLOCK
(019-I-101).
2. DFAH BURNER INTERLOCK (I-03)
To isolate the fuel gas supply to DFAH during flame failure.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS
SWITCH
I-03 19PI0302 -
19PI0301
UV-0301/0302 closes 0.25
Kg/cm2
HS-0301
DFAH flame
detectors
990
NM
3
/HR
019-I-01
98
When MAB discharge air Flow rate to regenerator is very low and I-01 is not in Bypassed (HS-0203 in
position-2), FSLL-0301 (2oo3) signal shall:
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS
SWITCH
MAB TRIP SIGNAL CLOSE SPECIAL CHECK VALVES (SP-01 & HS-5203
FROM MAB PLC SP-02).
I-101 FEED OUT AT MAB SET THE OUTPUT OF PV-202 TO 100%. 990 HS-0203
DISCHAREG AIR ACTUATE DFAH BURNER TRIP NM
3
/HR
FLOW INTERLOCK (019-I-03).
19FI0301A/B/C ACTUATE RR-SECTION TRIP INTERLOCK
(019-I-101).
2. DFAH BURNER INTERLOCK (I-03)
To isolate the fuel gas supply to DFAH during flame failure.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS
SWITCH
I-03 19PI0302 -
19PI0301
UV-0301/0302 closes 0.25
Kg/cm2
HS-0301
DFAH flame
detectors
990
NM
3
/HR
019-I-01
98
3. NAPHTHA FEED COLAESCER BOOT LEVEL INTERLOCK (I-04)
To isolate the naphtha feed from battery limit, avoiding ingress of water in Reactor Riser. :
INTERL
OCK
NO.
CAUSE EFFECT Value BYPASS/RESET SWITCH
I-04 Coalescer
boot Level
LT-
0503/0505
(2oo2
Voting)
Close Full range Naphtha feed flow
control valve (FV-0504A).
Close ON-Off valve (XV-0501) on
VB naphtha line to Coalescer
Open ON-Off valve (XV-0502) on
VB naphtha line to DHDT.
90% HS-0503
Position1 - XV 0501
open & XV-0502
close.
Position2 - XV 0501
close & XV-0502
open.
4. METAL TEMPERATURE OF 2” CATALYST MAKEUP LINE INTERLOCK (I-06)
To protect the process associated equipment from getting exposed to high temperature catalyst.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS
SWITCH
I-06 TI-0404 Close on-off valve (XV-0401) on
2” fresh catalyst make up line.
100°C
99
To isolate the naphtha feed from battery limit, avoiding ingress of water in Reactor Riser. :
INTERL
OCK
NO.
CAUSE EFFECT Value BYPASS/RESET SWITCH
I-04 Coalescer
boot Level
LT-
0503/0505
(2oo2
Voting)
Close Full range Naphtha feed flow
control valve (FV-0504A).
Close ON-Off valve (XV-0501) on
VB naphtha line to Coalescer
Open ON-Off valve (XV-0502) on
VB naphtha line to DHDT.
90% HS-0503
Position1 - XV 0501
open & XV-0502
close.
Position2 - XV 0501
close & XV-0502
open.
4. METAL TEMPERATURE OF 2” CATALYST MAKEUP LINE INTERLOCK (I-06)
To protect the process associated equipment from getting exposed to high temperature catalyst.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS
SWITCH
I-06 TI-0404 Close on-off valve (XV-0401) on
2” fresh catalyst make up line.
100°C
99
5. METAL TEMPERATURE OF 1.5” CATALYST MAKE UP LINE INTERLOCK (I-07)
To protect the process associated equipment from getting exposed to high temperature catalyst.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS
SWITCH
I-07 TI-0405 Close on-off valve (XV-0402) on
1.5” fresh catalyst make up line.
100°C
6. RR SECTION TRIP INTERLOCK (I-101)
To prevent unsafe condition in the reactor regenerator and to provide a level of automation.
Abnormal conditions for Reactor vapor temperature (TSHH -0502/TSLL-0502); Reactor stripper catalyst
bed level (LSLL-0501); Differential pressure across RCSV (DPSLL-0511) & SCSV (DPSLL-0510); Actuation
of interlock (019-I-01) or emergency shutdown by operator (HS-0502A/B) and HS-0501 in postion-2 (I-
101 logic Bypass switch not in Bypass mode) shall activate I-101
100
To protect the process associated equipment from getting exposed to high temperature catalyst.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS
SWITCH
I-07 TI-0405 Close on-off valve (XV-0402) on
1.5” fresh catalyst make up line.
100°C
6. RR SECTION TRIP INTERLOCK (I-101)
To prevent unsafe condition in the reactor regenerator and to provide a level of automation.
Abnormal conditions for Reactor vapor temperature (TSHH -0502/TSLL-0502); Reactor stripper catalyst
bed level (LSLL-0501); Differential pressure across RCSV (DPSLL-0511) & SCSV (DPSLL-0510); Actuation
of interlock (019-I-01) or emergency shutdown by operator (HS-0502A/B) and HS-0501 in postion-2 (I-
101 logic Bypass switch not in Bypass mode) shall activate I-101
100
INTE
RLO
CK
NO.
CAUSE EFFECT Value BYPASS/RESET
SWITCH
TT-
64A/65A/050
2 (2oo3)
Close Raw oil feed to riser on-off XV-79A and
open raw oil feed riser bypass on-off valve
XV-79B to the main column through XV-79B.
Emergency steam to riser, flow control valve
FV-466 gets 100% opens.
Stop the flue gas flow through two port slides
valve to CO boiler and bypass the flow
directly to the atmosphere through stack.
Close the catalyst circulation by closing
Regenerated catalyst slide valve and spent
catalyst slide valve.
Trip the raw oil feed pump (019-P-
02A/B/102C).
Trip the raw oil booster pump (019-P-25A/B).
Open the Raw oil feed nozzle dispersion
steam flow control valve (FV-452) 100% to
avoid choking of nozzles.
552°C
HS-0501 (I-
101 bypass)
HS-0401
(TPSV)
HS-79 (Feed)
HS-0504
(HCO)
HS-0505
(Slurry)
LT 0501A/B/C
(2oo3)
90%
DPI 0510
A/B/C (2oo3)
0.09
kg/cm²
DPI 0511
A/B/C (2oo3)
0.09
kg/cm²
TT-
64A/65A/050
2 (2oo3)
470°C
HS-0502A/B
(Emergency
Shutdown
(Local &
Remote))
101
RLO
CK
NO.
CAUSE EFFECT Value BYPASS/RESET
SWITCH
TT-
64A/65A/050
2 (2oo3)
Close Raw oil feed to riser on-off XV-79A and
open raw oil feed riser bypass on-off valve
XV-79B to the main column through XV-79B.
Emergency steam to riser, flow control valve
FV-466 gets 100% opens.
Stop the flue gas flow through two port slides
valve to CO boiler and bypass the flow
directly to the atmosphere through stack.
Close the catalyst circulation by closing
Regenerated catalyst slide valve and spent
catalyst slide valve.
Trip the raw oil feed pump (019-P-
02A/B/102C).
Trip the raw oil booster pump (019-P-25A/B).
Open the Raw oil feed nozzle dispersion
steam flow control valve (FV-452) 100% to
avoid choking of nozzles.
552°C
HS-0501 (I-
101 bypass)
HS-0401
(TPSV)
HS-79 (Feed)
HS-0504
(HCO)
HS-0505
(Slurry)
LT 0501A/B/C
(2oo3)
90%
DPI 0510
A/B/C (2oo3)
0.09
kg/cm²
DPI 0511
A/B/C (2oo3)
0.09
kg/cm²
TT-
64A/65A/050
2 (2oo3)
470°C
HS-0502A/B
(Emergency
Shutdown
(Local &
Remote))
101
INTERL
OCK
NO.
CAUSE EFFECT Value BYPASS
/RESET
SWITCH
Close the HCO feed on-off valve (XV-460).
Close slurry recycle feed on-off valve (XV-456) to the
riser and slurry recycle Reactor Riser bypass on-off
valve XV-79B the main column through XV-455.
Open the slurry nozzle dispersion steam flow control
valve (FV-457) 100% to avoid choking of nozzles.
Open the HCO nozzle dispersion steam flow control
valve (FV-462) 100% to avoid choking of nozzles.
Close the full range naphtha feed on-off valve (FV-
0504A).
Open the naphtha nozzle dispersion steam flow
control valve (FV-0503) 100% to avoid choking of
nozzles.
Close VB naphtha to naphtha Coalescer (XV-0501) and
open VB naphtha bypass on-off valve (XV-0502) to
DHDT.
Close the Combined naphtha feed to Reactor Riser
on-off valve (XV-0503).
102
OCK
NO.
CAUSE EFFECT Value BYPASS
/RESET
SWITCH
Close the HCO feed on-off valve (XV-460).
Close slurry recycle feed on-off valve (XV-456) to the
riser and slurry recycle Reactor Riser bypass on-off
valve XV-79B the main column through XV-455.
Open the slurry nozzle dispersion steam flow control
valve (FV-457) 100% to avoid choking of nozzles.
Open the HCO nozzle dispersion steam flow control
valve (FV-462) 100% to avoid choking of nozzles.
Close the full range naphtha feed on-off valve (FV-
0504A).
Open the naphtha nozzle dispersion steam flow
control valve (FV-0503) 100% to avoid choking of
nozzles.
Close VB naphtha to naphtha Coalescer (XV-0501) and
open VB naphtha bypass on-off valve (XV-0502) to
DHDT.
Close the Combined naphtha feed to Reactor Riser
on-off valve (XV-0503).
102
7. RAW OIL CHARGE PUMP TRIP INTERLOCK (I-42)
To protect Raw Oil Booster pump (019-P-25A/B) from cavitation.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS SWITCH
I-42 Raw Oil Charge
Pump trip
Stop Raw Oil Booster
Pumps (019-P-25A/B)
8. LCO PA AIR COOLER (019-EM-125A/B) TRIP INTERLOCK (I-41A/B)
To protect LCO PA Air Cooler Fan from high vibration
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS / RESET SWITCH
I-41A/B VT-3201
VT-3202
Trip the LCO PA
Air Cooler Motor
10 mm/Sec When process returns to
normal, the Air Cooler Motors
shall be allowed to start
manually.(Auto Reset)
103
To protect Raw Oil Booster pump (019-P-25A/B) from cavitation.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS SWITCH
I-42 Raw Oil Charge
Pump trip
Stop Raw Oil Booster
Pumps (019-P-25A/B)
8. LCO PA AIR COOLER (019-EM-125A/B) TRIP INTERLOCK (I-41A/B)
To protect LCO PA Air Cooler Fan from high vibration
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS / RESET SWITCH
I-41A/B VT-3201
VT-3202
Trip the LCO PA
Air Cooler Motor
10 mm/Sec When process returns to
normal, the Air Cooler Motors
shall be allowed to start
manually.(Auto Reset)
103
9. FIRE SHUT DOWN VALVE AT MAIN COLUMN BOTTOM (I-51)
To isolate the fuel supply source during fire and protect the process and/or associated equipment with a
level of automation.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS / RESET SWITCH
I-51 HS-3401A
(Auxiliary
Console
Panel)
Close XV-3401.
Loss of ZSH-3401
shall trip Main
Column Bottom
Pumps (019-P-
103A/B)
Actuation of field switch HS-
3401C shall open XV-3401.
Limit switch ZSH-3401 open
signal ZAH-3401 shall activate
start permissive for Main
Column Bottom Pumps (019-
P-103A/B)
HS-3401B/D
(Field 15 m
Away/Near)
10. SPONGE ABSORBER LEAN OIL PUMP TRIP INTERLOCK (I-56)
To protect Sponge Absorber Lean Oil Pump (020-P-7A/B) from cavitation.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS / RESET SWITCH
I-56 019- Whenever LCO Any one of the LCO Circulating
PM- Circulating pumps (019- pumps (019-P-108A/B) running
108A/B P-108A/B) trips, the trip indication XL-3501/3502 shall
Trip signal shall Stop Sponge activate start permissive for
Status Absorber Lean Oil Pumps Sponge Absorber Lean Oil
(020-P-7A/B). Pumps (020-P-7A/B).
104
To isolate the fuel supply source during fire and protect the process and/or associated equipment with a
level of automation.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS / RESET SWITCH
I-51 HS-3401A
(Auxiliary
Console
Panel)
Close XV-3401.
Loss of ZSH-3401
shall trip Main
Column Bottom
Pumps (019-P-
103A/B)
Actuation of field switch HS-
3401C shall open XV-3401.
Limit switch ZSH-3401 open
signal ZAH-3401 shall activate
start permissive for Main
Column Bottom Pumps (019-
P-103A/B)
HS-3401B/D
(Field 15 m
Away/Near)
10. SPONGE ABSORBER LEAN OIL PUMP TRIP INTERLOCK (I-56)
To protect Sponge Absorber Lean Oil Pump (020-P-7A/B) from cavitation.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS / RESET SWITCH
I-56 019- Whenever LCO Any one of the LCO Circulating
PM- Circulating pumps (019- pumps (019-P-108A/B) running
108A/B P-108A/B) trips, the trip indication XL-3501/3502 shall
Trip signal shall Stop Sponge activate start permissive for
Status Absorber Lean Oil Pumps Sponge Absorber Lean Oil
(020-P-7A/B). Pumps (020-P-7A/B).
104
11. MAIN COLUMN OVERHEAD AIR CONDENSER TRIP INTERLOCK (I-66A-R)
To protect Main Column Air Condenser Fans from high vibration.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS / RESET SWITCH
I-66 A-R 19C-1 O/H
Air Cooler
Fan very
high
vibration
VSHH-3701
Trip the main
column overhead
condenser motor
(019-EM-112)
10 When process returns to
normal, the Air Cooler Motors
shall be allowed to start
manually (Auto Reset).
12. FIRE SHUT DOWN VALVE AT MAIN COLUMN RECEIVER (I-71)
To isolate the fuel supply source during fire and protect the process and/or associated equipment with a
level of automation.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS / RESET SWITCH
I-71 HS-3801A Close XV-3801. Actuation of field switch HS-
(Auxiliary Loss of ZSH-3801 3801C shall open XV-3801.
Console shall trip 019-P- Limit switch ZSH-3801 open
Panel) 9A/B/C, 019-P- signal ZAH-3801 shall activate
HS-3801B/D 10A/B/C start permissive for 019-P-
(Field 15 m 9A/B/C, 019-P-10A/B/C
Away/Near)
105
To protect Main Column Air Condenser Fans from high vibration.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS / RESET SWITCH
I-66 A-R 19C-1 O/H
Air Cooler
Fan very
high
vibration
VSHH-3701
Trip the main
column overhead
condenser motor
(019-EM-112)
10 When process returns to
normal, the Air Cooler Motors
shall be allowed to start
manually (Auto Reset).
12. FIRE SHUT DOWN VALVE AT MAIN COLUMN RECEIVER (I-71)
To isolate the fuel supply source during fire and protect the process and/or associated equipment with a
level of automation.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS / RESET SWITCH
I-71 HS-3801A Close XV-3801. Actuation of field switch HS-
(Auxiliary Loss of ZSH-3801 3801C shall open XV-3801.
Console shall trip 019-P- Limit switch ZSH-3801 open
Panel) 9A/B/C, 019-P- signal ZAH-3801 shall activate
HS-3801B/D 10A/B/C start permissive for 019-P-
(Field 15 m 9A/B/C, 019-P-10A/B/C
Away/Near)
105
13. MAIN CLOUMN REFLUX & NET OVERHEAD PUMPS TRIP INTERLOCK (I-72)
To protect Main Column Reflux Pumps & Main Column Net Overhead Pumps from cavitation.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS / RESET SWITCH
I-72 019-V-105
level very
low, LSLL -
206
Trip Main Column
Net Overhead
Pumps (019-P-
10A/B/C)
20% When Main Column Receiver
(019-V-105) level returns to
normal, the Main Column Reflux
pumps 019-P-9A/B/C and Main
Column Net Overhead pumps
(019-P-10A/B/C) shall be
allowed to start manually
On fault alarm of level
transmitter LT-206, 019-P-
9A/B/C, 019-P-10A/B/C & 019-P-
12A/B/C shall be tripped.
019-V-105
level very
low, LSLLL -
206
Trip Main Column
Reflux Pumps
(019-P-9A/B/C)
10%
.
106
To protect Main Column Reflux Pumps & Main Column Net Overhead Pumps from cavitation.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS / RESET SWITCH
I-72 019-V-105
level very
low, LSLL -
206
Trip Main Column
Net Overhead
Pumps (019-P-
10A/B/C)
20% When Main Column Receiver
(019-V-105) level returns to
normal, the Main Column Reflux
pumps 019-P-9A/B/C and Main
Column Net Overhead pumps
(019-P-10A/B/C) shall be
allowed to start manually
On fault alarm of level
transmitter LT-206, 019-P-
9A/B/C, 019-P-10A/B/C & 019-P-
12A/B/C shall be tripped.
