Fccnht Manual
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OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT, VRCFP, HPCL VISAKH
Doc No. Draft Rev. A Page 1 of 182
OPERATING MANUAL FOR FCC NAPHTHA HYDROTREATING UNIT
VISAKH REFINERY CLEAN FUEL PROJECT
HINDUSTAN PETROLEUM CORPORATION LIMITED VISAKH
A Rev No.
Date
Issued for comments Purpose
Prepared by
Checked by
Approved by
PREFACE
Template No. 5-0000-0001-T2 Rev A
Copyrights EIL- All rights reserved
OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT, VRCFP, HPCL VISAKH
Doc No. Draft Rev. A Page 2 of 182
This operating manual for FCC Naphtha HydroTreater Unit (Unit No.-75) of Visakh Refinery Clean Fuel Project for HPCL Visakh Refinery has been prepared by M/s Engineers India Limited for M/s Hindustan Petroleum Corporation Limited. The objective of FCC Naphtha Hydrotreating Unit is to process FCC Gasoline to obtain product streams (Light gasoline and Heavy Hydrotreated gasoline) with targeted qualities of octane number, sulphur content, benzene content and olefins content. This manual contains process description and operating guidelines for the unit and is based on documents supplied by the Process Licensor (Axens). Hence the manual must be reviewed /approved by the licensor before the start-up /operation of the unit. Operating procedures & conditions given in this manual are indicative. These should be treated as general guide only for routine start-up and operation of the unit. The actual
operating
parameters
and
procedures
may
require
minor
modifications/changes from those contained in this manual as more experience is gained in operation of the Plant. For detailed specifications and operating procedures of specific equipment, corresponding Vendor's operating manuals/instructions need to be referred in addition to Process Package and Design Basis.
List Of Abbreviations, Definitions and Legend
Template No. 5-0000-0001-T2 Rev A
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OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT, VRCFP, HPCL VISAKH
Doc No. Draft Rev. A Page 3 of 182
TABLE OF CONTENTS SECTION- 1
INTRODUCTION.................................................................................................................................9
1.1
INTRODUCTION.....................................................................................................................................................10
1.2
UNIT CAPACITY....................................................................................................................................................10
1.3
ON-STREAM FACTOR............................................................................................................................................10
1.4
TURNDOWN RATIO...............................................................................................................................................10
1.5
FEED CHARACTERISTICS......................................................................................................................................10
1.5.1
FCC Gasoline
1.5.2
Sulfur Distribution (ppm wt)*....................................................................................................................11
1.5.3
Hydrogen
12
1.5.4
Lean Amine
13
1.5.5
Start-up inert naphtha
13
1.6
10
PRODUCTS SPECIFICATION....................................................................................................................................14
1.6.1
Light FCC gasoline:
14
1.6.2
Heavy desulfurized FCC gasoline.............................................................................................................15
1.6.3
Benzene Heartcut
15
1.6.4
Splitter purge gas
17
1.6.5
Selective HDS purge
17
1.6.6
Rich Amine
17
1.6.7
Stabilizer purge
18
1.7
PROPOSED TREATMENT SCHEME...............................................................................................................18
1.8
BATTERY LIMIT CONDITIONS OF PROCESS LINES.................................................................................................19
1.9
MATERIAL BALANCES..........................................................................................................................................20
1.9.1
SHU section overall balance.....................................................................................................................20
1.9.2
HDS section overall balance.....................................................................................................................20
1.10
SPECIFICATIONS OF CATALYSTS AND CHEMICALS............................................................................................21
1.10.1
Catalyst
21
1.10.2
Catalyst Bed Protections
22
1.10.3
Inert balls
23
1.10.4
Chemicals
24
1.11
UTILITY CONDITION AT UNIT BATTERY LIMIT...................................................................................25
1.12
UTILITY SPECIFICATION:.........................................................................................................................27
1.13
INTERMITTENT UTILITY CONSUMPTION...........................................................................................................28
1.13.1
Start-up requirement
1.13.2
Catalyst in-situ regeneration.....................................................................................................................30
1.14
EFFLUENT SUMMARY:.....................................................................................................................................31
SECTION- 2 2.1
28
PROCESS DESCRIPTION...............................................................................................................33
UNIT DESCRIPTION...............................................................................................................................................34
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OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT, VRCFP, HPCL VISAKH
Doc No. Draft Rev. A Page 4 of 182
2.2
SELECTIVE HYDROGENATION..............................................................................................................................34
2.3
SPLITTER SECTION...............................................................................................................................................35
2.4
HDS SECTION......................................................................................................................................................36
2.5
RECYCLE COMPRESSOR SECTION.........................................................................................................................37
2.6
STABILIZER SECTION........................................................................................................................................37
2.7
CATALYST IN-SITU REGENERATION OPERATION....................................................................................................38
SECTION- 3
PROCESS PRINCIPLE.....................................................................................................................40
3.1
PURPOSE OF THE PROCESS...................................................................................................................................41
3.2
GENERAL.............................................................................................................................................................41
3.3
SELECTIVE HYDROGENATION REACTOR (75-R-01)..............................................................................................41
3.4
SPLITTER (75-C-01).............................................................................................................................................42
3.5
FIRST HDS REACTOR (75-R-02)..........................................................................................................................43
3.6
CHEMICAL REACTIONS AND CATALYST...............................................................................................................43
3.6.1
Objective
3.6.2
Thermodynamics and kinetics...................................................................................................................44
3.6.3
Catalyst activity, selectivity AND stability................................................................................................44
3.6.4
Selective hydrogenation Reactions and Catalyst.......................................................................................45
3.6.5
Chemical reactions
3.6.6
Hydrogenation of diolefins 45
3.6.7
Isomerization of olefins
47
3.6.8
Hydrogenation of olefins
47
3.6.9
Thermal and catalytic polymerization of unstable compounds.................................................................47
3.6.10
Thermodynamic and kinetic analysis........................................................................................................47
3.6.11
Sulfur reaction
3.7
43
45
48
PROCESS VARIABLES IN SELECTIVE HYDROGENATION.............................................................................49
3.7.1
Reactor Temperature
3.7.2
Residence time in the reactor....................................................................................................................50
3.7.3
Reactor pressure
50
3.7.4
Hydrogen make-up rate
51
3.8
49
CHEMICAL: HDS REACTOR REACTIONS AND CATALYST.....................................................................................51
3.8.1
Chemical reactions
51
3.8.2
Hydrorefining
52
3.8.3
Hydrogenation of olefins
53
3.9
RELATIVE RATES OF REACTION............................................................................................................................54
3.9.1
Process variables in hds reactor...............................................................................................................54
3.9.2
Temperature
3.9.3
Operating pressure and H2/HC ratio........................................................................................................55
3.9.4
Space velocity
Template No. 5-0000-0001-T2 Rev A
54
56
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OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT, VRCFP, HPCL VISAKH SECTION- 4 4.1
Doc No. Draft Rev. A Page 5 of 182
UTILITY DESCRIPTION.................................................................................................................57
INTRODUCTION...............................................................................................................................................57
4.1.1
INSTRUMENT AIR SYSTEM.....................................................................................................................58
4.1.2
PLANT AIR SYSTEM
4.1.3
SEA COOLING WATER SYSTEM.............................................................................................................58
4.1.4
BEARING COOLING WATER SYSTEM..................................................................................................59
4.1.5
SERVIC WATER SYSTEM 59
4.1.6
NITROGEN
60
4.1.7
LP STEAM SYSTEM
60
4.1.8
MP STEAM SYSTEM
60
4.1.9
VHP STEAM SYSTEM
61
4.1.10
FUEL GAS SYSTEM
61
4.2
58
EFFLUENT SYSTEM........................................................................................................................................61
SECTION- 5
PREPARATION FOR START-UP....................................................................................................63
5.1
GENERAL..........................................................................................................................................................64
5.2
PRE-COMMISSIONING ACTIVITIES.............................................................................................................64
5.2.1
Inspection / Checking
65
5.2.2
Inspection of equipments
65
5.2.3
Piping and Accessories
66
5.2.4
Instruments
66
5.2.5
Relief Valves
66
5.2.6
Rotary Equipment
66
5.2.7
Drainage System
66
5.3
PREPARATION FOR PRE-COMMISSIONING.............................................................................................................67
5.4
PRE-COMMISSIONING...........................................................................................................................................67
5.4.1
Commissioning of Utilities 68
5.4.2
Final Inspection of Vessels 70
5.4.3
Pressure Test Equipment
5.4.4
Wash Out Lines and Equipment.................................................................................................................72
5.4.5
Functional Test of Rotating Equipment.....................................................................................................73
70
5.5
INSTRUMENTS CHECKING.....................................................................................................................................76
5.6
SAFETY DEVICES CHECK......................................................................................................................................78
5.7
HEATER REFRACTORY DRY-OUT AND REACTION SECTION DRY-OUT..................................................................78
5.8
PURGING AND GAS BLANKETING........................................................................................................................78
5.9
TIGHTNESS TEST..................................................................................................................................................80
5.10
CATALYST LOADING PROCEDURE.....................................................................................................................82
5.11
CATALYST SPECIAL PROCEDURE......................................................................................................................82
SECTION- 6
START-UP PROCEDURE.................................................................................................................84
Template No. 5-0000-0001-T2 Rev A