019-V-105
level very
low, LSLLL -
206
Trip Main Column
Reflux Pumps
(019-P-9A/B/C)
10%
.
106
14. CHARGE HEATER PASS-1 FLOW CONTROL (I-90)
To protect Charge Heater (019-F-1) with a level of automation.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS / RESET SWITCH
I-90 Raw oil to charge
heater Pass-1
FI-90B
Close Shutdown valve
XV-113 on Fuel Oil
supply to charge
heater
Close Shutdown valve
XV-114 on Fuel Gas
Supply to charge
heater.
Close Shutdown valve
XV-3301 on Fuel Oil
return from charge
heater.
PIC-104 shall go on
manual with zero
output.
PIC-108 shall go on
manual with zero
output.
45
m3/
hr
19F-1 Pass flow bypass
switch (Auxiliary
Console Panel)
For Fuel oil supply HS-
113C (field) shall open
XV-113
For Fuel gas supply HS-
114C (field) shall open
XV-114
For Fuel oil return HS-
3301C (field) shall
open XV-3301
HS-113A (Auxiliary
Console Panel) ,
HS-113B/D (Field
15 m Away/Near)
HS-114A (Auxiliary
Console Panel),
HS-114B/D (Field
15 m Away/Near)
HS-3301A
(Auxiliary Console
Panel), HS-
3301B/D (Field 15
m Away/Near)
The above logic is typical for interlock I-91 (FI-91B) (Charge Heater Flow through Pass-2
Low Low) and interlock I-93 (TI-98 : 380
0
C)(Heater coil outlet temperature high high) 107
To protect Charge Heater (019-F-1) with a level of automation.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS / RESET SWITCH
I-90 Raw oil to charge
heater Pass-1
FI-90B
Close Shutdown valve
XV-113 on Fuel Oil
supply to charge
heater
Close Shutdown valve
XV-114 on Fuel Gas
Supply to charge
heater.
Close Shutdown valve
XV-3301 on Fuel Oil
return from charge
heater.
PIC-104 shall go on
manual with zero
output.
PIC-108 shall go on
manual with zero
output.
45
m3/
hr
19F-1 Pass flow bypass
switch (Auxiliary
Console Panel)
For Fuel oil supply HS-
113C (field) shall open
XV-113
For Fuel gas supply HS-
114C (field) shall open
XV-114
For Fuel oil return HS-
3301C (field) shall
open XV-3301
HS-113A (Auxiliary
Console Panel) ,
HS-113B/D (Field
15 m Away/Near)
HS-114A (Auxiliary
Console Panel),
HS-114B/D (Field
15 m Away/Near)
HS-3301A
(Auxiliary Console
Panel), HS-
3301B/D (Field 15
m Away/Near)
The above logic is typical for interlock I-91 (FI-91B) (Charge Heater Flow through Pass-2
Low Low) and interlock I-93 (TI-98 : 380
0
C)(Heater coil outlet temperature high high) 107
15. FUEL GAS SUPPLY TO CHARGE HEATER INTERLOCK (I-92)
To protect charge heater (019-F-1) with a level of automation.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS / RESET SWITCH
I-92 fuel gas
supply
pressure to
charge
heater
(019-F-1) is
very low,
PSLL-101
Close Shutdown
valve XV-114 on
Fuel Gas Supply to
charge heater.
PIC-108 shall go on
manual with zero
output.
0.2
Kg/c
m2
Low fuel gas supply pressure
bypass switch (Auxiliary Console
Panel)
When Fuel gas Supply reset, HS-
114C depressed, the solenoid
valve SOV-114 shall be energized
to open XV-114
16. CBD DRUM LVEL INTERLOCK (I-81)
To Control the level in CBD Drum (Gap Control)
108
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS / RESET SWITCH
I-81 CBD drum (19-V-121) Trip BD pump. 20%
is low, LSL-8801
CBD drum (19-V-121) Start CBD 80%
is high, LSH-8801 pump.
To protect charge heater (019-F-1) with a level of automation.
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS / RESET SWITCH
I-92 fuel gas
supply
pressure to
charge
heater
(019-F-1) is
very low,
PSLL-101
Close Shutdown
valve XV-114 on
Fuel Gas Supply to
charge heater.
PIC-108 shall go on
manual with zero
output.
0.2
Kg/c
m2
Low fuel gas supply pressure
bypass switch (Auxiliary Console
Panel)
When Fuel gas Supply reset, HS-
114C depressed, the solenoid
valve SOV-114 shall be energized
to open XV-114
16. CBD DRUM LVEL INTERLOCK (I-81)
To Control the level in CBD Drum (Gap Control)
108
INTERLOCK
NO.
CAUSE EFFECT Value BYPASS / RESET SWITCH
I-81 CBD drum (19-V-121) Trip BD pump. 20%
is low, LSL-8801
CBD drum (19-V-121) Start CBD 80%
is high, LSH-8801 pump.
GASOLINE SPLITTER UNIT INTERLOCK
CAUSE EFFECT
FCCG Splitter Overhead High Pressure
06 NA 020-PSHH-0804
A/B/C
IS-05
IS-08
03
(12)
Very high pressure at splitter overhead
SHU section depressurization
Splitter Reflux Pumps Protection
(2)(3) 020-UV-0804
020-UV-0901
NA
NA
03
(12)
04
(13)
Close
Close
Close MP steam to FCCG Splitter Reboiler
Close LP steam to Side Stripper Reboiler
(3)
(3)
Loss of Liquid in FCCG Splitter LCN Draw-off (1)
07 NA 020-LSLL-0301
IS-05
03 Very low level in LCN draw-off tray
SHU section depressurization
306-P-02 A/B
020-UV-0302
NA
NA
03
03
Stop
Close
Stop LCN product pumps
Close inventory valve on splitter LCN product outlet
FCCG Splitter Overhead Pumps 020-P-16 A/B Protection
08 NA 020-LSLL-0306
020-HS-1007
020-HS-1006
03
03
(14)
03
(14)
Very low level in FCCG Splitter Receiver
Push button to isolate liquid inventory (on site)
Push button to isolate liquid inventory (on control room
panel)
(3)
(3)
020-P-16 A/B
020-UV-1001
IS-06
NA
NA
03
03
(14)
Stop
Close
Actuate
Stop FCCG Splitter Overhead Pumps
Close inventory valve on FCCG Splitter Receiver HC
liquid outlet
FCCG Splitter overhead high pressure
(3)
HDS Section Shutdown (Chemical Risk) (2)
12 3
NA
NA
307-TSHH1-
0617 to 0629
307-FSLL-0904
020-LSLL-0303
IS-05
IS-16
06
09
03
Very high temperature in HDS Reactor and at HDS
Reactor outlet
Very low flow of recycle gas to HDS Reactor
Very low level at FCCG Splitter bottoms
SHU section depressurization
Recycle Gas Compressor protection
(1)(4) 020-UV-0301
307-UV-0701
020-P-18 A/B N
020-P-15 A/B
IS-03
IS-13
3
NA
3
NA
03
07
03
04
Close
Close
Stop
Stop
Actuate
Actuate
HDS section feed cut-off
Stop BFW for washing injection
Stop HDS Feed Pumps
Stop FCC heart cut pumps
SHU section shutdown
Shut down HDS Heater
(5)
(6)
3
High pressure in HCN circuit
27 NA 020-PSHH-0330 03 Ver High pressure in 020-P-18 A/B discharge circuit ,
during isolated operation of FCCGS unit
020-P-18 A/B
020-FV-0803 N
NA
NA
03
03
Stop
Close
Stop HDS Feed Pumps
Close feed to FCCGS unit.
(1)
3
UC-
001
NA
020-UV-0804
020-UV-0901
NA
NA
12
13
Close
Close
Prevents flow of steam to FCCGS column reboiler
020-E-22
Prevents flow of steam to FCC Heartcut Stripper
109
reboiler 020-E-23
(2)
High Pressure
of 020-C-107 M
020-PAHH-0804
12
Very high pressure in FCCGS column
CAUSE EFFECT
FCCG Splitter Overhead High Pressure
06 NA 020-PSHH-0804
A/B/C
IS-05
IS-08
03
(12)
Very high pressure at splitter overhead
SHU section depressurization
Splitter Reflux Pumps Protection
(2)(3) 020-UV-0804
020-UV-0901
NA
NA
03
(12)
04
(13)
Close
Close
Close MP steam to FCCG Splitter Reboiler
Close LP steam to Side Stripper Reboiler
(3)
(3)
Loss of Liquid in FCCG Splitter LCN Draw-off (1)
07 NA 020-LSLL-0301
IS-05
03 Very low level in LCN draw-off tray
SHU section depressurization
306-P-02 A/B
020-UV-0302
NA
NA
03
03
Stop
Close
Stop LCN product pumps
Close inventory valve on splitter LCN product outlet
FCCG Splitter Overhead Pumps 020-P-16 A/B Protection
08 NA 020-LSLL-0306
020-HS-1007
020-HS-1006
03
03
(14)
03
(14)
Very low level in FCCG Splitter Receiver
Push button to isolate liquid inventory (on site)
Push button to isolate liquid inventory (on control room
panel)
(3)
(3)
020-P-16 A/B
020-UV-1001
IS-06
NA
NA
03
03
(14)
Stop
Close
Actuate
Stop FCCG Splitter Overhead Pumps
Close inventory valve on FCCG Splitter Receiver HC
liquid outlet
FCCG Splitter overhead high pressure
(3)
HDS Section Shutdown (Chemical Risk) (2)
12 3
NA
NA
307-TSHH1-
0617 to 0629
307-FSLL-0904
020-LSLL-0303
IS-05
IS-16
06
09
03
Very high temperature in HDS Reactor and at HDS
Reactor outlet
Very low flow of recycle gas to HDS Reactor
Very low level at FCCG Splitter bottoms
SHU section depressurization
Recycle Gas Compressor protection
(1)(4) 020-UV-0301
307-UV-0701
020-P-18 A/B N
020-P-15 A/B
IS-03
IS-13
3
NA
3
NA
03
07
03
04
Close
Close
Stop
Stop
Actuate
Actuate
HDS section feed cut-off
Stop BFW for washing injection
Stop HDS Feed Pumps
Stop FCC heart cut pumps
SHU section shutdown
Shut down HDS Heater
(5)
(6)
3
High pressure in HCN circuit
27 NA 020-PSHH-0330 03 Ver High pressure in 020-P-18 A/B discharge circuit ,
during isolated operation of FCCGS unit
020-P-18 A/B
020-FV-0803 N
NA
NA
03
03
Stop
Close
Stop HDS Feed Pumps
Close feed to FCCGS unit.
(1)
3
UC-
001
NA
020-UV-0804
020-UV-0901
NA
NA
12
13
Close
Close
Prevents flow of steam to FCCGS column reboiler
020-E-22
Prevents flow of steam to FCC Heartcut Stripper
109
reboiler 020-E-23
(2)
High Pressure
of 020-C-107 M
020-PAHH-0804
12
Very high pressure in FCCGS column
MAB INTERLOCK & START PERMISSIVE
Unit Trip Unit Trip
Turbine Exh End JNL BRG Temp
Voting logic given as per grouping
19-TI-234A Deg C 138
Lube oil suppply header pressure 19-PI-0222A/B/C Kg/cm2g 0.8
19-TI-234B Deg C 138
Control oil pressure 19-PI-0234A/B/C Kg/cm2g 6.3
19-TI-234C Deg C 138
Main Steam Turbine Exhaust Pressure 19-PI-0228 A/B/C Kg/cm2g 0.03
Turbine STM End JNL BRG Temp
Voting logic given as per grouping