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Doc No. Draft Rev. A Page 6 of 182
6.1
INTRODUCTION...............................................................................................................................................84
6.2
PRE-START-UP CHECKLIST FOR PRIME G+ UNIT..............................................................................................85
6.3
FIRST START-UP....................................................................................................................................................86
6.3.1
Chronology of start-up operations............................................................................................................87
6.3.2
Purging of air
6.4
87
START-UP PRELIMINARY OPERATION....................................................................................................................90
6.4.1
Unit status
6.4.2
Inert naphtha circulation (Reaction sections by-passed)..........................................................................91
6.4.3
Start-up of Hot Naphtha circulation in splitter and stabilizer..................................................................94
6.5
90
PRESSURIZATION OF THE REACTION SECTIONS AND HYDROGEN LEAK TESTS.....................................................95
6.5.1
Unit status
6.5.2
H2 inroduction in SHU section.................................................................................................................96
6.5.3
H2 inroduction in HDS section.................................................................................................................96
6.6
95
CATALYST SULFIDING – DRY SULPHIDING...........................................................................................................97
6.6.1
Sulfiding of HR-845 Catalyst in the Diolefin Reactor (75-R-01)..............................................................98
6.6.2
Sulfiding of HR-806 Catalyst of first HDS Reactor (75-R-02)..................................................................98
6.6.3
Sulphiding Procedure
6.7
98
UNIT START-UP..................................................................................................................................................100
6.7.1
UNIT Status
6.7.2
Lining up of the SHU reaction section....................................................................................................101
6.7.3
Lining up of the HDS reaction section....................................................................................................102
6.7.4
Inert naphtha circulation
103
6.7.5
FCC Gasoline Feed
104
SECTION- 7
100
NORMAL OPERATING PROCEDURE.......................................................................................107
7.1
GUIDELINES FOR NORMAL OPERATION.................................................................................................107
7.2
INTRODUCTION.............................................................................................................................................107
7.3
OPERATING PARAMETER............................................................................................................................108
7.4
ALARMS:.........................................................................................................................................................115
7.5
OPEARATING CONDITIONS OF DIFFERENT CASES OF OPERATION.................................................119
7.6
EQUIPMENT LIST...........................................................................................................................................120
7.6.1
Pumps
120
7.6.2
Vessels
120
7.6.3
Columns
121
7.6.4
Reactors
121
7.6.5
Heat Exchangers(Tubular) 122
7.7
LIST OF INSTRUMENTS................................................................................................................................123
7.7.1
Control Valves:
123
7.7.2
ON-OFF Valves
125
Template No. 5-0000-0001-T2 Rev A
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OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT, VRCFP, HPCL VISAKH 7.7.3
Safety valves
Doc No. Draft Rev. A Page 7 of 182
126
7.8
RELIEVE VALVE LOAD SUMMARY...........................................................................................................128
7.9
DETAIL OF INTERLOCK LOGIC AND TRIPS.............................................................................................128
7.10
EFFECT OF OPERATING VARIABLES ON THE PROCESS....................................................................................133
7.10.1
Operating parameters
133
7.10.2
Reactor temperature
133
7.10.3
other parameter
135
7.10.4
Make-up H2 and recycle H2 flow-rates....................................................................................................136
7.10.5
Space velocity (feed rate) 138
7.10.6
Feed quality
SECTION- 8 8.1
139
SHUTDOWN PROCEDURES........................................................................................................141
NORMAL SHUTDOWN PROCEDURE.........................................................................................................142
8.1.1
introduction
8.1.2
Preparations for a Planned Shutdown....................................................................................................142
8.1.3
General procedure
143
8.1.4
Short period shutdown
143
8.1.5
Long period shutdown
145
8.1.6
Shutdown followed by maintenance, inspection or catalyst unloading...................................................146
8.2
UNIT RESTART....................................................................................................................................................148
SECTION- 9 9.1
142
EMERGENCY SHUTDOWN PROCEDURE...............................................................................150
EMERGENCY SHUTDOWN PROCEDURE..................................................................................................151
9.1.1
general
9.1.2
Emergency shutdown by operators..........................................................................................................151
9.1.3
Loss of feed
153
9.1.4
Loss of cooling water
155
9.1.5
Lack of hydrogen make-up 155
9.1.6
Loss of Amine
155
9.1.7
Quench pump failure
155
9.1.8
Fuel gas failure
156
9.1.9
Steam failure
156
9.1.10
Instrument air failure
156
9.1.11
Power failure
156
9.1.12
Fire or major leak
157
9.1.13
Automatic emergency shutdown..............................................................................................................158
SECTION- 10 10.1
151
TROUBLE SHOOTING..................................................................................................................160
TROUBLE SHOOTING..............................................................................................................................161
10.1.1
High differential pressure (P) in the reactor.........................................................................................161
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Doc No. Draft Rev. A Page 8 of 182
10.1.2
Chemical H2 consumption increase........................................................................................................161
10.1.3
Octane losses
SECTION- 11
162
SAMPLING PROCEDURE AND LABORATORY ANALYSIS..................................................163
11.1
GENERAL....................................................................................................................................................164
11.2
SAMPLING PROCEDURE.........................................................................................................................164
SECTION- 12
SAFETY PROCEDURE...................................................................................................................170
12.1
INTRODUCTION........................................................................................................................................171
12.2
PLANT SAFETY FEATURES..............................................................................................................................171
12.2.1
General
171
12.2.2
Emergency shutdown
171
12.2.3
Overpressure protection
171
12.2.4
Safety shower and eye wash....................................................................................................................172
12.2.5
Operational safety stations 172
12.2.6
High pressure
172
12.2.7
Reactor protection
172
12.2.8
Personnel protection
172
12.3
SAFETY OF PERSONNEL.........................................................................................................................175
12.4
WORK PERMIT PROCEDURE..................................................................................................................176
12.5
PREPARATION OF EQUIPMENT FOR MAINTENANCE......................................................................178
12.6
PREPARATION FOR VESSEL ENTRY.....................................................................................................180
12.6.1
General procedure
12.6.2
Preparation of Vessel Entry Permit.........................................................................................................184
12.6.3
Checkout Prior to New Unit Start-up......................................................................................................184
12.6.4
Inspections during Turnarounds..............................................................................................................185
12.7
180
FIRE FIGHTING SYSTEM.........................................................................................................................186
12.7.1
Use of life saving device
SECTION- 13
187
GENERAL OPERATING INSTRUCTIONS FOR EQUIPMENT..............................................189
13.1
GENERAL....................................................................................................................................................190
13.2
CENTRIFUGAL PUMPS............................................................................................................................190
13.3
HEAT EXCHANGERS................................................................................................................................193
13.3.1
General
193
13.3.2
Air coolers
193
13.3.3
Exchangers
193
Template No. 5-0000-0001-T2 Rev A
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Doc No. Draft Rev. A Page 9 of 182
SECTION- 1 INTRODUCTION
Template No. 5-0000-0001-T2 Rev A
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OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT, VRCFP, HPCL VISAKH
Rev. A Page 10 of 182
1.1 INTRODUCTION Hindustan Petroleum Corporation Limited (HPCL), Visakh is in the process of augmenting the capacity of the existing refinery by revamping the existing primary units and installing additional facilities required to meet the product specifications. The objective of this Unit is to process FCC gasoline to produce a blend of two streams (LCN+HCN), Maximise the octane number while meeting pool specifications in term of sulphur content, benzene content and olefins content. Three different feeds considered for the design of the FCC Naphtha Hydrotreater unit: are NITCASE, AM (Arab Mix) CASE, BH (Bombay High) CASE 1.2 UNIT CAPACITY The unit capacity is 893 330 T/yr for all three cases 1.3 ON-STREAM FACTOR The unit is designed for a stream factor of 8000 hours/annum. 1.4 TURNDOWN RATIO The unit is capable of a turndown of 50% of hydrocarbon flow. 1.5 FEED CHARACTERISTICS Three operating cases, AM CASE, BH CASE and NIT CASE are selected for the design of the unit. 1.5.1
FCC GASOLINE:
Characteristics Max Available Rate,
t/hr St m3/hr Density at 15°C, g/cc Total Sulfur, wppm / RSH RON Template No. 5-0000-0001-T2 Rev A
AM
BH
NIT
CASE 111 666 152.3 0.7334 2400/720 93
CASE 111 666 156.0 0.716 180/90 93
CASE 111 666 152.8 0.731 1133/229 91.4 Copyrights EIL- All rights reserved
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OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT, VRCFP, HPCL VISAKH
Page 11 of 182
AM
BH
NIT
CASE 80.6
CASE 81.6
CASE 81.2
29.5 35.5
29.2 38.5
24.35 54.47
(Diolefins wt %) Naphthenes, vol % Aromatics, vol %
(2.0) 10.7 24.3
(2.0) 10.3 22.0
(2.0) 7.01 14.17
(Benzene, vol%) Distillation (ASTM-D86), °C IBP 10 % vol 30 % vol 50 % vol 70 % vol 90 % vol 95 % vol FBP
(1.8)
(1.9)
(0.38)
46.1 56.1 75.5 95.5 124.4 155 167.7 180
46.1 56.1 75.5 95.5 124.4 155 167.7 180
40 57.6 70.6 92 123.2 156.4 168.2 187
Characteristics MON PONA (vol %) Paraffins, vol % Olefins, vol %
1.5.2
Rev. A
SULFUR DISTRIBUTION (PPM WT)* AM case
BH case
NIT case
Methyl mercaptan Ethyl mercaptan C3 mercaptan C4 mercaptan
(ppm wt) 0.5 200 138 22
(ppm wt) 0.5 25 17 3
(ppm wt) 0.5 118 81 13
C5 mercaptan C6+ mercaptan Carbonyle disulfide Dimethyl sulfide Methyl ethyl sulfide Methyl-t-butyl sulfide Thiophene C1 thiophene Tetra hydro thiophene C2 thiophene C3+ thiophene and
263 97 0.5 2 2.0 5 236 360 51 262 773
33 12 0.1 0.2 0.2 0.5 12 24 5 12 37
12 5 0.5 1 1.0 3 100 200 20.0 128 451
benzothiophenes Total
2400
180
1133
Sulphur components
(*) Assumed from Axens data bank
Template No. 5-0000-0001-T2 Rev A
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OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT, VRCFP, HPCL VISAKH
1.5.3
Rev. A Page 12 of 182
HYDROGEN Components / Origin H2, mol%
Hydrogen from CCR 93.0
C1, mol%
2.3
C2, mol%
2.2
C3, mol%
1.7
iC4, mol%
0.3.
nC4
0.3
C5+, mol%
0.2
Total
100
Origin:
Start-up H2 99.9
balance
100
Normal
Impurities: H2S
1.5.4
Doc No. Draft
Start-up
5ppm vol max
Nil
HCl
0.5 ppm vol max
1 ppm vol max
CO
6-10 ppm vol max
1 ppm vol max
COS
1 ppm vol max
Others: CO+CO2 25 ppm vol max
20 ppm vol max
Water:
30-35 ppm vol
50 ppm vol max
Olefins:
10 ppm wt
Nitrogen:
1 ppm wt
LEAN AMINE Properties / Case Type
All cases Di-EthanolAmine (DEA)
Rate, kg/h
10 000
Amine Content, % wt
25
Loading, mol H2S/mol amine
Lean Amine : 0.03 Rich Amine: 0.33 max.