19-TI-233A Deg C 138
Surface Condeser Hot Well Level 19-LI-0233A/B/C % 100
19-TI-233B Deg C 138
MAB START PERMISSIVE
19-TI-233C Deg C 138
TRIP RESET PUSH BUTTON PRESSED 19PB0243
Turbine STM END THR BRG(ACT) Temp
Voting logic given as per grouping
19-TI-231A Deg C 138
T&T VALVE CLOSE 19ZSL0222
19-TI-231B Deg C 138
ANTISURGE VALVE FULLY OPEN 19ZSH0202
19-TI-231C Deg C 138
STATOR VANE CLOSE 19ZSL0201
Turbine STM END THR BRG(INACT) Temp
Voting logic given as per grouping
19-TI-232A Deg C 138
VACUUM BREAKER VALVE CLOSE 19ZSL0225
19-TI-232B Deg C 138
ONLINE TESTING VALVE POSITION OPEN 19ZSH0245A & B
TUR EXH END X AXIS RDL VIB 19-VT-222X Micron 102
TRIP SOLENOID VALVES CLOSE 19ZSL0246A & B
TUR EXH END Y AXIS RDL VIB
2oo2
19-VT-222Y Micron 102
TURNING GEAR LOCKOUT POSITION 19ZS-0232
TUR STM END X AXIS RDL VIBvotin g
19-VT-221X Micron 102
TURBINE LOACL TRIP VALVE CLOSE 19ZSL0247
TUR STM END Y AXIS RDL VIB 19-VT-221Y Micron 102
PROCESS COMMON START PERMISSIVE OK 19XS-0296
TUR STM END AXIAL DISPLACMENT
2oo2 voting
19-ZT-221A mm +/-0.54
BLOWER START PERMISSIVE LAMP IN FIELD 19XL0244A
19-ZT-222B mm +/-0.54
BLOWER START PERMISSIVE LAMP IN AUX CONSOLE 19XL0244
MAB RDL VIB
2oo2
19-VE-0223X Micron 83
Lube oil Rundown Tank Level 19-LI-0221 % 21
19-VE-0223Y Micron 83
Low Lube oil Supply Temp 19-TSL-0228 Deg C 38
MAB RDL VIB
voting
19-VE-0224X Micron 83
High Lube oil Supply Temp 19-TSH-0228 Deg C
19-VE-0224Y Micron 83
Lube oil Supply Pressure 19-PSL-0224 Kg/cm2g 0.92
MAB JNR BRG TEMP
Voting logic given as per grouping
19-TI-237A Deg C 138
Control Oil Supply Pressure 19-PSL-0233 Kg/cm2g 7.1
19-TI-237B Deg C 138
Turning Gear Operation
19-TI-237C Deg C 138
Low Lube oil Supply Pressure 19-PSLL-0224 Kg/cm2g 0.23
MAB RDL BRG TEMP
Voting logic given as per grouping
19-TI-238A Deg C 138
Oil Pump Start Permissive
19-TI-238B Deg C 138
Low Oil Reservoir level 19-LSL-0222 % 81.7 (60)
19-TI-238C Deg C 138
Low Oil Reservoir Temp 19-TSL-0226 Deg C 42 (21)
MAB THR BRG TEMP
Voting logic given as per grouping
19-TI-236A Deg C 138
Stand by pump Auto Start
19-TI-236B Deg C 138
Low Lube rundown tank level 19-LSL-0221 % 21.4
19-TI-236C Deg C 138
Low Lube oil Supply header Pressure 19-PSL-0224 Kg/cm2g 0.92
MAB THR BRG TEMP
Voting logic given as per grouping
19-TI-236A Deg C 138
Low main oil pump discahrge oil pressure 19-PSL-0236A Kg/cm2g 5.5 (11.0)
19-TI-236B Deg C 138
Oil Console header pressure low 19-PSL-0238 Kg/cm2g 11
19-TI-236C Deg C 138
Condesate Pump Start Premissive
MAB AXL POSITION
2oo2 voting
19-ZI-0222A MM +/-0.559
Hot Well Level not Low 19-LSL-0231 % 33.6
19-ZI-0222B MM +/-0.559
Standby Condesate Pump Auto Start
VOTING LOGIC EXISTS IN VIBRATION, AXIAL DISPLACEMENT & BEARING
TEMPERATURE INTERLOCK
High Hot Well Level 19-LSH-0231 % 86.6
Main Condesate pump Dischg Pr 19-PSL-0239 Kg/cm2g 3
Standby Condesate Pump Auto Stop
110
Low Hot Well Level 19-LSL-0231 % 33.6
Unit Trip Unit Trip
Turbine Exh End JNL BRG Temp
Voting logic given as per grouping
19-TI-234A Deg C 138
Lube oil suppply header pressure 19-PI-0222A/B/C Kg/cm2g 0.8
19-TI-234B Deg C 138
Control oil pressure 19-PI-0234A/B/C Kg/cm2g 6.3
19-TI-234C Deg C 138
Main Steam Turbine Exhaust Pressure 19-PI-0228 A/B/C Kg/cm2g 0.03
Turbine STM End JNL BRG Temp
Voting logic given as per grouping
19-TI-233A Deg C 138
Surface Condeser Hot Well Level 19-LI-0233A/B/C % 100
19-TI-233B Deg C 138
MAB START PERMISSIVE
19-TI-233C Deg C 138
TRIP RESET PUSH BUTTON PRESSED 19PB0243
Turbine STM END THR BRG(ACT) Temp
Voting logic given as per grouping
19-TI-231A Deg C 138
T&T VALVE CLOSE 19ZSL0222
19-TI-231B Deg C 138
ANTISURGE VALVE FULLY OPEN 19ZSH0202
19-TI-231C Deg C 138
STATOR VANE CLOSE 19ZSL0201
Turbine STM END THR BRG(INACT) Temp
Voting logic given as per grouping
19-TI-232A Deg C 138
VACUUM BREAKER VALVE CLOSE 19ZSL0225
19-TI-232B Deg C 138
ONLINE TESTING VALVE POSITION OPEN 19ZSH0245A & B
TUR EXH END X AXIS RDL VIB 19-VT-222X Micron 102
TRIP SOLENOID VALVES CLOSE 19ZSL0246A & B
TUR EXH END Y AXIS RDL VIB
2oo2
19-VT-222Y Micron 102
TURNING GEAR LOCKOUT POSITION 19ZS-0232
TUR STM END X AXIS RDL VIBvotin g
19-VT-221X Micron 102
TURBINE LOACL TRIP VALVE CLOSE 19ZSL0247
TUR STM END Y AXIS RDL VIB 19-VT-221Y Micron 102
PROCESS COMMON START PERMISSIVE OK 19XS-0296
TUR STM END AXIAL DISPLACMENT
2oo2 voting
19-ZT-221A mm +/-0.54
BLOWER START PERMISSIVE LAMP IN FIELD 19XL0244A
19-ZT-222B mm +/-0.54
BLOWER START PERMISSIVE LAMP IN AUX CONSOLE 19XL0244
MAB RDL VIB
2oo2
19-VE-0223X Micron 83
Lube oil Rundown Tank Level 19-LI-0221 % 21
19-VE-0223Y Micron 83
Low Lube oil Supply Temp 19-TSL-0228 Deg C 38
MAB RDL VIB
voting
19-VE-0224X Micron 83
High Lube oil Supply Temp 19-TSH-0228 Deg C
19-VE-0224Y Micron 83
Lube oil Supply Pressure 19-PSL-0224 Kg/cm2g 0.92
MAB JNR BRG TEMP
Voting logic given as per grouping
19-TI-237A Deg C 138
Control Oil Supply Pressure 19-PSL-0233 Kg/cm2g 7.1
19-TI-237B Deg C 138
Turning Gear Operation
19-TI-237C Deg C 138
Low Lube oil Supply Pressure 19-PSLL-0224 Kg/cm2g 0.23
MAB RDL BRG TEMP
Voting logic given as per grouping
19-TI-238A Deg C 138
Oil Pump Start Permissive
19-TI-238B Deg C 138
Low Oil Reservoir level 19-LSL-0222 % 81.7 (60)
19-TI-238C Deg C 138
Low Oil Reservoir Temp 19-TSL-0226 Deg C 42 (21)
MAB THR BRG TEMP
Voting logic given as per grouping
19-TI-236A Deg C 138
Stand by pump Auto Start
19-TI-236B Deg C 138
Low Lube rundown tank level 19-LSL-0221 % 21.4
19-TI-236C Deg C 138
Low Lube oil Supply header Pressure 19-PSL-0224 Kg/cm2g 0.92
MAB THR BRG TEMP
Voting logic given as per grouping
19-TI-236A Deg C 138
Low main oil pump discahrge oil pressure 19-PSL-0236A Kg/cm2g 5.5 (11.0)
19-TI-236B Deg C 138
Oil Console header pressure low 19-PSL-0238 Kg/cm2g 11
19-TI-236C Deg C 138
Condesate Pump Start Premissive
MAB AXL POSITION
2oo2 voting
19-ZI-0222A MM +/-0.559
Hot Well Level not Low 19-LSL-0231 % 33.6
19-ZI-0222B MM +/-0.559
Standby Condesate Pump Auto Start
VOTING LOGIC EXISTS IN VIBRATION, AXIAL DISPLACEMENT & BEARING
TEMPERATURE INTERLOCK
High Hot Well Level 19-LSH-0231 % 86.6
Main Condesate pump Dischg Pr 19-PSL-0239 Kg/cm2g 3
Standby Condesate Pump Auto Stop
110
Low Hot Well Level 19-LSL-0231 % 33.6
111
WGC INTERLOCK & START PERMISSIVE
WGC INTERLOCK & START PERMISSIVE
112
113
14.0 EQUIPMENT DETAILS
EQUIPMENT NO NAME OF THE EQUIPMENT
019-RX-1 REACTOR / STRIPPER
019-RG-1 REGENERATOR
19-F-1 CHARTE HEATER
19-F-2 DIRECT FIREED HEATER
19-F-3 CO-BOILER
019-K-101 MAIN AIR BLOWER
020-K-201 GAS COMPRESSOR
19-C-1 MAIN COLUMN
19-C-2 HN-STRIPPER
19-C-3 LCO-STRIPPER
20-C-1 PRIMARY ABSORBER
20-C-2 SECONDARY ABSORBER
20-C-3 STRIPPER
20-C-4 DEBUTANIZER – I
020-C-205 DEBUTANIZER-II
020-C-6 AMINE ABSORBER
19-V-1 FRESH CATALYST STORAGE
19-V-2 EQBM. CAT. STORAGE
019-V-4 FEED SURGE DRUM
019-V-105 MAIN COL. O/H RECEIVER
19-V-8 INTERMITTENT BD DRUM (19 E-4/E-7)
19-V-9 INTERMITTANT BLOW DOWN DRUM OF COB
19-V-10 CONTINUOUS BLOW DOWN DRUM.
19-V-11 CAT. HOUSE HOPPER.
019-V-21 CLOSED BLOW DOWN DRUM
114
EQUIPMENT NO NAME OF THE EQUIPMENT
019-RX-1 REACTOR / STRIPPER
019-RG-1 REGENERATOR
19-F-1 CHARTE HEATER
19-F-2 DIRECT FIREED HEATER
19-F-3 CO-BOILER
019-K-101 MAIN AIR BLOWER
020-K-201 GAS COMPRESSOR
19-C-1 MAIN COLUMN
19-C-2 HN-STRIPPER
19-C-3 LCO-STRIPPER
20-C-1 PRIMARY ABSORBER
20-C-2 SECONDARY ABSORBER
20-C-3 STRIPPER
20-C-4 DEBUTANIZER – I
020-C-205 DEBUTANIZER-II
020-C-6 AMINE ABSORBER
19-V-1 FRESH CATALYST STORAGE
19-V-2 EQBM. CAT. STORAGE
019-V-4 FEED SURGE DRUM
019-V-105 MAIN COL. O/H RECEIVER
19-V-8 INTERMITTENT BD DRUM (19 E-4/E-7)
19-V-9 INTERMITTANT BLOW DOWN DRUM OF COB
19-V-10 CONTINUOUS BLOW DOWN DRUM.
19-V-11 CAT. HOUSE HOPPER.
019-V-21 CLOSED BLOW DOWN DRUM
114
EQUIPMENT NO NAME OF THE EQUIPMENT
19-V-22 CORR. INHIBITOR DOSING VESSEL
020-V-201 INTERSTAGE RECEIVER.
020-V-202 WASH WATER SUCTION DRUM.
020-V-203 HIGH PR. RECEIVER.
20V-5 DEBUTANIZER-I O/H RECEIVER
20V-206 DEBUTANIZER-II O/H RECEIVER
20-V-7 KO VESSEL AFTER 20C-6
20-V-9 KO VESSEL AFTER 20 C-2
20V-210 WGC KOD
20V-208 CONDENSATE POT
20V-207 LP FLASH DRUM
20V-208 ATM. FLASH DRUM
20V03 WATER WASH OF LPG FROM MEROX ( REVIVED)
24N-C201 LPGTU AMINE ABSORBER COLUMN
24N-V201 AMINE SETTLER
24N-V202 CAUSTIC WASH VESSEL - I
24N-V203 CAUSTIC WASH VESSEL - II
24N-V204 WASH WATER VESSEL
24N-V205 SAND FILTER
24N-V206 COS VESSEL
24N-V207 COS SOLVENT STORAGE VESSEL
24N-V208 MEA STORAGE VESSEL
20-C107 GASOLINE SPLITTER COLUMN
20-C108 HEART CUT STRIPPER
20V-120 GSU REFLUX DRUM
20V-21 MP CONDENSATE VESSEL
20V-22 LP CONDENSATE VESSEL
115
19-V-22 CORR. INHIBITOR DOSING VESSEL
020-V-201 INTERSTAGE RECEIVER.
020-V-202 WASH WATER SUCTION DRUM.
020-V-203 HIGH PR. RECEIVER.
20V-5 DEBUTANIZER-I O/H RECEIVER
20V-206 DEBUTANIZER-II O/H RECEIVER
20-V-7 KO VESSEL AFTER 20C-6
20-V-9 KO VESSEL AFTER 20 C-2
20V-210 WGC KOD
20V-208 CONDENSATE POT
20V-207 LP FLASH DRUM
20V-208 ATM. FLASH DRUM
20V03 WATER WASH OF LPG FROM MEROX ( REVIVED)
24N-C201 LPGTU AMINE ABSORBER COLUMN
24N-V201 AMINE SETTLER
24N-V202 CAUSTIC WASH VESSEL - I
24N-V203 CAUSTIC WASH VESSEL - II
24N-V204 WASH WATER VESSEL
24N-V205 SAND FILTER
24N-V206 COS VESSEL
24N-V207 COS SOLVENT STORAGE VESSEL
24N-V208 MEA STORAGE VESSEL
20-C107 GASOLINE SPLITTER COLUMN
20-C108 HEART CUT STRIPPER
20V-120 GSU REFLUX DRUM
20V-21 MP CONDENSATE VESSEL
20V-22 LP CONDENSATE VESSEL
115
HEAT EXCHANGER NO NAME OF THE EQUIPMENT
19 E-2 FEED PRE HEAT EXCHANGER – LCO C/R FEED
19 E-3 A,B,C,D,E,F FEED PRE HEAT EXCHANGER – MCB/FEED.
19 E-4 MCB STEAM GENERATOR
19 E-5 A/B HEAT EXCHANGER – CLO/BFW
19 E-5 C/D HEAT EXCHANGER – CLO/BFW
19 E-6 UPPER CLO R/D COOLER – CLO/CW
19 E-6 LOWER CLO R/D COOLER – CLO/CW
19 E-7 HCO STEAM GENERATOR
19 E-9 LCO R/D COOLER
19 E-11 HN R/D COOLER
19 E-13 A/B/C TRIM COOLER 19C-1 O/H
19 E-15 FEED PRE HEAT EXCHANGER – FEED/HN C/R.
19 E-17 FEED PRE HEAT EXCHANGER – FEED/LCO C/R.
19 E-19 FLO COOLER
19 E-21 FEED PRE HEAT EXCHANGER – MCB/FEED
20 E-201 20-K-201 INTER STAGE COOLER
20 E-203 HP TRIM COOLER
20 E-4 20C-1 INTER COOLER (ABSORBANT)
20 E-5 LEAN LCO EX E-7/RICH LCO EX 20 C-2
20 E-6 CW/LEAN LCO
20 E-7 LEAN LCO/STRIPPER 20 C-3 REBOILER
20 E-220 STRIPPER 20C-3 STEAM REBOILER
20 E-9 ST. NAPHTHA AFTER 20 E-8/ STRIPPER FEED
20 E-11 STABILISED GASOLINE COOLER
20 E-12 HCO C/R / STABILIZER REBOILER
116
19 E-2 FEED PRE HEAT EXCHANGER – LCO C/R FEED
19 E-3 A,B,C,D,E,F FEED PRE HEAT EXCHANGER – MCB/FEED.
19 E-4 MCB STEAM GENERATOR
19 E-5 A/B HEAT EXCHANGER – CLO/BFW
19 E-5 C/D HEAT EXCHANGER – CLO/BFW
19 E-6 UPPER CLO R/D COOLER – CLO/CW
19 E-6 LOWER CLO R/D COOLER – CLO/CW
19 E-7 HCO STEAM GENERATOR
19 E-9 LCO R/D COOLER
19 E-11 HN R/D COOLER
19 E-13 A/B/C TRIM COOLER 19C-1 O/H
19 E-15 FEED PRE HEAT EXCHANGER – FEED/HN C/R.
19 E-17 FEED PRE HEAT EXCHANGER – FEED/LCO C/R.
19 E-19 FLO COOLER
19 E-21 FEED PRE HEAT EXCHANGER – MCB/FEED
20 E-201 20-K-201 INTER STAGE COOLER
20 E-203 HP TRIM COOLER
20 E-4 20C-1 INTER COOLER (ABSORBANT)
20 E-5 LEAN LCO EX E-7/RICH LCO EX 20 C-2
20 E-6 CW/LEAN LCO
20 E-7 LEAN LCO/STRIPPER 20 C-3 REBOILER
20 E-220 STRIPPER 20C-3 STEAM REBOILER
20 E-9 ST. NAPHTHA AFTER 20 E-8/ STRIPPER FEED
20 E-11 STABILISED GASOLINE COOLER
20 E-12 HCO C/R / STABILIZER REBOILER
116
EQUIPMENT NO NAME OF THE EQUIPMENT
20 E-14 GASOLINE / CW
20 E-14 A/B LPG / CW
20 E-14 A/B LPG / CW
20 E-216 A/B 20C-4 FEED PRODUCT
20 E-217 A/B 20C-205 FEED PRODUCT
20 E-219 SOUR GAS / CW
20 E-221 LCO CR/ 20C-205 REBOILER
20 E-222 HCO CR/ 20C-205 REBOILER
20 E-224A/B 20C-205 OVERHEAD CONDENSER
20 E-225 STEAM/CW
20E21A/B SPLITTER FEED / SPLITTER BOTTOM
20E22 SPLITTER REBOILER
20E23 HEART CUT STRIPPER REBOILER
20E24A/B HEART CUT COOLER
20E25A/B SPLITTER OVERHEAD COOLER
20E28A/B SPLITTER OVERHEAD CONDENSER
20E27 LP CONDENSATE FLASH VESSEL VENT CONDENSER
24N-E201 AMINE COOLER
117
20 E-14 GASOLINE / CW
20 E-14 A/B LPG / CW
20 E-14 A/B LPG / CW
20 E-216 A/B 20C-4 FEED PRODUCT
20 E-217 A/B 20C-205 FEED PRODUCT
20 E-219 SOUR GAS / CW
20 E-221 LCO CR/ 20C-205 REBOILER
20 E-222 HCO CR/ 20C-205 REBOILER
20 E-224A/B 20C-205 OVERHEAD CONDENSER
20 E-225 STEAM/CW
20E21A/B SPLITTER FEED / SPLITTER BOTTOM
20E22 SPLITTER REBOILER
20E23 HEART CUT STRIPPER REBOILER
20E24A/B HEART CUT COOLER
20E25A/B SPLITTER OVERHEAD COOLER
20E28A/B SPLITTER OVERHEAD CONDENSER
20E27 LP CONDENSATE FLASH VESSEL VENT CONDENSER
24N-E201 AMINE COOLER
117
AIR COOLER MOTOR NO NAME OF AIR COOLER
19EM-112 A TO H – 16 NOS. 19C-1 OVER HEAD AIR COOLER
19EM-125 – 2 NOS LCO CR AIR COOLER
19EM-122 – 3 NOS. HN CR AIR COOLER
19EM-8 – 2 NOS. HN R/D, HN CR AIR COOLER
20EM-13 – 8 NOS. 20C-4 OVERHEAD AIR COOLER
20EM-218 – 2 NOS. WGC INTERSTAGE AIR COOLER
20EM-223 – 4 NOS. 20C-205 OVERHEAD AIR COOLER
20EM-202 – 8 NOS. HP SEPERATOR AIR COOLER
20ACM-1 – 6 NOS. GSU AIR COOLER
PUMP DETAILS
118
SR NO TAG NUMBER SERVICE CAP. NM
3
/HR DIS. PR KG/CM
2
G
1 19-P-02A Raw Oil 118 17.1
2 19-P-02B Raw Oil 118 17.1
3 19-P-102C Raw Oil 118 17.1
4 19-P-103A /B MCB 495 10
5 19-P-4A/B CLO 25.0 9.04
6 19-P-5A LCO Product 21.07 11.9
7 019-P-106A/B HCO C/R 465.6 10.4
8 019-P-7A/B HN Product 23.9 9.1
9 19-P-108A/B LCO C/R 210 11.2
19EM-112 A TO H – 16 NOS. 19C-1 OVER HEAD AIR COOLER
19EM-125 – 2 NOS LCO CR AIR COOLER
19EM-122 – 3 NOS. HN CR AIR COOLER
19EM-8 – 2 NOS. HN R/D, HN CR AIR COOLER
20EM-13 – 8 NOS. 20C-4 OVERHEAD AIR COOLER
20EM-218 – 2 NOS. WGC INTERSTAGE AIR COOLER
20EM-223 – 4 NOS. 20C-205 OVERHEAD AIR COOLER
20EM-202 – 8 NOS. HP SEPERATOR AIR COOLER
20ACM-1 – 6 NOS. GSU AIR COOLER
PUMP DETAILS
118
SR NO TAG NUMBER SERVICE CAP. NM
3
/HR DIS. PR KG/CM
2
G
1 19-P-02A Raw Oil 118 17.1
2 19-P-02B Raw Oil 118 17.1
3 19-P-102C Raw Oil 118 17.1
4 19-P-103A /B MCB 495 10
5 19-P-4A/B CLO 25.0 9.04
6 19-P-5A LCO Product 21.07 11.9
7 019-P-106A/B HCO C/R 465.6 10.4
8 019-P-7A/B HN Product 23.9 9.1
9 19-P-108A/B LCO C/R 210 11.2
PUMP DETAILS
SR NO TAG NUMBER SERVICE CAP. NM
3
/HR DIS. PR KG/CM
2
G
10 019-P-09A/B/C MF Reflux 51.5 7.2
11 019-P-10A Unst. Gasoline 48 18.8
12 019-P-12A /B Sour Water 15 6.2
13 019-P-12C Sour Water 30 6.2
14 019-P-14A/B/C BFW 50 30
15 019-P-15A /B HN C/R 230 8.7
16 019-P-16A/B Ahurlan DOSING PUMP
17 019-P-25A/B Raw Oil 272.3 16.6
18 20-P-2A/B WGC Wash Water 17.7 9.8
19 20-P-203A/B Water+HC 20 18.5
20 20-P-4A/B/204C Naphtha 176 20.1
21 20-P-205A/B Naphtha 190.7 20.2
22 20-P-6A/B Gasoline 46.1 17.2
23 20-P-7A/B LCO 19.4 16.1
24 20-P-8A/B LPG C/R 96.9 15.1
25 20-P-9A/B/209C LPG R/D 33.6 20.9
26 20-P-211A/B Boot Water 18.3 20.3
27 20-P-212 WGC KOD pump 5 2.9
119
SR NO TAG NUMBER SERVICE CAP. NM
3
/HR DIS. PR KG/CM
2
G
10 019-P-09A/B/C MF Reflux 51.5 7.2
11 019-P-10A Unst. Gasoline 48 18.8
12 019-P-12A /B Sour Water 15 6.2
13 019-P-12C Sour Water 30 6.2
14 019-P-14A/B/C BFW 50 30
15 019-P-15A /B HN C/R 230 8.7
16 019-P-16A/B Ahurlan DOSING PUMP
17 019-P-25A/B Raw Oil 272.3 16.6
18 20-P-2A/B WGC Wash Water 17.7 9.8
19 20-P-203A/B Water+HC 20 18.5
20 20-P-4A/B/204C Naphtha 176 20.1
21 20-P-205A/B Naphtha 190.7 20.2
22 20-P-6A/B Gasoline 46.1 17.2
23 20-P-7A/B LCO 19.4 16.1
24 20-P-8A/B LPG C/R 96.9 15.1
25 20-P-9A/B/209C LPG R/D 33.6 20.9
26 20-P-211A/B Boot Water 18.3 20.3
27 20-P-212 WGC KOD pump 5 2.9
119
SR NO TAG NUMBER SERVICE CAP. NM
3
/HR DIS. PR KG/CM
2
G
28 20-P-213A/B LPG C/R 80.8 15.3
29 20-P-214A/B LPG R/D 67.2 21
30 20-P-215A/B LP Condesate 45 7.84
31 20 P 18A/B HCN Pump 99.7 29.3
32 20 P 15A/B Heart Cut Pump 27.9 8.5
33 20 P 16A/B GSU REFLUX 145.6 10.2
34 20 P 17A/B Condensate Pump 35.5 7.0
35 20 P 19A/B LCN Pump 24.7 9.6
36 24NP-202A/B Caustic Pump I 38.4 19.7
37 24NP-204 Wash Water Pump 38.4 16.6
38 24NP-207A/B COS Solvent 22.0 18.6
39 24NP-201A/B Lean Amine Pump 8.3 21.7
40 24NP-209A/B MEA Transfer Pump 11 2.4
41 24NP-203A/B Caustic II 38.4 16.9
42 24NP-205A/B Wash Water 38.5 16.6
43 24NP-206A/B COS Makeup 19.0 17.5
120
3
/HR DIS. PR KG/CM
2
G
28 20-P-213A/B LPG C/R 80.8 15.3
29 20-P-214A/B LPG R/D 67.2 21
30 20-P-215A/B LP Condesate 45 7.84
31 20 P 18A/B HCN Pump 99.7 29.3
32 20 P 15A/B Heart Cut Pump 27.9 8.5
33 20 P 16A/B GSU REFLUX 145.6 10.2
34 20 P 17A/B Condensate Pump 35.5 7.0
35 20 P 19A/B LCN Pump 24.7 9.6
36 24NP-202A/B Caustic Pump I 38.4 19.7
37 24NP-204 Wash Water Pump 38.4 16.6
38 24NP-207A/B COS Solvent 22.0 18.6
39 24NP-201A/B Lean Amine Pump 8.3 21.7
40 24NP-209A/B MEA Transfer Pump 11 2.4
41 24NP-203A/B Caustic II 38.4 16.9
42 24NP-205A/B Wash Water 38.5 16.6
43 24NP-206A/B COS Makeup 19.0 17.5
120
PSV DETAILS
SL.
No.
Location Set.
Press.
Discharge Isolation Facility
01. 19PSV-1 19 V-1 TOP 4.218 OPEN TO ATM. NO ISOLATION
02. 19PSV-2 19 V-2 TOP 4.218 OPEN TO ATM. NO ISOLATION
03. 19PSV-6 S H STEAM EX 19F-1 15.0 OPEN TO ATM NO ISOLATION
04. 19PSV-7 19F-1 COIL O/L(HC) 14.76 OPEN TO 19C-1 ISOLATION BOTH SIDES
05. 19PSV-9 19 E-3 SLURRY SIDE 11.24 19FRC-135 D/S LINE BOTH SIDE ISLATION B/VS
06. 19PSV-10A 19E-4 STEAM SIDE 15.46 OPEN TO ATM. NO ISOLATION
07. 19PSV-10B 19E-4 STEAM SIDE 15.46 OPEN TO ATM. NO ISOLATION
08. 19PSV-12A 19E-7 STEAM SIDE 15.46 OPEN TO ATM. NO ISOLATION
09. 19PSV-12B 19 E-7 STEAM SIDE 15.46 OPEN TO ATM. NO ISOLATION
10. 19PSV-11 19 E-4 SLURRY SIDE 11.24 JOINS 19FRC-135 D/S BOTH SIDE ISOLATION B/Vs.
11. 19PSV-3713A 19C-1 O/H VAPORS 3.16 OPEN TO FLARE BOTH SIDE ISOLATION B/V/s.
12. 19PSV-3713B 19C-1 O/H VAPORS 3.32 OPEN TO FLARE BOTH SIDE ISOLATION B/V/s.
13. 19PSV-3713C 19C-1 O/H VAPORS 3.32 OPEN TO FLARE BOTH SIDE ISOLATION B/V/s.
14. 19PSV-3713D 19C-1 O/H VAPORS 3.32 OPEN TO FLARE BOTH SIDE ISOLATION B/V/s.
15. 19PSV-3713E 19C-1 O/H VAPORS 3.16 OPEN TO FLARE BOTH SIDE ISOLATION B/V/s.
16. 19PSV-14 19 V-5O/H RECEIVER 3.7 OPEN TO FLARE BOTH SIDE ISOLATION B/V/s.
17. 19PSV-17 RAW OIL CIRCUIT 19.33 OPEN TO SLURRY RETURN BOTH SIDE ISOLATION VALVE
18. 19PSV-15 BOILED CBD 3.50 OPEN TO ATM. NO ISOLATION
19. 19PSV-XXXX 19V-101 7.0 OPEN TO FLARE BOTH SIDE ISOLATION B/V/s.
20. 19PSV-0301A/B 19F-2 9.0 OPEN TO FLARE BOTH SIDE ISOLATION B/V/s.
21. 19PSV-0501 19V-124 24.0 OPEN TO FLARE BOTH SIDE ISOLATION B/V/s.
22. 19PSV-0243 19K-101 SEALING STEAM 1.1 OPEN TO ATM. U/S SIDE ISOLATION
23. 19PSV-0221A/B 19P-127A/B 18.5 OPEN TO CONSOLE BOTH SIDE ISOLATION B/V/s.
121
SL.
No.
Location Set.
Press.
Discharge Isolation Facility
01. 19PSV-1 19 V-1 TOP 4.218 OPEN TO ATM. NO ISOLATION
02. 19PSV-2 19 V-2 TOP 4.218 OPEN TO ATM. NO ISOLATION
03. 19PSV-6 S H STEAM EX 19F-1 15.0 OPEN TO ATM NO ISOLATION
04. 19PSV-7 19F-1 COIL O/L(HC) 14.76 OPEN TO 19C-1 ISOLATION BOTH SIDES
05. 19PSV-9 19 E-3 SLURRY SIDE 11.24 19FRC-135 D/S LINE BOTH SIDE ISLATION B/VS
06. 19PSV-10A 19E-4 STEAM SIDE 15.46 OPEN TO ATM. NO ISOLATION
07. 19PSV-10B 19E-4 STEAM SIDE 15.46 OPEN TO ATM. NO ISOLATION
08. 19PSV-12A 19E-7 STEAM SIDE 15.46 OPEN TO ATM. NO ISOLATION
09. 19PSV-12B 19 E-7 STEAM SIDE 15.46 OPEN TO ATM. NO ISOLATION
10. 19PSV-11 19 E-4 SLURRY SIDE 11.24 JOINS 19FRC-135 D/S BOTH SIDE ISOLATION B/Vs.
11. 19PSV-3713A 19C-1 O/H VAPORS 3.16 OPEN TO FLARE BOTH SIDE ISOLATION B/V/s.
12. 19PSV-3713B 19C-1 O/H VAPORS 3.32 OPEN TO FLARE BOTH SIDE ISOLATION B/V/s.
13. 19PSV-3713C 19C-1 O/H VAPORS 3.32 OPEN TO FLARE BOTH SIDE ISOLATION B/V/s.
14. 19PSV-3713D 19C-1 O/H VAPORS 3.32 OPEN TO FLARE BOTH SIDE ISOLATION B/V/s.
15. 19PSV-3713E 19C-1 O/H VAPORS 3.16 OPEN TO FLARE BOTH SIDE ISOLATION B/V/s.
16. 19PSV-14 19 V-5O/H RECEIVER 3.7 OPEN TO FLARE BOTH SIDE ISOLATION B/V/s.
17. 19PSV-17 RAW OIL CIRCUIT 19.33 OPEN TO SLURRY RETURN BOTH SIDE ISOLATION VALVE
18. 19PSV-15 BOILED CBD 3.50 OPEN TO ATM. NO ISOLATION
19. 19PSV-XXXX 19V-101 7.0 OPEN TO FLARE BOTH SIDE ISOLATION B/V/s.
20. 19PSV-0301A/B 19F-2 9.0 OPEN TO FLARE BOTH SIDE ISOLATION B/V/s.
21. 19PSV-0501 19V-124 24.0 OPEN TO FLARE BOTH SIDE ISOLATION B/V/s.
22. 19PSV-0243 19K-101 SEALING STEAM 1.1 OPEN TO ATM. U/S SIDE ISOLATION
23. 19PSV-0221A/B 19P-127A/B 18.5 OPEN TO CONSOLE BOTH SIDE ISOLATION B/V/s.
121
122
SL.
No.
Location Set.
Press.
Discharge Isolation Facility
24. 19PSV-0521 19K-101 SURFACE
CONDENSER
OPEN TO ATM. ISOLATION B/Vs IS AT U/S
25. 19PSV-0222 19PT-127 19K-101 LOP
TURBINE
5.0 OPEN TO ATM. ISOLATION B/Vs IS AT U/S
26. 19PSV-0226 19PT-130 19K-101 CEP
TURBINE
5.0 OPEN TO ATM. ISOLATION B/Vs IS AT U/S
27. 19PSV-3201/02 19E-3A/B/C/D 18.1 19C-1 BOTH SIDE ISOLATION
28. 19PSV-21 BFW AT 19PRC-311 22.97 OPEN TO ATM. ISOLATION B/Vs IS AT U/S
29. 19PSV-22 19 V-23 FG KOD POT.
OPEN TO FLARE BOTH SIDE ISOLATION
30. 19PSV201A/B/C/D MAB DISCHARGE 4.2/4.2/4.4
1/.4..41
OPEN TO ATM. ISOLATION B/Vs BOTH SIDE
31. 19PSV-3401A/B CLO FILTER 12.2 19C-1 BOTH SIDE ISOLATION
32. 19PSV-3403/04 HCO FILTER 17.0 19C-1 BOTH SIDE ISOLATION
33. 19PSV-1301A/B 19E-145 ECONOMIZER 35.0 OPEN TO ATM. U/S SIDE ISOLATION
34 19TSV-0201/0202 19K-101 SURFACE
CONDENSER
7.0 OPEN TO ATM. U/S SIDE ISOLATION
35. 19TSV-0223/0202 19K-101 EJECTER
CONDENSER
7.0 OPEN TO ATM. U/S SIDE ISOLATION
36. 20PSV-4 20 V-5 TOP 14.06 OPEN TO FLARE NO ISOLATION B/P GIVEN
37. 20PSV-11 20 C-6 AMINE ABSORBER 7.7 OPEN TO FLARE NO ISOLATION B/Ps GIVEN.
38. 20PSV-3901A/B 20V-201 10.0 OPEN TO FLARE BOTH SIDE ISOLATION
39. 20PSV-4102A/B 20V-203 16.2 OPEN TO FLARE BOTH SIDE ISOLATION
40. 20PSV-4201 20V-208 17.0 OPEN TO ATM. U/S SIDE ISOLATION
41. 20PSV-12A/B 20V-9 7.7 OPEN TO FLARE BOTH SIDE ISOLATION
42. 20PSV-3A/B 20C-4 14.0 OPEN TO FLARE BOTH SIDE ISOLATION
43. 20PSV-4601A/B 20P-209C 25.6 OPEN TO FLARE BOTH SIDE ISOLATION
SL.
No.
Location Set.
Press.
Discharge Isolation Facility
24. 19PSV-0521 19K-101 SURFACE
CONDENSER
OPEN TO ATM. ISOLATION B/Vs IS AT U/S
25. 19PSV-0222 19PT-127 19K-101 LOP
TURBINE
5.0 OPEN TO ATM. ISOLATION B/Vs IS AT U/S
26. 19PSV-0226 19PT-130 19K-101 CEP
TURBINE
5.0 OPEN TO ATM. ISOLATION B/Vs IS AT U/S
27. 19PSV-3201/02 19E-3A/B/C/D 18.1 19C-1 BOTH SIDE ISOLATION
28. 19PSV-21 BFW AT 19PRC-311 22.97 OPEN TO ATM. ISOLATION B/Vs IS AT U/S
29. 19PSV-22 19 V-23 FG KOD POT.
OPEN TO FLARE BOTH SIDE ISOLATION
30. 19PSV201A/B/C/D MAB DISCHARGE 4.2/4.2/4.4
1/.4..41
OPEN TO ATM. ISOLATION B/Vs BOTH SIDE
31. 19PSV-3401A/B CLO FILTER 12.2 19C-1 BOTH SIDE ISOLATION
32. 19PSV-3403/04 HCO FILTER 17.0 19C-1 BOTH SIDE ISOLATION
33. 19PSV-1301A/B 19E-145 ECONOMIZER 35.0 OPEN TO ATM. U/S SIDE ISOLATION
34 19TSV-0201/0202 19K-101 SURFACE
CONDENSER
7.0 OPEN TO ATM. U/S SIDE ISOLATION
35. 19TSV-0223/0202 19K-101 EJECTER
CONDENSER
7.0 OPEN TO ATM. U/S SIDE ISOLATION
36. 20PSV-4 20 V-5 TOP 14.06 OPEN TO FLARE NO ISOLATION B/P GIVEN
37. 20PSV-11 20 C-6 AMINE ABSORBER 7.7 OPEN TO FLARE NO ISOLATION B/Ps GIVEN.
38. 20PSV-3901A/B 20V-201 10.0 OPEN TO FLARE BOTH SIDE ISOLATION
39. 20PSV-4102A/B 20V-203 16.2 OPEN TO FLARE BOTH SIDE ISOLATION
40. 20PSV-4201 20V-208 17.0 OPEN TO ATM. U/S SIDE ISOLATION
41. 20PSV-12A/B 20V-9 7.7 OPEN TO FLARE BOTH SIDE ISOLATION
42. 20PSV-3A/B 20C-4 14.0 OPEN TO FLARE BOTH SIDE ISOLATION
43. 20PSV-4601A/B 20P-209C 25.6 OPEN TO FLARE BOTH SIDE ISOLATION
SL.
No.
Location Set.
Press.