1.5.5
START-UP INERT NAPHTHA For start-up, inert naphtha is required to perform naphtha circulation in the unit and to put the unit at SOR temperatures. This naphtha should have the following properties.
Start-up Inert Naphtha Sulfur components Estimated
Specification Required 2 x unit volume
Volume, m3
8
A/B 75-P-02
HDS FEED PUMPS
112.3
123.5
34.8
472
4
A/B 75-P-03
SPLITTER
166.6
200
11.3
95.7
3.3
79.7
96
10.5
45.5
>8
A/B 75-P-04 A/B
REFLUX
PUMPS LIGHT GASOLINE PUMPS
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OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT, VRCFP, HPCL VISAKH Item No.
75-P-05 A/B 75-P-06 A/B
Item Description
Rated
Disc.
Diff.
NPSHA
l Cap.
Cap.
Press
Head
(m)
(m³/hr)
(m³/hr)
(Kg/cm²g)
(m)
FCC HEART CUT PUMPS
24.7
27.2
10.1
38.6
>8
QUENCH PUMPS
44.3
53.1
36.2
187.4
3.7
107.1
117.8
12.7
93.3
2.8
1.34
2.6
11.7
149.7
>8
15
18
12
86.7
2.*9
Internal
TL-TL
Oper.
Oper.
Dia.
(mm)
Temp
Press.
(mm) 3900 2400 2500 900 1100 900
11000 6800 8400 2800 3300 2500
°C 70 55 40 40 40 40
Kg/cm²g 3.0 5.5 21.5 21.4 6.3 21.5
600
1950
AMB
1.0
1600
5000
AMB
1.0
STABILIZER
A/B
PUMPS
75-P-08
CORROSION
A/B
PUMPS
75-P-09
STABILIZER
A/B
PUMP
BOTTOM
INHIBITOR
REFLUX
VESSELS: Tag No.
75-V-01 75-V-02 75-V-03 75-V-04 75-V-05 75-V-06 75-V-09 75-V-10
7.6.3
Page 113 of 182
Norma
75-P-07
7.6.2
Rev. A
Item Description
SHU FEED SURGE DRUM SPLITTER REFLUX DRUM SEPARATOR DRUM RECYCLE COMP. KOD STABILIZER REFLUX DRUM AMINE KOD CORROSION INHIBITOR DRUM SULFIDING AGENT DRUM
COLUMNS:
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OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT, VRCFP, HPCL VISAKH
Rev. A Page 114 of 182
Tag
Item
No.
Internal
TL-TL
Oper. Temp
Oper Press
No.
Description
of
Dia
(mm)
°C Top
Kg/cm²g Top Bottom
tray
(mm)
75-C-
GASOLINE
52
3100
41550
116
01 75-C-
SPLITTER AMINE
20
900
14150
50
02 75-T-
ABSORBER STABILISER
30
2100
26750
177
1003
COLUMN
Bottom 199
6.03
6.47
14.8 203
7.85
8.08
(Btm); 1100 (top)
7.6.4
7.6.5
REACTORS: Tag No.
Item Description
75-R-01 75-R-02
SHU REACTOR HDS REACTOR
Internal
TL-TL
Oper. Temp
Oper Press
Dia (mm)
1800 2500
(mm)
°C
Kg/cm²g
23420 12950
200 355
30 28.4
HEAT EXCHANGERS (TUBULAR):
Sr.
Tag
No.
No.
Service
Shell side
Tube side
fluid
fluid
Shell side
Tube side
temp (C)
temp (c)
1
75-E-01
SHU
HDS
HDS Effluent
SHU Feed
IN 211
2
75-E-02
Effluent exchanger SHU Feed / Effluent
SHU Effluent
SHU Feed
219
188
155
188
3 4 5 6 7 8
75-E-03 75-E-04 75-E-05 75-E-06 75-E-07 75-E-08
exchanger SHU preheater Splitter post condensor Light Gasoline cooler FCC Heartcut cooler Splitter reboiler HDS Feed / Effluent
VHP Steam HC+H2 Light Gasoline Gasoline VHP Steam HDS Feed
SHU Feed Cooling water Cooling water Cooling water HC HDS Effluent
238 55 65 65 238 174
238 40 40 40 238 312
128 33 33 33 216 370
200 40 40 40 221 207
9
A/B/C 75-E-09
Exchanger Reactor effluent
HC
Cooling water
65
40
33
40
10 11
75-E-10 75-E-11
cooler Lean Amine preheater Stabilizer Feed/Bottom
Lean Amine Stabilizer Feed
LP steam Stabilizer
40 225
50 107
128 41
128 169
12
A/B 75-E-12
exchanger Heavy gasoline
Heavy
Bottom Cooling water
65
40
33
40
13
A/B 75-E-13
cooler Stabilizer reboiler
gasoline VHP steam
Stabilizer
238
238
221
225
Stabilizer overhead trim
Stabilizer
bottom Cooling water
65
40
33
40
cooler
overhead
14
7.6.6
75-E-14
Feed
/
trim
trim
OUT 156
IN 66
OUT 155
AIR COOLERS
Template No. 5-0000-0001-T2 Rev A
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OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT, VRCFP, HPCL VISAKH
Sr. No. 1 2 3 4 5 6 7
Tag 75-A-01 75-A-02 75-A-03 75-A-04 75-A-05 75-A-06 75-A-07
Service Splitter overhead air condenser FCC heart cut air cooler HDS Effluent air condenser SHU recycle air condenser Stabilizer overhead condenser Light gasoline air cooler Heavy gasoline air cooler
Temp. - in 97 142 158 218 135 116 107
Doc No. Draft Rev. A Page 115 of 182
Temp. - out 55 65 65 65 65 65 65
7.7 LIST OF INSTRUMENTS In this section control valves, pressure safety valves, analysers etc are listed. Information regarding indicators & controllers (temperature, pressure, flow and level instrument) are already given in previous section. 7.7.1 S.
CONTROL VALVES: Tag No.
Description
Action of CV
No
on Air failure
. SHU FEED SURGE DRUM: 1. PV-1101A Gases from FSD to Flare 2. PV-1101B Nitrogen to FSD 3. LV-1101 FSD boot draining 4. FV-1103 Heavy Gasoline Recycle from SHU Recycle Air Condenser 5. FV-1104 Feed from storage SHU FEED SECTION: 6. FV-1201 SHU feed to 75-E-01
FC FC FC FC FC
7. 8. 9.
A/B FV-1202 FV-1203 FV-1204
Charge pump MCF Hydrogen to reaction section SHU Feed/Effluent Exchanger bypass to SHU Preheater
A/B SHU FEED PREHEATING SECTION: 10. FV-1301 VHP steam to SHU Preheater A/B SHU REACTOR: 11. PDV-1401 SHU Reactor first bed bypass SHU SPLITTER SECTION: 12. PV-1404 Splitter feed 13. PV-1501 Depressurization line 14. FV-1501 VHP steam condensate from Splitter Reboiler 15. PV-1601 Splitter reflux drum pressure control A/B 16. LV-1601
Reflux line
Template No. 5-0000-0001-T2 Rev A
FC FO FC FO
FC
FC FC FO FC FC FO
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OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT, VRCFP, HPCL VISAKH
S.
Tag No.
Description
Doc No. Draft Rev. A Page 116 of 182
Action of CV
No
on Air failure
. 17. FV-1701 Light gasoline to storage 18. FV-1702 FCC Heart cut gasoline to storage 19. FV-1703 Light gasoline pump min. fliow line HDS FEED SECTION: 20. FV-1801 HDS feed pump min. flow line 21. FV-1901 HDS feed to HDS feed/Eff. Exchanger 22. FV-1902 HDS Feed / Eff Exchanger bypass 23. FV-1904 HDS recycle HDS REACTION SECTION 24. FV-2001 Quench to reactor 25. FV-2002 Quench to reactor 26. FV-2003 Diluant line for start up 27. FV-2101 Plant air to HDS Reactor Feed Heater HDS SEPARATOR SECTION 28. FV-2401 Quench pump min. flow line 29. FV-2402 Stabilizer feed line 30. LV-2401 Sour water boot RECYCLE GAS KOD AND AMINE ABSORBER SECTION: 31. FV-2501 Lean amine to preheater 32. TV-2501 LP steam to preheater 33. LV-2501 HC liquid from Amine KOD 34. LV-2601 Rich amine to amine unit 35. FV-2601 Sweet purge gas to FG header 36. LV-2701 Amine from Recycle compressor K.O. drum to ARU 37. FV-2701 Make up H2 to Recycle Compressor K.O. Drum 38. FV-2702 Make up H2 to Recycle Compressor K.O. Drum STABILISER COLUMN: 39. FV-3001 Reflux to Splitter 40. FV-3002 VHP condensate from stabilizer reboiler 41. FV-3003 Stabilizer bottom pump min. flow line 42. LV-3001 VHP Condensate from Condensate Pot 43. FV-2901 Heavy gasoline to stabilizer feed / bottom exchanger 44. PV-3101 Sour purge gas From stabilizer reflux drum 45. LV-3101 Sour water to sour water treater
7.7.2 SL
FC FC FO FO FC FC FC FO FO FO FC FO FC FC FC FC FC FC FC FC FC FC FO FC FO FC FC FC FC
ON-OFF VALVES TAG NO.
DESCRIPTION/LOCATION
NO. SHU FEED SURGE DRUM: 1. UV-1101 FCC Gasoline Feed to SHU Feed Surge Drum
Template No. 5-0000-0001-T2 Rev A
ACTION
ON
AIR FAILURE FC
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OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT, VRCFP, HPCL VISAKH
SL
TAG NO.
DESCRIPTION/LOCATION
UV-1202
Effluent Exchanger H2 from Recycle Compressors to SHU Feed/Effluent
Exchanger SHU FEED PREHEATING SECTION: 7. UV-1301 VHP steam to SHU Preheater SHU SPLITTER SECTION: 8. UV-1501 SHU emergency depressurisation to flare 9. UV-1502 Heavy Gasoline from Splitter bottom 10. UV-1503 Splitter Reboiler steam inlet 11. UV-1701 Light gasoline to storage 12. UV-1702 FCC Heart cut gasoline to storage HDS FEED SECTION 13. UV-1901 HDS Feed to HDS Feed / Eff. Exchanger HDS REACTION SECTION 14. UV-2101 Plant air to feed heater 15. UV-2301 BFW injection at HDS Eff. Air condenser SEPARATOR DRUM: 16. UV-2401 Stabiliser Feed from Separator Drum 17. UV-2402 Separator Drum Boot Drain 18. UV-2403 Flare from Separator Drum for depressurisation AMINE ABSORBER: 19. UV-2501 HC liquid from amine KOD 20. UV-2502 LP steam to Amine preheater 21 UV-2503 Lean amine to preheater 22 UV-2504 LP condensate To 75-V-19 23 UV-2505 LP condensate To OWS 24. UV-2601 Rich Amine from Amine Absorber RECYCLE COMPRESSOR SECTION: 25. UV-2701 H2 from Recycle Compressor K.O. Drum 26. UV-2702 Make up H2 to Recycle Compressors K.O. Drum 27. UV-2703 Amine as Recycle Compressors K.O. Drum Drain 28. UV-2801 Recycle gas comp. discharge STABILISER COLUMN: 29. UV-3001 Heavy Gasoline from Stabiliser bottom to Stabiliser Bottom 30.
7.7.3
UV-3002
Page 117 of 182
ON
AIR FAILURE FC FC FC FC FC
FC FO FC FC FC FC FC FC FC FC FC FO FC FC FC FC FC FC FC FC FC FC FC FC
SAFETY VALVES:
S. No. 1. 2.
Pumps Stabiliser Reboiler Steam Inlet
Rev. A
ACTION
NO. 2. UV-1102 Heavy Gasoline Recycle from SHU Recycle Air Condenser 3. UV-1103 SHU Feed Surge Drum Boot Drain 4 UV-1104 Feed from FSD to Charge pump SHU FEED SECTION: 5. UV-1201 Gasoline from SHU Feed pumps to SHU Feed/HDS 6.
Doc No. Draft
Tag No. PSV-1101 A/B PSV-1102 A/B
Template No. 5-0000-0001-T2 Rev A
Description/Location
Set
Pressure
Feed Surge Drum Cold Feed Filter
(Kg/cm2g) 5.0 15
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OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT, VRCFP, HPCL VISAKH
S. No.
Tag No.
Doc No. Draft Rev. A Page 118 of 182
Description/Location
Set
Pressure
3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16.
PSV-1201 A/B PSV-1202 A/B PSV-1301 PSV-1401 PSV-1501A/B PSV-1502 PSV-1601/1602 PSV-1701/02 PSV-1703/04 PSV-2001 PSV-2101 PSV-2201 PSV-2301/2301 PSV-2401A/B /
Feed pump discharge SHU Feed to 75-E-03 SHU preheater condensate pot SHU Reactor From Gasoline Splitter to Flare Splitter reboiler condensate pot Sea water return from 75-E-04 Sea water return from 75-E-05A/B Sea water return from 75-E-06A/B First HDS Reactor First HDS heater outlet Fuel gas KOD Sea water return from 75-E-09A/B Flare from Separator drum
(Kg/cm2g) 37 37 40 35.1 8 40 7.6 7.6 7.6 36.5 31 9.0 7.6 27.5
17. 18. 19. 20. 21.
2402 PSV-2601 PSV-2701A/B PSV-2801A/B PSV-2802A/B PSV-2803
Flare from Amine Absorber Flare from Recycle Compressor K.O. Drum Recycle Compressor 75-K-01A Discharge Recycle Compressor 75-K-01B Discharge Recycle Compressor 75-K-01A Discharge
27.5 27.5 38.5 38.5 13
PSV-2804
(Regen. Case) Recycle Compressor 75-K-01B Discharge 13
PSV-2901/2902 PSV-3001A/B PSV-3002 PSV-3101/3102 PSV-3201/3202 PSV-3203/3204 PSV-3205
(Regen. Case) Sea water return from 75-E-12 A/B Flare from Stabiliser Column Stabilizer reboiler condensate pot Sea water return from 75-EE-14A/B Corrosion inhibitor pump discharge Sulfiding agent injection pump discharge Corrosion inhibitor drum
22. 23. 24. 25. 26. 27. 28. 29.
7.6 9.0 40 7.6 13.7 32 10.5
7.8 RELIEVE VALVE LOAD SUMMARY List of safety valves is already given in the previous section. Detail of relive load summary such as relieve valve tag, location, set pressure, capacity, failure scenarios considered are given in Flare Load Summary. Flare Load Summary is given in Annexure IV.
Template No. 5-0000-0001-T2 Rev A
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Doc No. Draft Rev. A Page 119 of 182
7.9 DETAIL OF INTERLOCK LOGIC AND TRIPS I.NO 101
CAUSE ACTUATOR DESCRIPTION DEVICE 75-LAHH-1103 Very high level in 75-UV-
103
SHU feed surge 1101 75-UVdrum 1102 Very low pressure 75-P-03
75-PALL-1604
EFFECT ACTION DESCRIPTION Close FCC gasoline feed Close
Hydrogenated
stop
gasoline recycle Pump 75-P-03 A/B
at
106 107 108
109
75-LALL-1701
75-P-03A/B operating 75-P-03 Start discharge spare Low level 75-PStop 04A/B chimney 75-P-05
75-LALL-1505
C-01
75-AT-2101
tray level low High O2 content
75-TAHH-
Very High temp in 2101
1403-1415 75-HS-
75-R-01 Case of fire
A/B 75-UV-
75-UV-
1102A(Board)
protection Spare pump auto start Light
gasoline
Stop
pump stops FCC heart
close
pump stop Air make up during
cut
regeneration Close
1104
Close
SHU
feed
surge drum bottom inventory valve
75-P75-HS-
Stops
Stop 75-P-01 A/B
Close
Boot drain to OWS
Close
VHP steam to 75-E-
01A/B
1102B(Local)
110
75-ZSC-1104
75-UV-1104
I-102
75-LALL-1106
CLOSE Very low level in 75-UVSHU feed surge 1103
111
75-PAHH-1510
drum boot Very pressure
high 75-UVat 1503
07 stop
splitter overhead 112
75-TAHH-2103
Very high temp in 75-F-01
75-HS-
any of the pass at
Template No. 5-0000-0001-T2 Rev A
Stop
Heater shutdown
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OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT, VRCFP, HPCL VISAKH
2102A(Board)
Rev. A Page 120 of 182
heater O/L
75-HS-2102B 113
(Local) 75-HS-
HDS
2401A(Board)
section
2502
75-HS-
depressurization
75-UV-
2401B(Local)
reaction 75-UV-
Close
LP steam to lean amine preheater
Close
Lean
2503 75-UV-
amine
to
Amine absorber Open
HDS
2403
reaction
section depressurization
75-UV-
Close
Stop feed to HDS
1901 75-UV-
reaction section Close
H2 make up
Stop
HDS heater burning
2702 75-F-01
off 75-UV-
Close
HC to stabilizer
Close
Rich
2401 75-UV2601 75-UV-
amine
to
amine unit Close
Close
3001
stabilizer
bottom
product
valve 75-UV-
Close
Recycle
2701 75-UV-
isolation Close
Recycle
2801 75-P-
comp comp
isolation Stop
Stop 75-P-01A/B
Actuate
Recycle comp KOD
07A/B I-117
interlock I-122
Actuate
Amine Low
absorber Low
level
interlock
Template No. 5-0000-0001-T2 Rev A
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OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT, VRCFP, HPCL VISAKH
114 115
117
Rev. A Page 121 of 182
75-LALL-2403
Very low level in 75-UV-
Close
HC to stabilizer
75-LAHH-2406
separator drum 2401 Very high level in 75-UV-
Close
BFW feed
Close
Rich
separator 116
Doc No. Draft
drum 2301
75-LALL-2602
boot Very low level in 75-UV-
75-LAHH-2704
Amine absorber 2601 Very high level in 75-K-
Stop
amine unit Stop Recycle comp
comp KOD
Close
Stop feed to HDS
75-FALL-2801
01A/B
Very low flow at 75-UVcomp discharge
1901
amine
to
reaction section Stop
Very low flow at comp discharge I-119
75-F-01
Heater shutdown
I-113 118
75-TAHH-2807 75-LALL-3002
Very low level in 75-UVstabilizer bottom
119
75-HS-
Case of fire
Close
Close
3001
stabilizer
bottom valve
75-P-
Stop
Stop 75-P-07A/B
01A/B I-117
Actuate
Recycle
2801A(Board)
comp
shutdown
75-HS2801B(Local) 75-ZSC-2801
75-UV-
Close
2801 75-ZSC-2701
75-UV-
75-PALL-3107
Very low pressure 75-P-09 at
121
75-HS-
75-P-09
Close
75-P-09
Case of fire
spare 75-UV-
Template No. 5-0000-0001-T2 Rev A
Recycle
comp
isolation
Stop
A/B operating
discharge
comp
isolation
2701
120
Recycle
Pumps 75-P-09A/B protection
Start
Spare pump auto
Close
start Close
stabilizer
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OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT, VRCFP, HPCL VISAKH
3002A(Board)
3001 75-P-
75-HS-
Doc No. Draft Rev. A Page 122 of 182
bottom valve Stop
Stop 75-P-07A/B
Close
Hydrocarbon liquid
07A/B
3002B(Local)
122
75-ZSC-3001
75-UV-3001
75-LALL-2502
Close Very low level in 75-UVamine KOD
I-113
2501
drain
HDS depressurisation
123
75-LALL-2702
inter lock Very low level in 75-UV-
124
75-FALL-1903
RGC KOD 2703 Very low flow at 75-UV-
Close
Hydrocarbon/Amine
Close
liquid drain Stop feed to HDS
HDS feed pump 1901 discharge
124
126
75-TALL-2003-
Very high temp in 2702
2019 75-AT-2101
first HDS reactor High O2 content
75-TAHH-
Very high temp in 2101
2003-2019
HDS reactor 75-
75-LALL-2407
R-02 Very low level in 75-UVseparator
127
75-UV-
75-PALL-2407
75-F-01 75-UV-
reaction section Close
OSBL Stop Stop
Close
Stop
LAL-3301
Pump
75-P-06
protection
operating 75-P-06
128
Close sour water to SWS
at quench pump 06A/B discharge
Heater shutdown Air to heater during regeneration
drum 2402
boot Very low pressure 75-P-
H2 make up from
spare Low level in CBD 75-P-11
Start
Spare pump auto
Stop
start CBD pump
drum
129
LAH-3301
High level in CBD 75-P-11
Start
CBD pump
LAL-3401
drum Low level in Flare UV-3401
Close
CBD Drain line
Template No. 5-0000-0001-T2 Rev A
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Doc No. Draft Rev. A Page 123 of 182
KOD LAH-3401
High level in Flare UV-3401
Open
CBD Drain line
Close
VHP steam supply
KOD 130
PAHH-
High-high
3012A/B/C
pressure
UV-3002 at
to 75-E-13
stabilizer O/H. 7.10
EFFECT OF OPERATING VARIABLES ON THE PROCESS
7.10.1 OPERATING PARAMETERS The
operating
parameters
are
the
variables
affecting
the
process
performance, which the operator can actually adjust in order to improve or restore the unit performance. The purpose of process: To perform the desulfurization of the gasoline. Regarding product specifications, refer to the process book. To limit octane losses. The operating parameters used to meet these specifications with an optimum catalyst life are the following: Reactors inlet temperature Make-up hydrogen and recycle hydrogen flowrates leading to the hydrogen partial pressure at outlet of the reactors, the hydrocarbon partial pressure, the hydrogen sulfide partial pressure. The space velocity (i. E. Feed rate). Operator action on these parameter enables the unit to match different feed and product qualities provided they are within the basis of design of the unit. 7.10.2 REACTOR TEMPERATURE 1. Selective Hydrogenation section: A temperature increase favors di-olefin hydrogenation but also olefin hydrogenation and coking, which reduces the cycle length. Moreover a high
Template No. 5-0000-0001-T2 Rev A
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Doc No. Draft Rev. A Page 124 of 182