Discharge Isolation Facility
44. 20PSV-6501A/B/C 20V-210 3.5/3.675/3
.675
OPEN TO FLARE BOTH SIDE ISOLATION
45. 20PSV-6601A/B 20K-201 21.0 OPEN TO FLARE BOTH SIDE ISOLATION
46. 20PSV-6801A/B 20C-205 14.1 OPEN TO FLARE BOTH SIDE ISOLATION
47. 20PSV-6901 20V-206 14.1 OPEN TO FLARE BOTH SIDE ISOLATION
48. 20PSV-6902A/B 20P-214A/B 25.6 20V-206 BOTH SIDE ISOLATION
49. 20PSV-7001A/B 20V-207 5.0 OPEN TO ATM. U/S SIDE ISOLATION
50. 20PSV-6701A/B LCO CR EX 20E-221 12.0 19C-1 BOTH SIDE ISOLATION
51. 20PSV-7121/22 20P-241A/B 20 K-201 LOP 10.7 OPEN TO CONSOLE BOTH SIDE ISOLATION
52. 20PSV-7322/23 20PT-241/243 LOP/CEP
TURBINE EXHAUST
5.0 OPEN TO ATM. U/S SIDE ISOLATION
53. 20PSV-7321/24 20K-201 EJECTOR STEAM 14.5 OPEN TO ATM. U/S SIDE ISOLATION
54. 20PSV-7351 20K-201 SURFACE
CONDENSER
OPEN TO ATM. NO ISOLATION
55. 20TSV-3901 20E-201A/B 7.0 OPEN TO ATM. U/S SIDE ISOLATION
56. 20TSV-4101 20E-203A/B 16.2 OPEN TO ATM. U/S SIDE ISOLATION
57. 20TSV-4401 20E-219 16.2 OPEN TO ATM. U/S SIDE ISOLATION
58. 20TSV-451 20E-14A/B 9.5 OPEN TO ATM. U/S SIDE ISOLATION
59. 20TSV-4601 20E-214C/D 9.5 OPEN TO ATM. U/S SIDE ISOLATION
60. 20TSV-6601 20K-201 SURFACE
CONDENSER
7.0 OPEN TO ATM. U/S SIDE ISOLATION
61. 20TSV-6602 20K-201 SURFACE
CONDENSER
7.0 OPEN TO ATM. U/S SIDE ISOLATION
62. 20TSV-6801 20E-224A/B 11.2 OPEN TO ATM. U/S SIDE ISOLATION
63. 20TSV-7001 20E-225 7.0 OPEN TO ATM. U/S SIDE ISOLATION
123
No.
Location Set.
Press.
Discharge Isolation Facility
44. 20PSV-6501A/B/C 20V-210 3.5/3.675/3
.675
OPEN TO FLARE BOTH SIDE ISOLATION
45. 20PSV-6601A/B 20K-201 21.0 OPEN TO FLARE BOTH SIDE ISOLATION
46. 20PSV-6801A/B 20C-205 14.1 OPEN TO FLARE BOTH SIDE ISOLATION
47. 20PSV-6901 20V-206 14.1 OPEN TO FLARE BOTH SIDE ISOLATION
48. 20PSV-6902A/B 20P-214A/B 25.6 20V-206 BOTH SIDE ISOLATION
49. 20PSV-7001A/B 20V-207 5.0 OPEN TO ATM. U/S SIDE ISOLATION
50. 20PSV-6701A/B LCO CR EX 20E-221 12.0 19C-1 BOTH SIDE ISOLATION
51. 20PSV-7121/22 20P-241A/B 20 K-201 LOP 10.7 OPEN TO CONSOLE BOTH SIDE ISOLATION
52. 20PSV-7322/23 20PT-241/243 LOP/CEP
TURBINE EXHAUST
5.0 OPEN TO ATM. U/S SIDE ISOLATION
53. 20PSV-7321/24 20K-201 EJECTOR STEAM 14.5 OPEN TO ATM. U/S SIDE ISOLATION
54. 20PSV-7351 20K-201 SURFACE
CONDENSER
OPEN TO ATM. NO ISOLATION
55. 20TSV-3901 20E-201A/B 7.0 OPEN TO ATM. U/S SIDE ISOLATION
56. 20TSV-4101 20E-203A/B 16.2 OPEN TO ATM. U/S SIDE ISOLATION
57. 20TSV-4401 20E-219 16.2 OPEN TO ATM. U/S SIDE ISOLATION
58. 20TSV-451 20E-14A/B 9.5 OPEN TO ATM. U/S SIDE ISOLATION
59. 20TSV-4601 20E-214C/D 9.5 OPEN TO ATM. U/S SIDE ISOLATION
60. 20TSV-6601 20K-201 SURFACE
CONDENSER
7.0 OPEN TO ATM. U/S SIDE ISOLATION
61. 20TSV-6602 20K-201 SURFACE
CONDENSER
7.0 OPEN TO ATM. U/S SIDE ISOLATION
62. 20TSV-6801 20E-224A/B 11.2 OPEN TO ATM. U/S SIDE ISOLATION
63. 20TSV-7001 20E-225 7.0 OPEN TO ATM. U/S SIDE ISOLATION
123
SL.
No.
Location Set.
Press.
Discharge Isolation Facility
64. 24NPSV-1101 24N-C201 25.6 OPEN TO FLARE BOTH SIDE ISOLATION
65. 24NPSV-1301 24N-V204 25.6 OPEN TO FLARE BOTH SIDE ISOLATION
66. 24NPSV-1302 24N-V205 25.6 OPEN TO FLARE BOTH SIDE ISOLATION
67. 24NTSV-1102 24NE-201 20.0 OPEN TO ATM. U/S SIDE ISOLATION
68. 24NPSV-1401A/B 24N-V208 3.5 OPEN TO ATM. U/S SIDE ISOLATION
69. 24NPSV-1402A/B 24N-V207 3.5 OPEN TO ATM. U/S SIDE ISOLATION
70. 20PSV-0801A/B 20C-107 – PILOT PSV 4.5 OPEN TO FLARE BOTH SIDE ISOLATION
71. 20PSV-1001A/B 20V-120 4.5 OPEN TO FLARE BOTH SIDE ISOLATION
72.
20P-18 DISCHARGE
BOTH SIDE ISOLATION
73 20V03 PSV HP SEPERATOR PSV
SHIFTED TO THIS
16.2 OPEN TO FLARE BOTH SIDE ISOLATION
124
No.
Location Set.
Press.
Discharge Isolation Facility
64. 24NPSV-1101 24N-C201 25.6 OPEN TO FLARE BOTH SIDE ISOLATION
65. 24NPSV-1301 24N-V204 25.6 OPEN TO FLARE BOTH SIDE ISOLATION
66. 24NPSV-1302 24N-V205 25.6 OPEN TO FLARE BOTH SIDE ISOLATION
67. 24NTSV-1102 24NE-201 20.0 OPEN TO ATM. U/S SIDE ISOLATION
68. 24NPSV-1401A/B 24N-V208 3.5 OPEN TO ATM. U/S SIDE ISOLATION
69. 24NPSV-1402A/B 24N-V207 3.5 OPEN TO ATM. U/S SIDE ISOLATION
70. 20PSV-0801A/B 20C-107 – PILOT PSV 4.5 OPEN TO FLARE BOTH SIDE ISOLATION
71. 20PSV-1001A/B 20V-120 4.5 OPEN TO FLARE BOTH SIDE ISOLATION
72.
20P-18 DISCHARGE
BOTH SIDE ISOLATION
73 20V03 PSV HP SEPERATOR PSV
SHIFTED TO THIS
16.2 OPEN TO FLARE BOTH SIDE ISOLATION
124
Chemical
15.0 CHEMICALS, CATALYST & LUBE OILS
1. Corrosion inhibitor Anti Corrosive agent for 19C-1 O/H.
2. Hydrazine hydrate For Deaeration of BFW.
3. Morpholine For PH control of BFW.
4. Tri Sod. Phosphate Film former to avoid corrosion.
Catalyst
1. FCC catalyst (SBR-IM-1) – M/s JGC Used for catalytic cracking.
CORPORATION LIMITED, JAPAN
2. ZSM-5 Additives – M/s SUD CHEMIE Used for Propylene Maximization.
(Developed by IOCL R&D), INDIA
3. CO Promoter – M/s SUD CHEMIE Used for CO Combustion.
(Developed by IOCL R&D), INDIA
Lube Oil
1. Servo System – 68 For pump lubrication.
2. Servo prime – 46 T 20K-201 turbine Oil.
3. SP-32T 19K-101 turbine Oil, Pump seal pot
4. EXXONMOBIL DTE 25 SERIES Used as hydraulic oil for slide valves.
125
15.0 CHEMICALS, CATALYST & LUBE OILS
1. Corrosion inhibitor Anti Corrosive agent for 19C-1 O/H.
2. Hydrazine hydrate For Deaeration of BFW.
3. Morpholine For PH control of BFW.
4. Tri Sod. Phosphate Film former to avoid corrosion.
Catalyst
1. FCC catalyst (SBR-IM-1) – M/s JGC Used for catalytic cracking.
CORPORATION LIMITED, JAPAN
2. ZSM-5 Additives – M/s SUD CHEMIE Used for Propylene Maximization.
(Developed by IOCL R&D), INDIA
3. CO Promoter – M/s SUD CHEMIE Used for CO Combustion.
(Developed by IOCL R&D), INDIA
Lube Oil
1. Servo System – 68 For pump lubrication.
2. Servo prime – 46 T 20K-201 turbine Oil.
3. SP-32T 19K-101 turbine Oil, Pump seal pot
4. EXXONMOBIL DTE 25 SERIES Used as hydraulic oil for slide valves.
125
5. Resistance to Poison
FCCU CATALYST
Desired Properties:-
1.
Catalytic Performance
2. Fluidization Properties
3. Attrition Resistance
4. Thermal / Hydrothermal Stability
Feed molecule
Zeolite
126
FCCU CATALYST
Desired Properties:-
1.
Catalytic Performance
2. Fluidization Properties
3. Attrition Resistance
4. Thermal / Hydrothermal Stability
Feed molecule
Zeolite
126
Catalyst Properties :
Zeolite – Activity, selectivity, Product quality
Matrix – Alumina, Bottom cracking (Primary cracking of large molecules), Prevents N2/Vi attack &
guards Zeolite activity.
Binder (Silica / Silica-Alumina / clay) - Serves as a glue to hold Zeolite, matrix, clay together. Dilute
catalyst activity.
Filler - Clay (Kaoline–Al2(OH)2, Si2O5) provides desirable heat transfer characteristics that are
important in commercial FCC operations.
Binder & Filler provide physical integrity (Density, attrition resistance, particle size), necessary
mechanical strength & hardness to preserve the integrity of catalyst under severe regeneration
conditions required by process.
Catalyst Performance Evaluation :
ZSA/MSA: Matrix, Zeolite distribution, Correlates with activity
PV: Pore volume availability for cracking. Thermal deactivation decreases PV.
ABD : Very high Poor fluidization, Very low Cat. Loss
PSD : Indication of fluidization property. More 0-40 µ fraction, better fluidization, more catalyst loss
MAT : Standard VGO injected into fixed bed of catalyst. Conversion (221
0
C) is reported as MAT
Al
2O
3 : Bottom cracking ability
C : Coke on Regenerated Catalyst (CRC)
UCS : Indicator of Zeolite activity. Low UCS, more activity, more octane, C3
=
.
Rare earth : Improves Zeolite stability, High Gasoline, less octane
Ni/V : Present in heavier fraction of Vacuum column. Ni deposits on Matrix, promotes
dehydrogenation reaction, produces unstable olefins, Hence more dry gas & coke. V also promotes
dehydrogenation but 20-50% less than Ni. Unlike Ni, V migrates to inner pore & V2O5 melts at 690
0
C
causing collapse of Zeolite structure.
Grace Index = Ni + V/4, H2/Methane Ratio : <0.5 (MR FCCU)
Na2O : Reacts with Zeolite acid sites, decreases hydrothermal stability
127
Zeolite – Activity, selectivity, Product quality
Matrix – Alumina, Bottom cracking (Primary cracking of large molecules), Prevents N2/Vi attack &
guards Zeolite activity.
Binder (Silica / Silica-Alumina / clay) - Serves as a glue to hold Zeolite, matrix, clay together. Dilute
catalyst activity.
Filler - Clay (Kaoline–Al2(OH)2, Si2O5) provides desirable heat transfer characteristics that are
important in commercial FCC operations.
Binder & Filler provide physical integrity (Density, attrition resistance, particle size), necessary
mechanical strength & hardness to preserve the integrity of catalyst under severe regeneration
conditions required by process.
Catalyst Performance Evaluation :
ZSA/MSA: Matrix, Zeolite distribution, Correlates with activity
PV: Pore volume availability for cracking. Thermal deactivation decreases PV.
ABD : Very high Poor fluidization, Very low Cat. Loss
PSD : Indication of fluidization property. More 0-40 µ fraction, better fluidization, more catalyst loss
MAT : Standard VGO injected into fixed bed of catalyst. Conversion (221
0
C) is reported as MAT
Al
2O
3 : Bottom cracking ability
C : Coke on Regenerated Catalyst (CRC)
UCS : Indicator of Zeolite activity. Low UCS, more activity, more octane, C3
=
.
Rare earth : Improves Zeolite stability, High Gasoline, less octane
Ni/V : Present in heavier fraction of Vacuum column. Ni deposits on Matrix, promotes
dehydrogenation reaction, produces unstable olefins, Hence more dry gas & coke. V also promotes
dehydrogenation but 20-50% less than Ni. Unlike Ni, V migrates to inner pore & V2O5 melts at 690
0
C
causing collapse of Zeolite structure.
Grace Index = Ni + V/4, H2/Methane Ratio : <0.5 (MR FCCU)
Na2O : Reacts with Zeolite acid sites, decreases hydrothermal stability
127
Additives
Desired Properties:-
1.
Improves operational flexibility
2. Significant Economic Benefits
3. Quick response / performance
4. Easy to add / withdraw
Commonly used additives:
ZSM-5 – Increases gasoline octane, C3/C4 olefin yields
CO Promoter – Enhances CO Burning in Rg dense bed
Bottom Cracking Additives (BCA) – Upgrades bottom of the feed, Useful for units with higher Rg
temperature, higher bottom yield & frequent feed quality variation
SOX additives – Reduces SOX in Rg flue gas
Ni & V Passivators – Reduces detrimental effects of metals on product yields & catalyst health
GSR Additives – Reduces Sulfur in Gasoline products
Catalyst Deactivation
1. Catalyst deactivation by temperature: Activity remains stable in the region of 620-730
0
C. After
this point activity begins decreasing rapidly.
2. Steam deactivation: Hot regenerated catalyst is subject to breakage and deactivation if contacted
by large amounts of steam over extended period. If the velocity of steam is too high, attrition can
damage catalyst.
3. Torch oil: If not properly atomized, a high concentration of the oil can result in localized areas
hotter than seen by Rg TIs .This can also happen when oil is injected into a non fluidized stagnant
bed. Lower air rates as during startup can cause this. Therefore torch oil during startup should be
minimized.
4. Coke: Gets deposited after cracking. Contains 5-10% hydrogen with small quantities of S,N and
metals. Coke deactivates by blocking acid sites and at times the entire pore.
5. N2 : Basic N2 neutralizes acid sites. Temporary poison, produces Nox
6. Poison : Damages or weakens catalyst structure, Block acid sites, catalyze undesirable reaction12s8
Desired Properties:-
1.
Improves operational flexibility
2. Significant Economic Benefits
3. Quick response / performance
4. Easy to add / withdraw
Commonly used additives:
ZSM-5 – Increases gasoline octane, C3/C4 olefin yields
CO Promoter – Enhances CO Burning in Rg dense bed
Bottom Cracking Additives (BCA) – Upgrades bottom of the feed, Useful for units with higher Rg
temperature, higher bottom yield & frequent feed quality variation
SOX additives – Reduces SOX in Rg flue gas
Ni & V Passivators – Reduces detrimental effects of metals on product yields & catalyst health
GSR Additives – Reduces Sulfur in Gasoline products
Catalyst Deactivation
1. Catalyst deactivation by temperature: Activity remains stable in the region of 620-730
0
C. After
this point activity begins decreasing rapidly.
2. Steam deactivation: Hot regenerated catalyst is subject to breakage and deactivation if contacted
by large amounts of steam over extended period. If the velocity of steam is too high, attrition can
damage catalyst.
3. Torch oil: If not properly atomized, a high concentration of the oil can result in localized areas
hotter than seen by Rg TIs .This can also happen when oil is injected into a non fluidized stagnant
bed. Lower air rates as during startup can cause this. Therefore torch oil during startup should be
minimized.
4. Coke: Gets deposited after cracking. Contains 5-10% hydrogen with small quantities of S,N and
metals. Coke deactivates by blocking acid sites and at times the entire pore.
5. N2 : Basic N2 neutralizes acid sites. Temporary poison, produces Nox
6. Poison : Damages or weakens catalyst structure, Block acid sites, catalyze undesirable reaction12s8
FCCU PUMPS LUBE OIL GRADE
129
129
130
131
What is a Work Permit?