temperature can lead to excessive vaporization in the reactor which is theoretically in liquid phase. This may lead to problems with liquid distribution and pressure drop. The temperature increase in the selective hydrogenation reactor is a function of the diolefin content and H2/HC ratio. Moreover, reactions of oligomerisation can take place if the temperature is too high, leading to gum formation. In practice, the operating temperature will be set so that the exothermicity starts to be perceptible. The hydrogen make-up will be adjusted so that the heavy FCC gasoline MAV is decreased below 2.(Diene value < 0.5) 2. HDS reaction section: The reactor inlet temperature is adjusted at the value required for gasoline product sulfur specification without a great loss of olefins. However, because fresh catalyst is very active, it is sometimes possible to operate at a lower temperature at start-up. A temperature increase favors all the following reactions: desulfurization, hydrogenation of olefins and coking. The latter also reduces the cycle length. Accordingly, the temperature at reactor inlet must be adjusted at the lowest value which enable to meet the product specifications. The temperature increase in the first HDS reactor (75-R-02) is a function of the olefin content and the olefin hydrogenation level, but the T is controlled by the quench. The reactor weighted average bed temperature (WABT) is the main parameter used to adjust product sulfur content. The WABT is controlled by the first HDS reactor inlet temperature and the quench rate (adjusted to limit the HDS reactor exotherm). Increasing WABT results in lower product sulfur (higher HDS) and additional olefin hydrogenation. Typically, during operation, when the unit is lined out at design capacity and the stabilizer bottom product is on-spec there are only a few cases when the operator needs to adjust the reactor inlet temperature. In NIT case, non selective mode, the reactor exotherm is limited at 50 0C and controlled by the liquid quench between the first and second bed and between second and third bed. Some part of the hydrogenated product from the
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Doc No. Draft Rev. A Page 125 of 182
separator drum 75-V-03 is recycled and mixed with the HDS feed for olefin dilution. In AM case; selective mode, the exotherm in the HDS rector is controlled at 200C by the liquid quench of the HDS reactor. 7.10.3 OTHER PARAMETER 1. Coke accumulation on the catalyst surface: Coke can have 2 different origins. Catalytic coke During the catalyst cycle, coke may build-up on the catalyst surface within the pores, reducing the reaction surface and consequently the activity. An adjustment will be required on the Reactor inlet temperature to compensate for this activity loss. This change is very gradual over the catalyst cycle and depends upon the feed quality. Coke formation due to coke precursors in the feed This coke formation is due to a combined action of dissolved oxygen, rust and temperature. Therefore, it is very important to be careful with the quality of the feed especially to limit content of compounds containing the carbonyl bound (C=O) and the rust content. This formation of coke leads to a higher P in reactors and decreases the catalyst cycle. The coke formation due to coke precursors in feed is more important than catalytic coke. 2. Feed quality changes a) Higher level of contaminants If there is a higher level of contaminants in the feed, the operator must increase
the
reactor
inlet
temperature
until
the
efficiency
of
the
hydrodesulfurization reactions is restored.
b) Higher sulfur content
Template No. 5-0000-0001-T2 Rev A
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Doc No. Draft Rev. A Page 126 of 182
If the sulfur content of the feed is higher, the operator must increase the reactor inlet temperature to reach the same sulfur specification. c) Higher olefin content In order to avoid high exothermicity, the olefin content must be lower than 35% vol. The reactor inlet temperature needs not to be increased for a higher olefin content. Quench and eventually top bed diluant shall be adjusted to control the T through the catalytic beds. 3. Major changes in feed rate As catalyst activity is higher with a lower space velocity, then the reactor inlet temperature at 60% capacity should be different from the one at 100% capacity. The operator can decrease the reactor inlet temperature at lower space velocity and therefore preserve catalyst cycle length. The end of a catalyst cycle is reached when the following takes place:
The catalyst deactivation is such that it is no longer possible to meet the product specifications.
The maximum allowable temperatures have been reached.
The pressure drop in the reactor is too high.
In this case, the catalyst must be regenerated ex-situ.
7.10.4 MAKE-UP H2 AND RECYCLE H2 FLOW-RATES 1. Hydrogen partial pressure at reactors outlet. a) First section – Selective Hydrogenation Reactor 75-R-01 The H2/HC ratio increases by feeding more make-up hydrogen gas. This enhances both the di-olefin hydrogenation and the mercaptan removal reactions and decreases the coke formation rate. However, if the H 2 excess is too high, it could lead to excessive vaporization of naphtha creating problems in distribution and pressure drop in the reactor. It would result in excessive loss of light FCC gasoline at the splitter vent gas and excessive olefin saturation. The hydrogen rate is set to decrease the MAV in the heavy FCC gasoline product below 2.
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Doc No. Draft Rev. A Page 127 of 182
b) Second section - HDS reactor 75-R-02 The hydrogen partial pressure is defined by the following formula ppH2 = reactor outlet pressure
number of H 2 moles number of total moles
The ppH2 at reactor outlet is a function of: The total pressure (which is fixed at the design stage and is beyond the reach of operators). The hydrogen excess versus the chemical consumption, which depends on the amount of hydrogen gas make up, and the hydrogen purity (which is also beyond the reach of operators). The required ppH2 is achieved when the HDS section is operated at pressure - around 15 Kg/cm2g at the separator drum (AM case, selective). - around 21.5 Kg/cm2g at the separator drum (NIT case, nonselective) In terms of activity, an increase of the hydrogen partial pressure enhances the hydrodesulfurization and hydrogenation of olefins. In addition, a high hydrogen partial pressure reduces the polymerization reactions and coke deposit, increasing the catalyst cycle length. Actually ppH2 is not a variable that operators adjust but they have to ensure that it is always around the design value. The design ppH2 is fixed by the system pressure, hydrogen recycle rate and hydrogen gas purity. If the recycle gas purity decreases due to lack of make-up gas, the hydrogen partial pressure will decrease as well. The operator must maintain the hydrogen recycle quality within the design range by adequate purge and hydrogen makeup. By increasing the PPH2, the olefin and H2S partial pressures decrease and then selectivity is improved. 2. Hydrocarbon partial pressure ppHC = pressure
number of moles of hydrocarbons number of total moles
The ppHC is a function of: The total pressure. The hydrocarbon contents i.e. feed rate.
Template No. 5-0000-0001-T2 Rev A
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Doc No. Draft Rev. A Page 128 of 182
The hydrocarbon partial pressure has no impact on the hydrodesulfurization. On the other hand, to minimize hydrogenation of olefins, it is necessary to minimize olefin partial pressure therefore hydrocarbon partial pressure. For instance, if the feed flowrate is 60% of the normal flowrate, it would be better not to decrease the H2 flowrate. Indeed, the ratio H2/HC will increase and the selectivity will be enhanced. 3. Hydrogen sulfide partial pressure The ppH2S is a function of: The total pressure. The H2S content. H2S
has
no
real
impact
on
olefin
hydrogenation
but
affects
hydrodesulfurization. Therefore, it is necessary to have a low H 2S content to enhance selectivity; this means to maximize the performance of the amine absorber. 7.10.5 SPACE VELOCITY (FEED RATE) Space velocity coupled with reactor inlet temperature defines the severity of the hydrotreatment. Severity is increased when either the space velocity is decreased or the temperature is increased. Space velocity as defined earlier is the amount of liquid feed (expressed in weight or volume) which is processed per hour divided by the amount of catalyst (in weight or volume). The inverse of the space velocity is related to the residence time or contact time in the reactor. As the quantity of catalyst is fixed, the space velocity will change by varying the feed rate. Decreasing the feed rate decreases the space velocity. At constant temperature this increases the activity as there are now more catalyst active sites per unit of feed. This will improve the hydrotreatment efficiency. For small changes in the feed rate, no action is required by the operator. For large reductions however, the operator may lower the reactor inlet temperature to preserve the cycle length. It is recommended that, if an adjustment to a new temperature level is considered, the reduction must be in increments no greater than 2°C until the new stable performance level is reached. In general the following rules are valid: Template No. 5-0000-0001-T2 Rev A
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In case of feed is to be increased: first increase the temperature, then increase the feed rate. In case of feed is to be decreased: first decrease the feed rate, then decrease the temperature. These measures are required to keep the safe side of the gasoline quality. 7.10.6 FEED QUALITY 1. Contaminant content Feed quality is an indirect variable, a variable that the operator reacts to rather than adjusts for performance control. The unit is designed for a particular feedstock with a maximum design level of sulfur, Nitrogen, Mercury, Arsenic and with other contaminant levels defined within the normal range of most crudes. As the feed quality changes during processing of different crudes i.e. higher levels of nitrogen and sulfur, the operator must raise the reactor inlet temperature to maintain unit performances. Prior to a crude change, the operator must be made aware of potential higher contaminant levels than the previous crude by reviewing the crude essays. For new crude, the raw gasoline feed to the unit must be thoroughly analyzed for all contaminants including metals. If possible, this must be done prior to feeding the unit but if not, as early as possible. This will avoid a higher rate of catalyst saturation due to higher metals content. Moreover, it is important to be careful with the content of compounds with carbonyl bound (C = O) and of rust. Indeed, a combined action of dissolved oxygen, rust and temperature leads to a coke formation, which increases P in reactors and decreases the catalyst cycle.
2. Di-olefin content Di-olefin content higher than the design means an increased exothermicity for the Di-olefin reactor. As there is no quench or diluent on them, an increase of diolefin content in the feed induces a higher T across the catalyst bed. This results in a shorter cycle length. If all the di-olefins are not hydrogenated in the Diolefin reactor, they will reduce the second reactor cycle length.
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3. Olefin content Olefin content higher than the design in the heavy FCC gasoline fraction of the feed means an increased exothermicity for the HDS reactor. This can be compensated, in order to keep the same WABT, either by decreasing the inlet temperature or by higher quench and diluent flow rates. If these conditions are not sufficient, then the feed flow rate has to be reduced, while maximizing the diluent rate and quench.
SECTION- 8 SHUTDOWN PROCEDURES
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8.1 NORMAL SHUTDOWN PROCEDURE 8.1.1
INTRODUCTION Normal shutdown applies to a shutdown planned in advance for preventive maintenance or to unexpected events which are not of an emergency nature. Before initiating any planned shutdown, review all records to determine what inspections and repair work must be accomplished during the shutdown. Prepare a shutdown schedule, including plans for pre-arranging feed and product inventories during turnaround time. Notify all services and other dependent operating units of the schedule so that all activities can be properly coordinated. Arrange for all required parts, tools and services in advance, in particular adequate nitrogen for purging. While shutting down the unit due to maintenance or emergency care must be taken not to admit air into the system until all hydrocarbon vapours have been removed. Operators should be thoroughly familiar with shutdown procedures and understand the reasons for each work. Good judgement must be exercised as no written procedure can completely cover all details or problems that can arise in an emergency. Judgement is more likely to be exact if prior thought and planning have been made Precautions During shutdowns, precautions must be taken to avoid the following, whether planned or unplanned: Exposing personnel to toxic or noxious conditions when equipment is drained or depressurised. Fire possibilities when the reactors are opened, due to explosive hydrogenoxygen mixtures, or exposure of pyrophoric material to air.
8.1.2
PREPARATIONS FOR A PLANNED SHUTDOWN For a planned shutdown some work can be done in advance, such as:
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Prepare blind lists and blind list accounting procedures for required isolations. Have test equipment onsite for: Explosive Gas and Hydrogen Analyzers Oxygen Analyzers (If Vessel Entry is Planned) If inert atmosphere entry into the vessels is planned, have the necessary personnel protective equipment on hand. Have the necessary materials onsite to complete the shutdown. Inform all interested parties of shutdown plans. Have temporary piping spools, blinds, gaskets, etc., onsite. Erect staging (scaffolding). Ensure adequate storage space is available in the off plot storage system. Plan for any unbalanced utilities. 8.1.3
GENERAL PROCEDURE When shutting down, steps should be taken to prevent catalyst or equipment damage from expansion, contraction, thermal shock or unusual pressure surges. Purge with care all vessels, using inert gas and steam until all equipment is free of hydrocarbon liquids and gases. Purge thoroughly and check the atmosphere in the vessels before entering or starting repairs. Rigorously observe all safety precautions. The general procedure to be followed for a total shutdown is the following: Lower the capacity and if necessary the severity. Switch the product to off-spec. or raw storage. Shutdown the Reaction section. Drain all hydrocarbons. Depressurize and purge. Several shutdown cases are considered : Short duration shutdowns (i.e. less than 24 hours). Long duration shutdowns. Shutdowns to be followed by catalyst regeneration or inspection of equipment.
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SHORT PERIOD SHUTDOWN This shutdown is typically less than 24 hours to carry out minor repairs without opening any major equipment. Reduce unit capacity to 60% of normal feed rate. It should not be necessary to adjust the reactor inlet temperatures immediately before the shutdown. Maintain hydrogen gas flow rate and make-up hydrogen through selective hydrogenation reactor. Disconnect the level cascaded controllers on the separator drum 75-V-03, and on the Stabilizer bottom while keeping normal flow rates. Switch the products to off-spec storage. (light cut, heart cut and heavy FCC gasoline) Shut down steam flow to the SHU feed steam heater 75-E-03 to decrease inlet temperature to selective hydrogenation reactor at least down to 10°C below the normal temperature. The make-up H2 supply to the selective hydrogenation reactor is also stopped. Reduce the temperature at the inlet to the first HDS reactor 75-R-02 by decreasing firing in 75-F-01 at a rate of 40°C per hour down to 180°C. Close block valves on liquid flow outlet from the separator drum 75-V-03 when level decreases below 30%. Shutdown DEA solution circulation through the Amine absorber and open the bypass line of absorber. When the selective hydrogenation reactor temperature is at least 10°C below the normal temperature, and levels in splitter and stabilizer have decreased, shut-off level control valves. The evacuation of stabilizer column 75-C-03 depends on pressure in the column. In order to avoid sudden decrease of pressure, the reflux flow rate must be reduced and fuel gas flow rate to reboiler heater is controlled consequently. The splitter and stabilizer shall operate at total reflux. Stop the fresh feed to the selective hydrogenation reactor 75-R-01. Close the block valves on the Splitter bottom. The SHU and HDS sections are now isolated.
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The circulation of hydrogen through the HDS reaction section is continued for a period of two hours to strip out hydrocarbons from the catalyst. The unit is now considered to be on stand-by with gasoline feed stopped, hydrogen circulating through the HDS catalyst beds at reduced temperature, splitter and stabilizer at total reflux. 8.1.5
LONG PERIOD SHUTDOWN This shutdown is required for major repair of some equipment or some sections of the unit. The procedure described above for short period shutdown is followed, but completed to full cooling of equipment to ambient temperature. After two hours stripping of catalysts with circulation of hydrogen and make up hydrogen gas flow through reactor 75-R-01 the temperature is decreased gradually to 100°C at 40°C/h. At temperature of 100°C at inlet to reactors 75-R-01, 75-R-02, the firing in heater 75-F-01 stopped. The hydrogen recycle gas compressor 75-K-01 A/B remains in operation until temperature in HDS catalyst beds is below 50°C. The hydrogen make up remains also in operation until the 75-R-01 reactor beds temperature is below 50°C. The HDS reaction section shall be isolated from other section of the unit and kept under pressure of hydrogen gas, provided that no repair or equipment opening is required in this section. Splitter and stabilizer sections are shutdown by closing steam to reboiler. The air cooled condensers are shutdown and water flow to trim coolers closed when pressure drops below 2 to 3 Kg/cm 2g. The extended period of shutdown requires to introduce nitrogen to the feed drum 75-V-01, and reflux drums 75V-02, 75-V-05 in order to keep equipment under positive pressure. NOTE: 180oC is the maximum allowable at which hydrogen can be circulated on the catalyst without any risk of desulfiding. i.e. (Metal sulfide + H2 ------ H2S + bare metal).
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8.1.6
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SHUTDOWN FOLLOWED BY MAINTENANCE, INSPECTION OR CATALYST UNLOADING Shutdown for this purpose requires the complete removal of hydrogen and hydrocarbons from the equipment. The equipment of reaction section must be purged with nitrogen before admission of air. The equipment involving the splitter and the stabilizer must be steamed out. The first steps of shut down are the same as used for long period shutdown described above. The reaction section of selective hydrogenation reactor and reaction section of HDS reactor with compressor should be isolated from the remaining equipment. a) Selective Hydrogenation Reaction section 75-R-01 The reactor section should be isolated from splitter and feed section at outlet of SHU feed steam heater 75-E-03 and at inlet line to splitter. The system is depressurized to the flare system. The remaining pressure should be slightly above atmospheric pressure to avoid entry of air. The rest of the equipment is drained and N2 purged. b) HDS Reaction section 75-R-02 The reaction section should be isolated from the splitter and the stabilizer section by closing valves on discharge of 75-P-02 A/B pumps, and on stabilizer inlet line. The system is depressurized to the flare to a pressure slightly above atmospheric. The amine solution in 75-C-02 is displaced to the refinery regenerator before depressurizing this section. The recycle compressor 75-K-01 A/B is isolated depressurized and purged with nitrogen. The block valves on amine absorber are closed. The remaining amine solution is drained to sewer. The absorber is filled with demineralized water. The start-up ejector 75-J-01 is lined to the separator drum 75-V-03 outlet line and gases are evacuated. The system is filled with nitrogen, pressurized, released to flare and then evacuated by the ejector. The repeated operation allows to reach the decrease of hydrogen and hydrocarbon concentration below the explosive limits. The explosive meter is
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used to check the limit at which vessels can be opened for entry of atmospheric air. Care should be taken given the fact that catalyst pores retain some hydrocarbons and some time is needed for their release. The period of time of 1-hour minimum is required to ensure that hydrocarbons are released and tests show less than 0.5% vol of hydrocarbons. When the catalyst remains in the reactors and only other parts of equipment are subject of opening, close the reactor block valves and keep a positive pressure of nitrogen in the reactors from 0.5 to 0.8 Kg/cm2g. When catalyst is to be unloaded, the pressure is decreased to atmospheric by opening the top flange and the catalyst is discharged by catalyst unloading nozzles. Before entering any vessel, the testing for explosiveness, H2S content and oxygen content is mandatory. c) Splitter and stabilizer sections All vessels, exchangers and piping are free from hydrocarbons by pumping and draining to sewer. The content of splitter bottom sent to off spec tank via stabilizer. The remaining hydrocarbons in the splitter, reflux drum and piping should be drained to closed hydrocarbons collecting system. The stabilizer bottom should be sent to off-spec storage. The remaining liquid must be drained. Take care not to pass hydrogen. When all the liquid is drained from the system, temporary steam hoses are connected to pumps, columns, and drums and steam out operation started. This operation is usual in refineries and familiar to operators. After steam out, cooling down the equipment is ready for opening of manways, dismounting of flange joints, etc. Before entering any vessel, the testing for explosiveness and hydrogen sulfide presence is mandatory.