16.0 PERMIT SYSTEM
A safety clearance issued from Work Indenter (Issuer) to Executer(Receiver)
Issued in 2 parts –
Work Permit – in principle/general clearance for the entire execution period
Work Permit Clearance – specific clearance for actual execution job & time, limiting to 8hrs.
Standard in practice : OISD-STD-105 – Work Permit System
Types of Work Permit –
Cold Work: An activity which does not produce sufficient heat to ignite a flammable air - hydrocarbon
mixture or a flammable substance.
Hot Work : An activity that can produce a spark or flame or other source of ignition having sufficient
energy to cause ignition, where the potential for flammable vapors, gases, or dust exists.
Confined Space Entry
Working at Height
Excavation/Dyke Cutting /Road Cutting
Radiation work permit
132
16.0 PERMIT SYSTEM
A safety clearance issued from Work Indenter (Issuer) to Executer(Receiver)
Issued in 2 parts –
Work Permit – in principle/general clearance for the entire execution period
Work Permit Clearance – specific clearance for actual execution job & time, limiting to 8hrs.
Standard in practice : OISD-STD-105 – Work Permit System
Types of Work Permit –
Cold Work: An activity which does not produce sufficient heat to ignite a flammable air - hydrocarbon
mixture or a flammable substance.
Hot Work : An activity that can produce a spark or flame or other source of ignition having sufficient
energy to cause ignition, where the potential for flammable vapors, gases, or dust exists.
Confined Space Entry
Working at Height
Excavation/Dyke Cutting /Road Cutting
Radiation work permit
132
TERMINOLOGY
1. INDENTER : Generally Operations personnel; work requester
2. EXECUTER: Maintenance personnel
3. NOTIFICATION CREATION: By INDENTER(ISSUER)
4. NOTIFICATION DISPLAY: By INDENTER/EXECUTER
5. WORK PERMIT / CLEARNACE REQUESTER / RECEIVER: Authorized Maintenance personnel
6. WORK PERMIT / CLEARNACE ISSUER: Authorized Operations personnel
7. NOTIFICATION: Work request issued by INDENTER to EXECUTER
8. MAINTENANCE ORDER: Created against the notification by EXECUTER to their workgroup. PRs can
be generated through the same maintenance order, which will capture the cost implications.
9. WORK PERMIT REQUEST : Posted by EXECUTER (RECEIVER) on the basis of the notification or
maintenance order or work order.
10. WORK PERMIT ISSUE : INDENTER(ISSUER) issues to EXECUTER (RECEIVER) based on the WORK
PERMIT REQUEST. Max. duration- 7 days.
11. PERMIT CLEARANCE REQUEST: requested by EXECUTER to INDENTER for the day to day or shift to
shift work on against the work permit request
12. WORK PERMIT CLEARANCE ISSUE : Issued by INDENTER to EXECUTER against the work permit
clearance request. Max. duration 8 hrs.
13. WORK PERMIT CLEARANCE CLOSE: By INDENTER.
14. WORK PERMIT CLOSE: By INDENTER.
15. MAINTENANCE ORDER CLOSE: By EXECUTER
16. NOTIFICATION CLOSE: By INDENTER(ISSUER)
133
1. INDENTER : Generally Operations personnel; work requester
2. EXECUTER: Maintenance personnel
3. NOTIFICATION CREATION: By INDENTER(ISSUER)
4. NOTIFICATION DISPLAY: By INDENTER/EXECUTER
5. WORK PERMIT / CLEARNACE REQUESTER / RECEIVER: Authorized Maintenance personnel
6. WORK PERMIT / CLEARNACE ISSUER: Authorized Operations personnel
7. NOTIFICATION: Work request issued by INDENTER to EXECUTER
8. MAINTENANCE ORDER: Created against the notification by EXECUTER to their workgroup. PRs can
be generated through the same maintenance order, which will capture the cost implications.
9. WORK PERMIT REQUEST : Posted by EXECUTER (RECEIVER) on the basis of the notification or
maintenance order or work order.
10. WORK PERMIT ISSUE : INDENTER(ISSUER) issues to EXECUTER (RECEIVER) based on the WORK
PERMIT REQUEST. Max. duration- 7 days.
11. PERMIT CLEARANCE REQUEST: requested by EXECUTER to INDENTER for the day to day or shift to
shift work on against the work permit request
12. WORK PERMIT CLEARANCE ISSUE : Issued by INDENTER to EXECUTER against the work permit
clearance request. Max. duration 8 hrs.
13. WORK PERMIT CLEARANCE CLOSE: By INDENTER.
14. WORK PERMIT CLOSE: By INDENTER.
15. MAINTENANCE ORDER CLOSE: By EXECUTER
16. NOTIFICATION CLOSE: By INDENTER(ISSUER)
133
SAP T-CODES
1. IW21 – creation of Notification
2. IW23 – display of Notification.
3. YI21R - Request permit
4. YI21I - Issue/view/print permit status
5. YI22 - View permit details & print permit
6. YI24R - Request for clearance
7. YI24I - Issue clearance
8. YI21M – MIS view
9. IW22 - change/close Notification
134
1. IW21 – creation of Notification
2. IW23 – display of Notification.
3. YI21R - Request permit
4. YI21I - Issue/view/print permit status
5. YI22 - View permit details & print permit
6. YI24R - Request for clearance
7. YI24I - Issue clearance
8. YI21M – MIS view
9. IW22 - change/close Notification
134
VESSEL ENTRY PROCEDURE
In refinery operation a vessel is a process equipment normally used to hold temporarily or store various type of
process fluids. Hydrocarbon gases or liquids, steam or water, acids or alkalis are the prevailing fluids usually in use:
PREPARION OF VESSEL FOR MAINTENANCE & INSPECTION
Pump out the vessel content completely.
For heavy hydrocarbons dilute the material with flushing oil and pump out.
Drain out remaining portion of hydro carbons to CBD or OWS.
For Vessel handling chemicals, dilute the vessel content with water and then empty out to chemical sewage
system.
Close all the inlet and outlet valves of lines connected to the vessel, including SRV isolation valves, steam coils
(if provided).
Depressurize the vessel and purge the hydrocarbon vapors with steam/inert gas to flare. Then keep the vent
open.
Blind all inlet and outlet flanges of the vessel. With wedge opening towards vessel side.
Steam the vessel thoroughly. For vessel containing heavy hydrocarbons more steaming required.
Keep the vents and drains of instrument tapings open for flushing.
Ensure proper steaming by checking steam flow from from all opening provided.
Ensure proper draining of the condensates from the vessel for effective steaming and removal of effective
hydrocarbons.
Provide water supply to the vessel. Fill and overflow water from the vessel for about four hours.
Hot water wash may be given, if required, followed by cold water wash.
Drain the water completely.
Open the man way covers.
Blind steam and water supply lines.
Provide exhaust fans, as required for cooling and ventilation.
Gas test and calibration instrument : Test vessel inside and surrounding for presence of explosive gas mixture
(negative), oxygen (more than 19%), Hydrogen sulfide (negative).
135
In refinery operation a vessel is a process equipment normally used to hold temporarily or store various type of
process fluids. Hydrocarbon gases or liquids, steam or water, acids or alkalis are the prevailing fluids usually in use:
PREPARION OF VESSEL FOR MAINTENANCE & INSPECTION
Pump out the vessel content completely.
For heavy hydrocarbons dilute the material with flushing oil and pump out.
Drain out remaining portion of hydro carbons to CBD or OWS.
For Vessel handling chemicals, dilute the vessel content with water and then empty out to chemical sewage
system.
Close all the inlet and outlet valves of lines connected to the vessel, including SRV isolation valves, steam coils
(if provided).
Depressurize the vessel and purge the hydrocarbon vapors with steam/inert gas to flare. Then keep the vent
open.
Blind all inlet and outlet flanges of the vessel. With wedge opening towards vessel side.
Steam the vessel thoroughly. For vessel containing heavy hydrocarbons more steaming required.
Keep the vents and drains of instrument tapings open for flushing.
Ensure proper steaming by checking steam flow from from all opening provided.
Ensure proper draining of the condensates from the vessel for effective steaming and removal of effective
hydrocarbons.
Provide water supply to the vessel. Fill and overflow water from the vessel for about four hours.
Hot water wash may be given, if required, followed by cold water wash.
Drain the water completely.
Open the man way covers.
Blind steam and water supply lines.
Provide exhaust fans, as required for cooling and ventilation.
Gas test and calibration instrument : Test vessel inside and surrounding for presence of explosive gas mixture
(negative), oxygen (more than 19%), Hydrogen sulfide (negative).
135
Give “Entry Permit” through prescribed format, specifying all precautions to be taken for cleaning the vessel.
Ensure one person outside the vessel near manhole till person working inside.
Presence of “Pyrophoric iron sulfide “ when exposed to air reacts with oxygen generating sufficient heat to
become a source of ignition. These are to be removed under wet conditions to a safe area or buried to
prevent ignition.
Chemical solution wash to diffuse Pyrophoric iron may be used, if felt necessary.
Gas test with calibrated instrument: test vessel inside and surroundings for presence of explosive gas
mixture(negative), Oxygen (more than 19%).
Give “Entry Permit” through prescribed format, specifying all precautions to be taken for “Maintenance &
Inspection”.
136
Ensure one person outside the vessel near manhole till person working inside.
Presence of “Pyrophoric iron sulfide “ when exposed to air reacts with oxygen generating sufficient heat to
become a source of ignition. These are to be removed under wet conditions to a safe area or buried to
prevent ignition.
Chemical solution wash to diffuse Pyrophoric iron may be used, if felt necessary.
Gas test with calibrated instrument: test vessel inside and surroundings for presence of explosive gas
mixture(negative), Oxygen (more than 19%).
Give “Entry Permit” through prescribed format, specifying all precautions to be taken for “Maintenance &
Inspection”.
136
17.0 COMMUNICATION NETWROK
EMERGENCY TEPHONE NUMBERS
FIRE
ICOM DOT
FIRE CALL 7333/ 7777
FIRE CONTROL ROOM 7060/ 7070 2480149
FIRE STATION MATHURA 101,2462323
MEDICAL SERVICES
REFINERY HOSPITAL EMERGENCY
6444
2480150
FIRST AID REFINERY SITE 7200
REFINERY HOSPITAL INDOOR 6242
SWARNA JAYANTI HOSPITAL
SECURITY / ADMN.
3209177,2431164,2431165
CISF CONTROL ROOM 7300/7999
CISF TOWNSHIP GATE 6098/6099
REFINERY DISASTER C/R 7700/7500 2480172
REFINERY SHIFT MANAGER OFFICE 7400/7499 2480127
MAIN CONTROL ROOM 7053
FCC SHIFT INCHARGE 7423/7424 9219457028
FCCU SPNM 7404
137
EMERGENCY TEPHONE NUMBERS
FIRE
ICOM DOT
FIRE CALL 7333/ 7777
FIRE CONTROL ROOM 7060/ 7070 2480149
FIRE STATION MATHURA 101,2462323
MEDICAL SERVICES
REFINERY HOSPITAL EMERGENCY
6444
2480150
FIRST AID REFINERY SITE 7200
REFINERY HOSPITAL INDOOR 6242
SWARNA JAYANTI HOSPITAL
SECURITY / ADMN.
3209177,2431164,2431165
CISF CONTROL ROOM 7300/7999
CISF TOWNSHIP GATE 6098/6099
REFINERY DISASTER C/R 7700/7500 2480172
REFINERY SHIFT MANAGER OFFICE 7400/7499 2480127
MAIN CONTROL ROOM 7053
FCC SHIFT INCHARGE 7423/7424 9219457028
FCCU SPNM 7404
137
IMPORTANT TEPHONE NUMBERS
138
Ph. No. Location Ph. No. Location
7443 DMPN Office 8417 New MAB Floor
8417 New Comp. house local room 7078 IFO Pump House
7055 PRU/COB Control Room 7456/7457 OM&S I, RB PNE / SPNE
8021 Near 20K-1 Compressor 7401 CPNM
8022 FCCU Lift ground floor 7404 SPNM
8023 Near 20C-3 7004/7007/7743 Electrical Process substation
8024 Near Merox Compressor 7746/7776/7039 Electrical DHDS substation
8025 19C-1 Air Cooler 7041 Electrical NPRU substation
8026 At RCSV Platform 7660/7659/7658 QC Lab shift in charge
8027 At SCSV Platform 7707/7708/7709/7042 TPS
8028 At DDSV Platform 7031 MSQ
8029 At TPSV Platform 7742/7756 Water Block
7441 FCC Lift 7062 OHCU
8495 NLPGTU 7051/7412 AVU C/R
7056 Old Comp. Control room 7476 OM&S II
8031 GSU Near 20P-18A/B 7534 MECH MAINT.
8418 NWGC CEP 7819 ELEC MAINT.
8415 20P-2A 7627/7639 INST MAINT.
8419 New WGC Floor 7587/7575 CIVIL MAINT
138
Ph. No. Location Ph. No. Location
7443 DMPN Office 8417 New MAB Floor
8417 New Comp. house local room 7078 IFO Pump House
7055 PRU/COB Control Room 7456/7457 OM&S I, RB PNE / SPNE
8021 Near 20K-1 Compressor 7401 CPNM
8022 FCCU Lift ground floor 7404 SPNM
8023 Near 20C-3 7004/7007/7743 Electrical Process substation
8024 Near Merox Compressor 7746/7776/7039 Electrical DHDS substation
8025 19C-1 Air Cooler 7041 Electrical NPRU substation
8026 At RCSV Platform 7660/7659/7658 QC Lab shift in charge
8027 At SCSV Platform 7707/7708/7709/7042 TPS
8028 At DDSV Platform 7031 MSQ
8029 At TPSV Platform 7742/7756 Water Block
7441 FCC Lift 7062 OHCU
8495 NLPGTU 7051/7412 AVU C/R
7056 Old Comp. Control room 7476 OM&S II
8031 GSU Near 20P-18A/B 7534 MECH MAINT.
8418 NWGC CEP 7819 ELEC MAINT.
8415 20P-2A 7627/7639 INST MAINT.
8419 New WGC Floor 7587/7575 CIVIL MAINT
18.0 KNOW YOUR OWN SAFETY
PRINCIPAL CAUSES OF ACIDENTS:
1. RULES AND INSTRUCTIONS NOT OBSERVED :
Many accidents happen because the employees some times deviate from the established rules
and procedures.
2. IMPROPER TOOLS AND DEVICES :
Know your tools and use the proper tool for the job.
3. METHOD USED NOT SUAITABLE :
A Safe workman knows the correct method of performing his job.
4. PROTECTIVE DEVICES NOT USED :
Every employee should use all the safe guard, safety appliances or devices provided for his
protections.
5. LACK OF PROPER INSPECTION AND MAINTENANCE :
Machinery tools and all equipments should be regularly inspected and maintained by men using
them. Defects if any should immediately be reported and go rectified.
6. LOOSE CLOTHING :
This is a cause of many accidents particularly around moving machinery.
7. WORK WITHOUT AN AUTHORITY :
Take proper work permit for each job.
8. SHORT CUT:
Never adopt short cut or make shift arrangements.
9. POOR JUDGEMENT:
Safety is a matter of common sense which must be used.
10. HORSE PLAY :
Horse play is not allowed in the plant as it constitutes a contributory factor for the accidents.
139
PRINCIPAL CAUSES OF ACIDENTS:
1. RULES AND INSTRUCTIONS NOT OBSERVED :
Many accidents happen because the employees some times deviate from the established rules
and procedures.
2. IMPROPER TOOLS AND DEVICES :
Know your tools and use the proper tool for the job.
3. METHOD USED NOT SUAITABLE :
A Safe workman knows the correct method of performing his job.
4. PROTECTIVE DEVICES NOT USED :
Every employee should use all the safe guard, safety appliances or devices provided for his
protections.
5. LACK OF PROPER INSPECTION AND MAINTENANCE :
Machinery tools and all equipments should be regularly inspected and maintained by men using
them. Defects if any should immediately be reported and go rectified.
6. LOOSE CLOTHING :
This is a cause of many accidents particularly around moving machinery.
7. WORK WITHOUT AN AUTHORITY :
Take proper work permit for each job.
8. SHORT CUT:
Never adopt short cut or make shift arrangements.
9. POOR JUDGEMENT:
Safety is a matter of common sense which must be used.
10. HORSE PLAY :
Horse play is not allowed in the plant as it constitutes a contributory factor for the accidents.
139
1. Hydrogen Sulfide
MATERIAL SAFETY DATA :
Routes of Entry : Inhalation, skin & eyes
Effects of Exposure/ Inhalation Symptoms : If high concentrations are inhaled, hyperemia & respiratory
paralysis may occur. Very high concentration may produce pulmonary edema.
Skin & Eyes : Causes severe irritation.
Emergency Treatment:
Inhalation : Remove the victim to fresh air area, provide artificial respiration or Oxygen if needed.
Ingestion : Eyes : Irrigate with plenty of water for 15 mins.
Contact : Skin : Remove the contaminated clothing & wash the affected area with plenty of water & soap. Seek
medical aid immediately.