Important notes 1. Entry of personnel to vessels needs particular safety precautions. Vessels operating in presence of H2S may contain sulfides adhered to the surface of Template No. 5-0000-0001-T2 Rev A
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metal. These sulfides are pyrophoric and may release H 2S. The forced ventilation and permanent supervision is required on vessels subject to work of personnel inside these vessels. 2. The nitrogen purge does not mean that vessel is ready for entering of personnel. Nitrogen is suffocating gas leading to death. The vessels must be fully vented and tested for oxygen content before admission of personnel entry. The "dead" spaces in vessels such as down comers, separation weirs, etc. must be considered. 8.2 UNIT RESTART Any unit restart procedure derives from the first start-up procedure. The unit status after the shutdown will dictate the point where the general start-up procedure can be resumed. For instance during a feed pump shutdown for a short duration, the unit would be kept on standby with the make-up hydrogen flowing at full capacity, the heater on and the reactor temperatures slightly lowered. The columns would have no feed but the reboilers would be on and circulating at lower temperatures. In this case, the restart procedure would begin at the steam-in step with levels already in the vessels. For a long duration shutdown, the unit has been cooled down, the SHU reaction section filled with gasoline, the HDS reaction section left under pressure of hydrogen and the columns under a nitrogen pressure. The restart procedure will include the following steps: Start the columns at total reflux by admission of steam to reboiler and inert naphtha via start-up lines. Re-pressurize the reaction section to the operating pressure. Start the 75-P-01 A/B pumps and feed the selective hydrogenation section at 60% of normal flow with raw gasoline. The 75-E-03 feed steam heater is started by admission of steam. The gasoline from the SHU reactor is sent to the splitter 75-C-01, the light, heart cut and heavy FCC gasoline products from the splitter are sent to the off-spec storage.
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The HDS reaction section is started with circulation of hydrogen gas through the recycle compressor 75-K-01 A/B. The heater 75-F-01 is put in service and temperature gradually increased up to 180°C. The Amine absorber, filled with hydrogen, is lined up with other equipment of the HDS reaction section, and the recycle gas circulated through the absorber. Start circulation of amine solution. When the products are on-spec, the splitter and the HDS section can be connected. The heavy FCC gasoline product from the splitter is routed to the HDS reacton section and stabilizer section. When the product is on specification, slowly increase feed flowrate in steps of 5% up to 100%. Catalyst sulfiding is not necessary if the catalyst has not been regenerated or exposed to air during the long shutdown.
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SECTION- 9 EMERGENCY SHUTDOWN PROCEDURE
9.1 EMERGENCY SHUTDOWN PROCEDURE 9.1.1
GENERAL Emergencies must be recognised and acted upon immediately. The operators and supervisory personnel should carefully study in advance, and become thoroughly familiar with, the steps to be taken in such situations. While some of the emergencies listed in this section may not only result in a unit shutdown, they could cause serious trouble on the unit if not handled properly. In
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addition, damage to the catalyst might occur. In general the objective of the emergency procedures is to avoid damage to equipment and catalyst. Hard and fast rules cannot be made to cover all situations, which might arise. The following outline lists those situations, which might arise and suggested means of handling the situation. Emergency shut down by Operators Loss of feed Loss of cooling water Lack of hydrogen make-up Loss of Amine Quench pump failure Fuel gas failure Steam failure Instrument air failure Power Failure Automatic shut down 9.1.2
EMERGENCY SHUTDOWN BY OPERATORS General Typically, the following measures must be taken in an emergency situation to shutdown a reaction unit: SHU reaction section: Stop the feed steam heater 75-E-03. Close the H2 make-up supply. Shut-off the liquid feed to the reaction section. Fully bypass SHU preheat train exchanger 75-E-01 and 75-E-02. Stop LCN pump 75-P-04A/B Stop FCC heart cut pump 75-P-05 A/B. HDS reaction section: Shut-off the heater 75-F-01. Stop the feed to the reactor. If necessary, cool the reactor down through circulation of hydrogen.
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When possible, the H2 circulation is maintained. Otherwise, stop the compressor 75-K-01 A/B. Close the H2 make-up. Close the inlet/outlet lines on the Amine absorber. Close the liquid outlet on the separator 75-V-03. Close the purge gas on outlet of 75-C-02. Close water outlet on the separator and BFW feed at upstream of 75-A-03air cooler. As a last resort, partial or total depressurization can be used to cool the reactor down by opening the Emergency Shutdown Push Button on the separator drum from control room or on site. This unit is equipped with certain emergency shutdown controls which will automatically place the unit in a non-hazardous status should a major failure occur. The actions of the emergency shutdowns are aimed at protecting (a) the personnel and (b) the catalyst and equipment from heavy coking or serious damage. Personnel and equipment protection also results from the following: Personnel having a satisfactory knowledge of the safe operating and shutdown procedures. A compliance with the safety rules in plant construction i.e. safety distances, adequate orientation etc. The installation of adequate fire and gas detection devices and fire fighting equipment. Adequate operator safety awareness and procedures training. Concerning the catalyst preservation, operators must avoid : An excessive catalyst temperature gain which can change the structure of the alumina (> 700°C). To avoid damaging the catalyst structure, bulk temperature must never exceed 500°C. Note that the design temperature of the reactor (under design pressure) is much lower.
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The presence of hydrocarbons without a sufficient hydrogen quantity which would result in a rapid coke deposit and the possible agglomeration of catalyst particles. The following sections cover most situations operators may have to face according to Axens' operating experience. All operating personnel must study and fully understand the steps to be taken in such situations prior to the unit start-up. Many of these situations are handled by automatic shutdown trips. These trips must always be operational, by-passing must be kept to a minimum e.g. during start-up, transient periods only. The following procedures include all the actions to be taken by the operator assuming no action by the automatic devices. Some of the following situations may end up in an emergency shutdown. If the right and prompt action is taken, an orderly normal shutdown is possible. 9.1.3
LOSS OF FEED A loss of feed may be due to feed pump failure with an unexpected delay in starting the spare pump or, more commonly, from leaks or other difficulties in the feed line requiring an interruption of the feed. Loss of feed at the gasoline feed pump is instantaneous and requires immediate action. SHU section: If feed is still available to do this operation: Stop the heater 75-E-03. Close the H2 make-up supply. Reduce the unit capacity to 60% of the feed capacity. Switch the products to off-spec storage. Stop the unit feed when the reactor temperature is at least 10°C below the normal temperature. Close the LCN line (from draw off tray) to storage and stop LCN pump 75-P04A/B. Close the FCC heart cut line (from draw off tray) to storage and stop FCC heart cut pump 75-P-05A/B. Allow the splitter to operate on total reflux.
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If interruption is to take place for several hours, short shutdown procedure should be implemented. When flow to the reactor is re-established, start H 2 feed and return to previous operating temperatures if the feed is shortly recovered. HDS section: In case of short period loss of feed to the HDS section, Maintain H2 circulation. Allow the stabilizer to operate on total reflux. When the level in the stabilizer starts to fall, close the valves on the stabilizer bottom and heavy FCC gasoline line to storage. Maintain these conditions until feed is available again. Maintain pressure in the HDS reaction section by hydrogen make-up. Start-up again from former current reactor operating temperature if the feed is recovered shortly. If not proceed with the normal shutdown as previously explained (Refer to section “Shutdown of the unit/ Normal shutdown/ Short duration shutdowns”). Do not leave catalyst under a hot hydrogen circulation for more than 12 hours, unless the H2S content in the recycle is maintained between 100-200 ppm vol. Note also that an increased H 2S content while circulating hot hydrogen would be the sign of a catalyst desulfiding and would require the cooling down of the catalyst bed. 9.1.4
LOSS OF COOLING WATER In case of partial or total cooling water failure, the splitter and stabilizer overhead will be hotter, and the products to storage will be hotter than normal. Also, the HDS reactor effluent will be hotter before entering the HDS separator drum 75-V-03 and vapour phase will be larger leading to a potential pressure increase of the HDS section. Reduce the steam flow to the splitter and stabilizer reboiler, 75-E-07/75-E-13 and eventually stop it if the cooling water is not recovered. Increase the air coolers to their maximum capacity if possible.
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Increase vapor purge in HDS section to recover H2 recycle purity as much as possible. Route the products to the off-spec storage. 9.1.5
LACK OF HYDROGEN MAKE-UP The reaction pressure will decrease quickly and if no action is taken, the catalyst will coke due to hydrogen shortage to saturate the cracked material. The feed rate has to be decreased rapidly to 50%. If at 80% of the normal operating pressure, the hydrogen is not restored to the reaction, the feed has to be cut by stopping the feed until the make-up gas is back or the normal shutdown procedure should continue.
9.1.6
LOSS OF AMINE Increase the reactor temperature to achieve the required HDS at a higher octane loss. The stabilizer operation should be monitored to control the H 2S in the heavy FCC gasoline product.
9.1.7
QUENCH PUMP FAILURE Reduce the firing of HDS reactor feed heater to maintain HDS reactor inlet temperature and to maintain the same WABT provided the reactor T is not excessive. Over temperature may cause the shut down of HDS feed heater 75-F01, stopping feed and H2 make-up.
9.1.8
FUEL GAS FAILURE The HDS reactor feed heater will shutdown shutdown as well as the reboiling of the splitter and stabilizer. Cut raw gasoline feed immediately and proceeds as per loss of feed. Follow refinery safety practice for isolation of fuel gas system.
9.1.9
STEAM FAILURE A lack of steam leads to SHU feed steam heater 75-E-03, splitter reboiler 75E-07 and stabilizer reboiler 75-E-13 failure.