Permissible Exposure Limit (PPM) : 10, TLV (ACGIH) (PPM): 10, STEL (PPM) : 15
FIRE
Fire Extinguishing Media : Alcohol foam, CO2, DCP. Keep the containers cool by spraying water if exposed to
heat or flame. Flash back along vapor trail may occur.
First Aid Measures
Inhalation : Remove the victim to fresh air area, Provide artificial respiration or oxygen if needed.
Eyes : Irrigate with plenty of water for 15 min.
Skin : Remove the contaminated clothing and wash the affected area with plenty of water and soap. Seek
medical aid immediately.
Spills : Shut off leaks, if without risk. If in the liquid form, allow to vaporize. In case of gas leakage, pass
through FeCl3 solution with a trap in li9ne for prevention of back siphoning. Place cylinder in or near hood and
leave bleed off.
ADDITIONAL INFORMATION/ REFERENCES
Extremely hazardous, poisonous and flammable gas. An asphyxiant. Low concentration of 20-150 PPM causes
irritation of eyes. Slightly higher concentrations may cause irritation of upper respiratory tract. Exposures of
800-1000 PPM may be fatal in 30 mins. Higher concentrations are instantly fatal
140
MATERIAL SAFETY DATA :
Routes of Entry : Inhalation, skin & eyes
Effects of Exposure/ Inhalation Symptoms : If high concentrations are inhaled, hyperemia & respiratory
paralysis may occur. Very high concentration may produce pulmonary edema.
Skin & Eyes : Causes severe irritation.
Emergency Treatment:
Inhalation : Remove the victim to fresh air area, provide artificial respiration or Oxygen if needed.
Ingestion : Eyes : Irrigate with plenty of water for 15 mins.
Contact : Skin : Remove the contaminated clothing & wash the affected area with plenty of water & soap. Seek
medical aid immediately.
Permissible Exposure Limit (PPM) : 10, TLV (ACGIH) (PPM): 10, STEL (PPM) : 15
FIRE
Fire Extinguishing Media : Alcohol foam, CO2, DCP. Keep the containers cool by spraying water if exposed to
heat or flame. Flash back along vapor trail may occur.
First Aid Measures
Inhalation : Remove the victim to fresh air area, Provide artificial respiration or oxygen if needed.
Eyes : Irrigate with plenty of water for 15 min.
Skin : Remove the contaminated clothing and wash the affected area with plenty of water and soap. Seek
medical aid immediately.
Spills : Shut off leaks, if without risk. If in the liquid form, allow to vaporize. In case of gas leakage, pass
through FeCl3 solution with a trap in li9ne for prevention of back siphoning. Place cylinder in or near hood and
leave bleed off.
ADDITIONAL INFORMATION/ REFERENCES
Extremely hazardous, poisonous and flammable gas. An asphyxiant. Low concentration of 20-150 PPM causes
irritation of eyes. Slightly higher concentrations may cause irritation of upper respiratory tract. Exposures of
800-1000 PPM may be fatal in 30 mins. Higher concentrations are instantly fatal
140
2. Hydrogen
Gas : Appearance : Colorless, Odourless
Vapor Density (Air = 1) : 0.069
Flammability
Flammability : Yes, LEL (%V) : 4.1, UEL (%V) : 74.2, Auto ignition Temperature
o
C : 400
ADDITIONAL INFORMATION/ REFERENCES : Practically no toxicity, except that it is an asphyxiant. Highly
dangerous fire and severe explosion hazard when exposed to heat and flame and oxidizers. Flammable and
explosive when mixed with air, O2, Cl2. Vigorous exothermic reactions with Benzene + Nickel Catalyst, metals
(like Strontium, Potassium, Barium-above 300
o
C) ventilate at highest points.
3. CO
Appearance : Colourless, Odourless
Vapor Density (Air = 1) : 0.97
Flammability :Yes, LEL (%V) : 12.5%, UEL (%V) : 74.2%, Auto ignition Temperature
o
C : 608.8
Effects of Exposure/ Inhalation : Human systematic effects by inhalation, changes in psycho-physiological tests
and preventing hemoglobin from binding oxygen.
Emergency Treatment
Inhalation : Remove the victim to fresh air area. Support respiration, provide oxygen, if required.
Permissible Exposure Limit ppm : 50, TLV (ACGIH)ppm : 50, STEL, ppm : 400
EMERGENCY AND FIRST AID MEASURES
Inhalation : Remove victim from exposure to fresh air area, support respiration, provide O2 if required.
Skin : If burnt by liquid, treat as frostbite.
Eyes : Irrigate with plenty of water for 15 minutes. Seek medical aid immediately for all type of exposures.
ADDITIONAL INFORMATION/ REFERENCES
Acute case of poisoning resulting from brief exposure to high concentrations seldom results in any
permanent disability if recovery takes place. Auditory disturbances and contractions of the visual fields
have been demonstrated. Repeated exposure to low concentrations of the gas upto 100 ppm in air is
generally believed to cause no signs of poisoning of permanent damage. A very dangerous explosion
hazard when exposed to heat or flame.
141
Gas : Appearance : Colorless, Odourless
Vapor Density (Air = 1) : 0.069
Flammability
Flammability : Yes, LEL (%V) : 4.1, UEL (%V) : 74.2, Auto ignition Temperature
o
C : 400
ADDITIONAL INFORMATION/ REFERENCES : Practically no toxicity, except that it is an asphyxiant. Highly
dangerous fire and severe explosion hazard when exposed to heat and flame and oxidizers. Flammable and
explosive when mixed with air, O2, Cl2. Vigorous exothermic reactions with Benzene + Nickel Catalyst, metals
(like Strontium, Potassium, Barium-above 300
o
C) ventilate at highest points.
3. CO
Appearance : Colourless, Odourless
Vapor Density (Air = 1) : 0.97
Flammability :Yes, LEL (%V) : 12.5%, UEL (%V) : 74.2%, Auto ignition Temperature
o
C : 608.8
Effects of Exposure/ Inhalation : Human systematic effects by inhalation, changes in psycho-physiological tests
and preventing hemoglobin from binding oxygen.
Emergency Treatment
Inhalation : Remove the victim to fresh air area. Support respiration, provide oxygen, if required.
Permissible Exposure Limit ppm : 50, TLV (ACGIH)ppm : 50, STEL, ppm : 400
EMERGENCY AND FIRST AID MEASURES
Inhalation : Remove victim from exposure to fresh air area, support respiration, provide O2 if required.
Skin : If burnt by liquid, treat as frostbite.
Eyes : Irrigate with plenty of water for 15 minutes. Seek medical aid immediately for all type of exposures.
ADDITIONAL INFORMATION/ REFERENCES
Acute case of poisoning resulting from brief exposure to high concentrations seldom results in any
permanent disability if recovery takes place. Auditory disturbances and contractions of the visual fields
have been demonstrated. Repeated exposure to low concentrations of the gas upto 100 ppm in air is
generally believed to cause no signs of poisoning of permanent damage. A very dangerous explosion
hazard when exposed to heat or flame.
141
4. Nitrogen
Gas : Appearance : odourless, colourless, tasteless, compressed gas
Relative vapour density (air=1): 0.97
Inhalation : Unconsciousness, Weakness, Death.
First Aid : Fresh air, rest. Artificial respiration if indicated. Oxygen may be beneficial if administered by a
trained person on physician's advice, Refer for medical attention.
ADDITIONAL INFORMATION/ REFERENCES
High concentrations in the air cause a deficiency of oxygen with the risk of unconsciousness or death.
Check oxygen content before entering area. Effects are the result of oxygen deficiency. Do not attempt
rescue without air supplied respirator.
5. Caustic Soda
A strong base, appearance : White Flakes / Pellets , Odourless
Inhalation : Causes small burns to upper respiratory tract & lungs, mild nose irritation.
Ingestion : Causes severe damage to mucous membrane, Severe scaring or perforation may occur.
Eyes: Severe damage. Skin: Causes severe burns.
Emergency Treatment
Inhalation: Remove the victim from exposure. Support respiration, give oxygen, If necessary.
Ingestion: Give water or milk followed by dilute vinegar or fruit juice. Do not induce vomiting.
Skin: Wash the affected area with plenty of water and soap.
Eyes: Wash with plenty of water for 15 mins.
Seek medical aid immediately.
SPILLS : Sweep and collect without making dust. Wash the surface with plenty of water and soap.
142
Gas : Appearance : odourless, colourless, tasteless, compressed gas
Relative vapour density (air=1): 0.97
Inhalation : Unconsciousness, Weakness, Death.
First Aid : Fresh air, rest. Artificial respiration if indicated. Oxygen may be beneficial if administered by a
trained person on physician's advice, Refer for medical attention.
ADDITIONAL INFORMATION/ REFERENCES
High concentrations in the air cause a deficiency of oxygen with the risk of unconsciousness or death.
Check oxygen content before entering area. Effects are the result of oxygen deficiency. Do not attempt
rescue without air supplied respirator.
5. Caustic Soda
A strong base, appearance : White Flakes / Pellets , Odourless
Inhalation : Causes small burns to upper respiratory tract & lungs, mild nose irritation.
Ingestion : Causes severe damage to mucous membrane, Severe scaring or perforation may occur.
Eyes: Severe damage. Skin: Causes severe burns.
Emergency Treatment
Inhalation: Remove the victim from exposure. Support respiration, give oxygen, If necessary.
Ingestion: Give water or milk followed by dilute vinegar or fruit juice. Do not induce vomiting.
Skin: Wash the affected area with plenty of water and soap.
Eyes: Wash with plenty of water for 15 mins.
Seek medical aid immediately.
SPILLS : Sweep and collect without making dust. Wash the surface with plenty of water and soap.
142
6. Tri sodium phosphate
Physical and Chemical Properties Physical State: solid
Appearance and Odor: white/ off white crystals /powder/granules - odorless
Formula Weight: 380.12
Density: Specific Gravity (H20=J, at 4 0C): 1.62 g/cm pH:
Water Solubility: soluble
Acute Effects
Inhalation: May cause irritation of the respiratory tract with burning pain in the nose and throat,
coughing, wheezing, shortness of breath and pulmonary edema.
Eye: May cause severe eye irritation. May result in corneal injury.
Skin: May cause severe irritation and possible burns.
Ingestion: May cause severe gastrointestinal tract irritation with nausea, vomiting and possible burns.
Ingestion: May cause severe Gastrointestinal tract irritation with nausea, vomiting and possible burns.
First Aid Measures
Inhalation: Remove from exposure to fresh air immediately. If not breathing, give artificial respiration. If
breathing is difficult, give oxygen. Get medical treatment.
Eye Contact: Immediately flush eyes with plenty of water for at least 15 minutes, occasionally lifting the
upper and lower eye lids. Get medical aid immediately. Do not allow victim to rub or close eyes.
Skin Contact: Immediately flush skin with plenty of soap and water for at least 15 minutes while
removing contaminated clothing and shoes. Get medical attention if irritation develops or persists.
Ingestion: If victim is conscious and alert, give 2-4 cupfuls of milk or water. Never give anything by
mouth to an unconscious person. Get medical aid immediately. After first aid, get appropriate inplant
paramedic, or community medical support Note to Physicians: Treat symptomatically and supportively.
143
Physical and Chemical Properties Physical State: solid
Appearance and Odor: white/ off white crystals /powder/granules - odorless
Formula Weight: 380.12
Density: Specific Gravity (H20=J, at 4 0C): 1.62 g/cm pH:
Water Solubility: soluble
Acute Effects
Inhalation: May cause irritation of the respiratory tract with burning pain in the nose and throat,
coughing, wheezing, shortness of breath and pulmonary edema.
Eye: May cause severe eye irritation. May result in corneal injury.
Skin: May cause severe irritation and possible burns.
Ingestion: May cause severe gastrointestinal tract irritation with nausea, vomiting and possible burns.
Ingestion: May cause severe Gastrointestinal tract irritation with nausea, vomiting and possible burns.
First Aid Measures
Inhalation: Remove from exposure to fresh air immediately. If not breathing, give artificial respiration. If
breathing is difficult, give oxygen. Get medical treatment.
Eye Contact: Immediately flush eyes with plenty of water for at least 15 minutes, occasionally lifting the
upper and lower eye lids. Get medical aid immediately. Do not allow victim to rub or close eyes.
Skin Contact: Immediately flush skin with plenty of soap and water for at least 15 minutes while
removing contaminated clothing and shoes. Get medical attention if irritation develops or persists.
Ingestion: If victim is conscious and alert, give 2-4 cupfuls of milk or water. Never give anything by
mouth to an unconscious person. Get medical aid immediately. After first aid, get appropriate inplant
paramedic, or community medical support Note to Physicians: Treat symptomatically and supportively.
143
7. Morpholine
PHYSICAL AND CHEMICAL PROPERTIES
Appearance Form liquid Colour colourless Safety data pH 10.6 at 5 g/l at 20 °C (68 °F)
Melting point/freezing point Melting point/range: -7 - -5 °C (19 - 23 °F)
Boiling point 129 °C (264 °F)
Flash point 31 °C (88 °F) Ignition temperature 310 °C (590 °F)
Lower explosion limit 1.8 %(V) Upper explosion limit 10.8 %(V)
Density 0.996 g/cm3 at 25 °C (77 °F) Water solubility completely miscible
Odour unpleasant
HANDLING AND STORAGE
Precautions for safe handling Avoid contact with skin and eyes. Avoid inhalation of vapour or mist. Keep
away from sources of ignition - No smoking. Take measures to prevent the build up of electrostatic
charge. Conditions for safe storage Keep container tightly closed in a dry and well-ventilated place.
Containers which are opened must be carefully resealed and kept upright to prevent leakage.
Hygroscopic.
Potential Health Effects
Inhalation May be harmful if inhaled. Material is extremely destructive to the tissue of the mucous
membranes and upper respiratory tract.
Skin Toxic if absorbed through skin. Causes skin burns.
Eyes Causes eye burns.
Ingestion Harmful if swallowed.
144
PHYSICAL AND CHEMICAL PROPERTIES
Appearance Form liquid Colour colourless Safety data pH 10.6 at 5 g/l at 20 °C (68 °F)
Melting point/freezing point Melting point/range: -7 - -5 °C (19 - 23 °F)
Boiling point 129 °C (264 °F)
Flash point 31 °C (88 °F) Ignition temperature 310 °C (590 °F)
Lower explosion limit 1.8 %(V) Upper explosion limit 10.8 %(V)
Density 0.996 g/cm3 at 25 °C (77 °F) Water solubility completely miscible
Odour unpleasant
HANDLING AND STORAGE
Precautions for safe handling Avoid contact with skin and eyes. Avoid inhalation of vapour or mist. Keep
away from sources of ignition - No smoking. Take measures to prevent the build up of electrostatic
charge. Conditions for safe storage Keep container tightly closed in a dry and well-ventilated place.
Containers which are opened must be carefully resealed and kept upright to prevent leakage.
Hygroscopic.
Potential Health Effects
Inhalation May be harmful if inhaled. Material is extremely destructive to the tissue of the mucous
membranes and upper respiratory tract.
Skin Toxic if absorbed through skin. Causes skin burns.
Eyes Causes eye burns.
Ingestion Harmful if swallowed.
144
7. Morpholine
First Aid Measures
General advice Consult a physician.
Show this safety data sheet to the doctor in attendance.Move out of dangerous area.
If inhaled If breathed in, move person into fresh air. If not breathing, give artificial respiration. Consult a
physician.
In case of skin contact Take off contaminated clothing and shoes immediately. Wash off with soap and
plenty of water. Take victim immediately to hospital. Consult a physician.
In case of eye contact Rinse thoroughly with plenty of water for at least 15 minutes and consult a
physician.Continue rinsing eyes during transport to hospital. I
f swallowed Do NOT induce vomiting. Never give anything by mouth to an unconscious person. Rinse
mouth with water. Consult a physician.
8. Hydrazine
Physical State. Liquid
Odor and AppearanceClear, colourless liquid with ammonia odor.
Specific Gravity (Water=1) 1.019 at 25oC
Vapor Pressure (mm Hg, 20oC) 22 at 25oC
Boiling Point. 109.4oC
Freeze/Melting Point. -65oC
pH10.1-10.7 (1% solution in neutral, distilled water)
Solubility in Water. Completely soluble
Molecular Formula. N2H4
Molecular Weight. 32.04
145
First Aid Measures
General advice Consult a physician.
Show this safety data sheet to the doctor in attendance.Move out of dangerous area.
If inhaled If breathed in, move person into fresh air. If not breathing, give artificial respiration. Consult a
physician.
In case of skin contact Take off contaminated clothing and shoes immediately. Wash off with soap and
plenty of water. Take victim immediately to hospital. Consult a physician.
In case of eye contact Rinse thoroughly with plenty of water for at least 15 minutes and consult a
physician.Continue rinsing eyes during transport to hospital. I
f swallowed Do NOT induce vomiting. Never give anything by mouth to an unconscious person. Rinse
mouth with water. Consult a physician.
8. Hydrazine
Physical State. Liquid
Odor and AppearanceClear, colourless liquid with ammonia odor.
Specific Gravity (Water=1) 1.019 at 25oC
Vapor Pressure (mm Hg, 20oC) 22 at 25oC
Boiling Point. 109.4oC
Freeze/Melting Point. -65oC
pH10.1-10.7 (1% solution in neutral, distilled water)
Solubility in Water. Completely soluble
Molecular Formula. N2H4
Molecular Weight. 32.04
145
Hazard Identification
Inhalation: Irritating to nose, throat and lungs. Can cause headache, dizziness, vomiting, diarrhea, nausea and
convulsions.
Skin Contact / Absorption: Irritation upon direct contact. Can cause reddening, itching, swelling burning and
possible blistering. Prolonged or repeated skin contact may cause dermatitis and/or defatting of the skin.
Eye Contact Eye contact may cause moderate irritation consisting of transient redness, swelling and mucous
membrane discharge to the conjunctiva. No corneal involvement or visual impairment is expected.
Ingestion. Highly toxic. May cause severe irritation of the gastrointestinal tract and gastrointestinal discomfort
with the following symptoms: nausea, vomiting and/or diarrhea.
First Aid Measures
Inhalation Remove victim to fresh air. Give artificial respiration only if breathing has stopped. If breathing is
difficult, give oxygen. Seek immediate medical attention.
Skin Contact / Absorption Remove and dispose of contaminated clothing. Wash affected area with soap and
water. Seek medical attention if irritation occurs or persists.
Eye Contact. Flush immediately with water for at least 20 minutes. Forcibly hold eyelids apart to ensure complete
irrigation of eye tissue. Seek immediate medical attention.
Ingestion. Do not induce vomiting unless directed by medical personnel. Never give anything by mouth to an
unconscious person. Get immediate medical attention. Additional Information. Pyridoxine (Vitamin B6) has been
used successfully to treat the neurological symptoms of hydrazine exposure.
Handling Procedures.
Use proper equipment for lifting and transporting all containers. Use sensible industrial hygiene and
housekeeping practices. Wash thoroughly after handling. Avoid all situations that could lead to harmful exposure.
This product may become electrostatically charged during filling and transferring. Make sure equipment is
properly bonded and grounded. Storage Requirements. ................... Store in a dry place away from heat (below
50oC) and away from ignition sources and oxidants, preferably outdoors. Shelter drums stored outdoors from
direct sunlight. For indoor storage areas, continuous ventilation should be provided. 146
Inhalation: Irritating to nose, throat and lungs. Can cause headache, dizziness, vomiting, diarrhea, nausea and
convulsions.
Skin Contact / Absorption: Irritation upon direct contact. Can cause reddening, itching, swelling burning and
possible blistering. Prolonged or repeated skin contact may cause dermatitis and/or defatting of the skin.
Eye Contact Eye contact may cause moderate irritation consisting of transient redness, swelling and mucous
membrane discharge to the conjunctiva. No corneal involvement or visual impairment is expected.
Ingestion. Highly toxic. May cause severe irritation of the gastrointestinal tract and gastrointestinal discomfort
with the following symptoms: nausea, vomiting and/or diarrhea.
First Aid Measures
Inhalation Remove victim to fresh air. Give artificial respiration only if breathing has stopped. If breathing is
difficult, give oxygen. Seek immediate medical attention.
Skin Contact / Absorption Remove and dispose of contaminated clothing. Wash affected area with soap and
water. Seek medical attention if irritation occurs or persists.
Eye Contact. Flush immediately with water for at least 20 minutes. Forcibly hold eyelids apart to ensure complete
irrigation of eye tissue. Seek immediate medical attention.
Ingestion. Do not induce vomiting unless directed by medical personnel. Never give anything by mouth to an
unconscious person. Get immediate medical attention. Additional Information. Pyridoxine (Vitamin B6) has been
used successfully to treat the neurological symptoms of hydrazine exposure.
Handling Procedures.
Use proper equipment for lifting and transporting all containers. Use sensible industrial hygiene and
housekeeping practices. Wash thoroughly after handling. Avoid all situations that could lead to harmful exposure.
This product may become electrostatically charged during filling and transferring. Make sure equipment is
properly bonded and grounded. Storage Requirements. ................... Store in a dry place away from heat (below
50oC) and away from ignition sources and oxidants, preferably outdoors. Shelter drums stored outdoors from
direct sunlight. For indoor storage areas, continuous ventilation should be provided. 146
147
19. QUALITY CONTROL OF PRODUCTS
1. COPPER STRIP CORROSION:
This test method detects presence of components in petroleum product, which may be corrosive to
copper.
Significance: Copper corrosion limit provides assurance that the fuel oil is safe for copper and copper
alloy fittings and connections.
Outline of the method: A polished copper strip is immersed in the specified volume of the sample and
maintained at the specified temperature for the specified length of time. The strip is then compared
with ASTM copper strip corrosion standard colour code after cleaning with sulphur free petroleum
spirit. A special copper strip corrosion test cylinder is used for testing of LPG.
2. CARBON RESIDUE (Conradson):
Carbon residue can be defined as the amount of carbon residue left after evaporation and pyrolysis of
an oil. Carbon residue is tested for relatively non-
volatile petroleum products, which partially decompose on distillation at atmospheric pressure.
Significance: It gives measure of carbon depositing tendency of fuel oil. It correlates approximately with
the combustion chamber deposits of the engine.
Conradson Carbon Residue: In this method a weighed quantity of sample is placed in a crucible and
subjected to destructive distillation by applying severe heating. At the end of the specified heating
period, the test crucible containing the carbonaceous residue is cooled in a desiccator and weighed. The
residue remaining is calculated as percentage of the original sample and reported as Conradson Carbon
Residue.
148
1. COPPER STRIP CORROSION:
This test method detects presence of components in petroleum product, which may be corrosive to
copper.
Significance: Copper corrosion limit provides assurance that the fuel oil is safe for copper and copper
alloy fittings and connections.
Outline of the method: A polished copper strip is immersed in the specified volume of the sample and
maintained at the specified temperature for the specified length of time. The strip is then compared
with ASTM copper strip corrosion standard colour code after cleaning with sulphur free petroleum
spirit. A special copper strip corrosion test cylinder is used for testing of LPG.
2. CARBON RESIDUE (Conradson):
Carbon residue can be defined as the amount of carbon residue left after evaporation and pyrolysis of
an oil. Carbon residue is tested for relatively non-
volatile petroleum products, which partially decompose on distillation at atmospheric pressure.
Significance: It gives measure of carbon depositing tendency of fuel oil. It correlates approximately with
the combustion chamber deposits of the engine.
Conradson Carbon Residue: In this method a weighed quantity of sample is placed in a crucible and
subjected to destructive distillation by applying severe heating. At the end of the specified heating
period, the test crucible containing the carbonaceous residue is cooled in a desiccator and weighed. The
residue remaining is calculated as percentage of the original sample and reported as Conradson Carbon
Residue.
148
3. DENSITY, RELATIVE DENSITY AND API GRAVITY:
Density is the mass of liquid per unit volume at specified temperature (15°C). Relative density (specific
gravity) is the ratio of the mass of the given volume of the liquid at 60°F to mass of equal volume of
pure water at the same temperature. API gravity is special function of relative density (specific gravity).
141.5
Degree API = ----------------------------------- 131.5
Specific Gr. 60°/60°F
Significance: Density is a fundamental physical property that can be used in conjunction with other
properties to characterize petroleum product. Accurate determination of density, relative density and
API gravity of petroleum products is necessary for the conversion of the measured volumes to the
volumes at standard temperature of 15°C of 60°F. It is also a factor governing the quality of crude
petroleum oil and used as one of the factor for deciding the price of the crude oil. Higher API gravity
means higher light and middle distillate content in crude oil.
Outline of the method: Density can be carried out manually using hydrometers and thermometer or it
can be done using a digital density meter that work on the principle of change in oscillation frequency
due to the change in mass of the sample tube in conjunction with calibration data.
4. DOCTOR TEST:
This test method is intended for the detection of mercaptans in motor fuel, kerosene and similar
petroleum products.
Outline of the method: The sample is shaken with sodium plumbite solution (Doctor solution), a small
quantity of powder sulphur is added and the mixture shaken again. The presence of mercaptans or
hydrogen sulphide or both is indicated by discolouration of the sulphur layer floating at the oil-water
interface or by discolouration of either of the phases.
Significance: Mercaptan sulphurs and hydrogen sulphide present in distillate fuels are corrosive in
nature and can attack many metallic and non-metallic parts in fuel distribution systems.
149
Density is the mass of liquid per unit volume at specified temperature (15°C). Relative density (specific
gravity) is the ratio of the mass of the given volume of the liquid at 60°F to mass of equal volume of
pure water at the same temperature. API gravity is special function of relative density (specific gravity).
141.5
Degree API = ----------------------------------- 131.5
Specific Gr. 60°/60°F
Significance: Density is a fundamental physical property that can be used in conjunction with other
properties to characterize petroleum product. Accurate determination of density, relative density and
API gravity of petroleum products is necessary for the conversion of the measured volumes to the
volumes at standard temperature of 15°C of 60°F. It is also a factor governing the quality of crude
petroleum oil and used as one of the factor for deciding the price of the crude oil. Higher API gravity
means higher light and middle distillate content in crude oil.
Outline of the method: Density can be carried out manually using hydrometers and thermometer or it
can be done using a digital density meter that work on the principle of change in oscillation frequency
due to the change in mass of the sample tube in conjunction with calibration data.
4. DOCTOR TEST:
This test method is intended for the detection of mercaptans in motor fuel, kerosene and similar
petroleum products.
Outline of the method: The sample is shaken with sodium plumbite solution (Doctor solution), a small
quantity of powder sulphur is added and the mixture shaken again. The presence of mercaptans or
hydrogen sulphide or both is indicated by discolouration of the sulphur layer floating at the oil-water
interface or by discolouration of either of the phases.
Significance: Mercaptan sulphurs and hydrogen sulphide present in distillate fuels are corrosive in
nature and can attack many metallic and non-metallic parts in fuel distribution systems.
149
5. FLASH POINT:
It is the lowest temperature at which a material gives so much vapour that, these vapour when mixed
with air, forms an ignitable mixture and gives a momentary flash on application of a small pilot flame.
Outline of the method: The sample is heated in a test cup at a specified rate with continuous stirring. A
small test flame is directed in to the cup at regular
intervals with simultaneous interruption of stirring. The flash point is taken as the lowest temperature at
which the application of the test flame causes the vapour above the sample to ignite momentarily.
Significance: It is one of a number of properties that must be considered in accessing the overall
flammability hazard of a material. Flash point and fire point have importance in connection with legal
requirements and safety precautions involved in fuel handling and storage.
6. POUR POINT TEST:
Pour point is the lowest temperature expressed as a multiple of 3°C at which the oil is observed to flow
when cooled and examined under prescribed conditions.
Outline of method: After preliminary heating the sample is cooled at a specified rate and examined at
intervals of 3°C for flow characteristics. The lowest temperature at which movement of the sample is
observed is recorded as the pour point.
Significance: The pour point of a petroleum product is an index of the lowest temperature of it’s utility
for certain applications.
7. REID VAPOUR PRESSURE OF HYDROCARBON LIQUID:
This method is for the determination of vapour pressure of volatile non-viscous liquid.
Outline of the method: The sample chamber filled with the cold sample is connected to the air chamber
of the apparatus fitted with a pressure gauge. The apparatus is then kept at a temperature of 38°C and
shaken periodically until a constant reading is obtained on the pressure gauge. Necessary corrections are
applied to this reading to get the corrected Reid Vapour Pressure of the sample.
150
It is the lowest temperature at which a material gives so much vapour that, these vapour when mixed
with air, forms an ignitable mixture and gives a momentary flash on application of a small pilot flame.
Outline of the method: The sample is heated in a test cup at a specified rate with continuous stirring. A
small test flame is directed in to the cup at regular
intervals with simultaneous interruption of stirring. The flash point is taken as the lowest temperature at
which the application of the test flame causes the vapour above the sample to ignite momentarily.
Significance: It is one of a number of properties that must be considered in accessing the overall
flammability hazard of a material. Flash point and fire point have importance in connection with legal
requirements and safety precautions involved in fuel handling and storage.
6. POUR POINT TEST:
Pour point is the lowest temperature expressed as a multiple of 3°C at which the oil is observed to flow
when cooled and examined under prescribed conditions.
Outline of method: After preliminary heating the sample is cooled at a specified rate and examined at
intervals of 3°C for flow characteristics. The lowest temperature at which movement of the sample is
observed is recorded as the pour point.
Significance: The pour point of a petroleum product is an index of the lowest temperature of it’s utility
for certain applications.
7. REID VAPOUR PRESSURE OF HYDROCARBON LIQUID:
This method is for the determination of vapour pressure of volatile non-viscous liquid.
Outline of the method: The sample chamber filled with the cold sample is connected to the air chamber
of the apparatus fitted with a pressure gauge. The apparatus is then kept at a temperature of 38°C and
shaken periodically until a constant reading is obtained on the pressure gauge. Necessary corrections are
applied to this reading to get the corrected Reid Vapour Pressure of the sample.
150
Significance: Vapour pressure is critically important for both automotive and aviation gasolines,
affecting starting, warm up, and tendency to vapour lock with high operating temperatures or high
altitudes. Vapour pressure of crude oil is important for it’s safe transportation, storage and initial
refinery treatments.
8. WATER AND SEDIMENTS:
This method is for the determination of precipitated water and sediment in crude oil and fuel oil by
means of the centrifuge.
Outline of the method: Equal volumes of the sample and water saturated toluene are placed in each
of two cone shaped 100 ml centrifuge tubes and thoroughly mixed. After centrifugation the volume of
water and sediment layer collected at the bottom of the tube is read and reported as BS&W.
Significance: The water and sediment present in a fuel oil may cause corrosion of equipment and
problem in processing. It is also important for evaluation of crude oil for commercial purposes.
9. OCTANE NUMBER (RESEARCH METHOD AND MOTOR METHOD):
Octane number of the spark ignition engine fuels is volume percent of iso-octane in a blend with n-
heptane that matches the knock intensity of the fuel when compared under specified conditions. The
research octane number is determined by knock testing unit (CFR Engine) using the standard operating
conditions given in ASTM D 2699. Whereas motor octane number is determined using the standard
operating conditions given in ASTM D 2700.
Significance: Research octane number in conjunction with motor octane number defines the Antiknock
Index of Automatic Spark Ignition Engine fuels in accordance with specification ASTM D 4812. The
antiknock index of a fuel approximates the road octane ratings for many vehicles.
(RON + MON)
Antiknock Index (AKI) = ----------------------
2
151
affecting starting, warm up, and tendency to vapour lock with high operating temperatures or high
altitudes. Vapour pressure of crude oil is important for it’s safe transportation, storage and initial
refinery treatments.
8. WATER AND SEDIMENTS:
This method is for the determination of precipitated water and sediment in crude oil and fuel oil by
means of the centrifuge.
Outline of the method: Equal volumes of the sample and water saturated toluene are placed in each
of two cone shaped 100 ml centrifuge tubes and thoroughly mixed. After centrifugation the volume of
water and sediment layer collected at the bottom of the tube is read and reported as BS&W.
Significance: The water and sediment present in a fuel oil may cause corrosion of equipment and
problem in processing. It is also important for evaluation of crude oil for commercial purposes.
9. OCTANE NUMBER (RESEARCH METHOD AND MOTOR METHOD):
Octane number of the spark ignition engine fuels is volume percent of iso-octane in a blend with n-
heptane that matches the knock intensity of the fuel when compared under specified conditions. The
research octane number is determined by knock testing unit (CFR Engine) using the standard operating
conditions given in ASTM D 2699. Whereas motor octane number is determined using the standard
operating conditions given in ASTM D 2700.
Significance: Research octane number in conjunction with motor octane number defines the Antiknock
Index of Automatic Spark Ignition Engine fuels in accordance with specification ASTM D 4812. The
antiknock index of a fuel approximates the road octane ratings for many vehicles.
(RON + MON)
Antiknock Index (AKI) = ----------------------
2
151
10. PIONA ANALYSIS:
This test method provides for the estimation of paraffins, iso-paraffins, olefins, naphthenes and
aromatics by carbon number in low olefinic hydrocarbon streams having final boiling points of 200
0
C or
less.
Significance: Knowledge of the composition of hydrocarbon refinery streams is useful for process
control and quality assurance purposes. Aromatics in gasoline are soon to be limited by federal
mandate. This test method can be used to provide such information.
152
This test method provides for the estimation of paraffins, iso-paraffins, olefins, naphthenes and
aromatics by carbon number in low olefinic hydrocarbon streams having final boiling points of 200
0
C or
less.
Significance: Knowledge of the composition of hydrocarbon refinery streams is useful for process
control and quality assurance purposes. Aromatics in gasoline are soon to be limited by federal
mandate. This test method can be used to provide such information.
152
20. Fire fighting List of MCP’S and Layout
153
153
154
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