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Cut raw gasoline feed completely, as unstable gasoline product with H2S cannot be sent to storage. Follow the same procedure as per loss of feed. 9.1.10 INSTRUMENT AIR FAILURE The valves take their safe positions according to the fail-open or fail-close specification. The loss of instrument air pressure is generally slow and there is time to proceed to a normal shutdown. 9.1.11 POWER FAILURE It is assumed that all electrical equipment in the unit will shutdown including air coolers, recycle compressor, and all pumps The operator shall complete the shutdown procedure with the following actions: Initiate the I-102 for stopping H2 make up and steam to steam heater 75-E03. Stop heater 75-F-01. Watch the tube skin temperature in heater. If there is an increasing trend, open the air damper and inject sufficient steam. Isolation of the feed and make-up gases Isolation of the product lines by closing control and block valves. Closing of block valve downstream control valve FV-2901 on stabilizer bottom outlet line. Shut-off steam to the reboiler of stabilizer and splitter. Maintain pressure in the reaction section. If necessary, inject nitrogen in the stabilizer to maintain pressure. There is a potential danger for increased hydrocracking in the reactors which are idle with no flow of hydrogen to strip the hydrocarbons. If power outage is suspected for a long duration, depressurize the reaction section to flare. If the critical equipment is fed by an emergency power supply, the operators must be familiar with the list of equipment that is able to be restarted immediately. In addition, the general philosophy is to restart the equipment in the following order: -
Air fin cooler
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The compressor, in order to resume the hydrogen circulation and cool down the reactors or to maintain the reactors inlet temperature after restarting the heater. The reflux pumps of the column, in order to bring under control the overhead temperature and pressure. The remaining electrical equipment is restarted as required by the start-up procedure. 9.1.12 FIRE OR MAJOR LEAK The following is only an overview of the steps to be taken during the discovery of a leak resulting in a fire. This section will be defined in detail by the Unit Owner and the Engineering Contractor according to the refinery safety philosophies and will include any safety devices (hardware or software) which may be added during detailed engineering. The following steps are described from a process point of view, mainly aimed at avoiding runaway reactions and protecting the equipment and catalyst. Shut-off fuel to heater by activating the fuel gas emergency shutdown system from the control room. Shutdown the raw gasoline feed pump, close the splitter and stabilizer feed and block-in. Shut-off steam to the reboiler of the splitter and stabilizer, and to the SHU feed steam 75-E-03. Isolate the unit: Block the feed, product and hydrogen make-up gas lines. Isolate the reaction section from the feed, splitter and stabilizer sections. Depending on the severity of the leak and its location, shutdown the hydrogen recycle compressor immediately, block-in and depressurize the HDS reaction section to the flare. Depressurize the splitter and stabilizer sections to the flare. Drain all the vessels to the hydrocarbon blowdown. As the depressurized hot vessels cool down, watch the pressure and inject N 2 as necessary to avoid a vacuum.
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Nitrogen purging and steam out should be considered for the splitter and stabilizer circuits. If a fire has occurred, then all the steps above will be taken while the fire fighting is taking place. Note, however, that the depressurizing step may be needed sooner than described above depending upon the gravity of the situation. If a small leak occurs in the heater, the hydrocarbons will ignite immediately in this confined area. Open the snuffing steam and the damper (if possible) and maximize the draft to keep the fire under control within the heater box. In case of extreme emergency, the reaction section can be depressurized to the flare, using the quick depressurization valve by actuating HS-2401 emergency shut down push button. 9.1.13 AUTOMATIC EMERGENCY SHUTDOWN The actions undertaken in any emergency situation must aim at the following: Protecting the operators. Protecting the equipment and the catalyst. Resulting in a safe situation compatible with an easy restart. Process vessels, heater, compressors are fitted with switches which actuate the corresponding devices to avoid damage of equipment in case that operating variable exceeds the threshold limits. Hereafter are summarized the causes and effects for the unit shutdown interlocks. Causes and effects for the equipment safety interlocks are summarized in the Process Book. Other interlocks have to be specified by Engineering Contractor or Manufacturer of equipment (heater, compressor, etc). In several cases, a number of actions are carried out by the emergency safety sequences. But operators must always check the satisfactory completion of the sequence and complement it as described. In addition they must be able to perform the safety sequence in manual mode, if needed. A few actions through hand-switches are left to operators judgement, who can anticipate the automatic action such as reactors depressurization.
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SECTION- 10 TROUBLE SHOOTING Template No. 5-0000-0001-T2 Rev A
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TROUBLE SHOOTING
This section offers some guidelines for trouble shooting various problems that may be encountered over the course of normal operation of the unit and effects on incoming / out going conditions. The information is given for the following general subject areas of the unit: 10.1.1 HIGH DIFFERENTIAL PRESSURE (P) IN THE REACTOR High pressure drop This unit is designed for a given maximum reactor pressure drop. During normal operation the pressure drop will be lower than indicated in the section 1.1.5 of the Process data Book. The reactor pressure drop indicator is transmitted to the DCS and the trend data will allow the operator to predict when the unit needs to be shutdown for catalyst skimming. P is strongly dependent on the feed quality (precursors of coke in the feed). That is why a special attention to the feed quality must be taken. The pressure drop of the HDS reactor, is also dependent on the performance of the selective hydrogenation reactor.
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Leak of SHU feed in HDS effluent / HDS feed in HDS effluent / stabilizer feed in stabilizer bottoms Since, for these 3 equipments, the fluid with higher sulfur content is at higher pressure, contamination of the hydrotreated gasoline is possible. When sulfur shows up in the stabilizer bottoms and all the proper corrective actions have been taken with no improvement, then it is highly likely that a leak exists in either the SHU feed/HDS effluent or reactor feed effluent exchangers or stabilizer feed bottoms exchangers. These leaks can be easily detected through sampling upstream and downstream. 10.1.2 CHEMICAL H2 CONSUMPTION INCREASE Hydrogen gas make up to Selective hydrogenation reactor 75-R-01 In normal operation, the H2 supply to the diolefin reactor is under flow ratio to the feed. Increased H2 consumption may result from excessive olefin saturation or higher diolefins content in the feed. Monitoring of the MAV at the splitter bottom should be used to adjust the make-up H2 rate.
Hydrogen gas make up to HDS reactor 75-R-02 This situation can occur if the olefins content of the feed is higher than expected, and also if the unit is oversaturating the olefins. The H2 consumption could be controlled by decreasing the reactor severity without impacting the product quality. 10.1.3 OCTANE LOSSES A significant octane loss means a too high olefin hydrogenation in the reactors. This could be controlled by decreasing the reactor severity.
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SECTION- 11 SAMPLING PROCEDURE AND LABORATORY ANALYSIS
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GENERAL
Control tests provide the information to the operating staff for making necessary adjustments to get the maximum output and “on-spec” quality products. The control tests are to be made at all steps to monitor the intermediate and final products whether or not they are at the desired specification. Samples are taken and analysed at regular intervals such that the operation of the plant are monitored and any deviation (from specification will indicate some mal operation / malfunction of the plant which can be spotted and rectified in time without undue loss of time and product. Sometimes, samples are taken to find out the effect of certain changes brought about in the operating conditions. The samples are to be taken with great care so that the samples are representative samples. The frequency of sampling, the type of analysis and points where samples are to be taken are attached as annexure. During guarantee tests some additional samples can be taken at higher frequencies that is also specified in the technical procedures prior to test run. The following guidelines should be followed while collecting samples. 11.2
SAMPLING PROCEDURE
a) Liquid Sampling Procedure (Non-Flashing Type) The person taking samples should wear proper or appropriate safety clothing like face shields, aprons, rubber gloves etc. to protect face, hands and body. Template No. 5-0000-0001-T2 Rev A
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1. Whenever hot samples are taken, check cooling water flow in the sample cooler is circulating properly. 2. Sample points usually have two valves in series. One gate valve for isolation (tight shutoff) and other globe valve for regulating the flow. Open gate valves first and then slowly open the globe valve after properly placing the sample containers. After the sampling is over, close the globe valve first and then the gate. Then again open the globe valve and drain the hold up between the gate and globe valve in case of congealing liquid. 3. Sample valve should be slowly opened, first slightly to check for plugging. If the plugging is released suddenly, the liquid will escape at a dangerously uncontrolled rate. Never tap the line to release the plugging. Call the maintenance gang to properly unplug the line. In case of congealing type samples, sample point should be equipped with copper coil type steam tracer. It should be ensured that steam tracing line is functioning normally. 4. The operator taking the sample should be careful to stand in a position such that the liquid does not splash on him and he has unobstructed way out from the sample point in case of accident. 5. While taking dangerous toxic material for sampling, it will act as an observer for safety. Proper gas mask is to be used. It is advisable to stand opposite to wind direction in case of volatile toxic liquid. 6. Sample should be collected in clean, dry and stoppered bottle. In case of congealing samples use clean dry ladle. 7. Rinsing of the bottle should be thorough before actual collection. 8. Before collecting, ensure that the line content has been drained and fresh sample is coming. 9. Gradually warm up the sample bottle / metallic can by repeated rinsing before collecting the sample. 10. Stopper the bottle immediately after collection of sample. 11. Attach a tag to the bottle indicating date, time, and name of the product and tests to be carried out. 12. A few products suffer deterioration with time. For example, the colour of the heavier distillates slowly deteriorates with time. So these sampls should be sent to laboratory at the earliest after collection. Template No. 5-0000-0001-T2 Rev A
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1. The samples after collection should be kept away from any source of ignition to minimise fire hazard. 2. Volatile samples (e.g. naphtha) should be collected in bottles and kept in ice particularly for some critical test like RVP.
b) High Pressure Hydrocarbon Liquid Samples (Flashing Type) The person who is taking sample should use personal protection appliances like apron, gas mask and hand gloves to protect himself. 1. Ensure that sample bomb is empty, clean and dry. 2. Connect the sample bomb inlet valve to the sample point with a flexible hose. 3. Open the inlet and outlet valves of the sample bomb. Hold the sample bomb. Hold the sample bomb outlet away from person. Keep face away from hydrocarbon vapour and stand in such a way that prevalent wind should blow hydrocarbon vapour away. Open the gate valve of sample point slowly till full open. Then slowly cracks open the regulating valve. One should be careful at the time of draining, because chance of icing is there. As a result, the formation of solid hydrates is a continuing process that leads to the plugging of valves. 4. When all the air in the hose and bomb are displaced as seen by the hydrocarbon vapour rising from the outlet of sample bomb close the sample outlet valve. Allow a little quantity of liquid to spill to make sure that the bomb is receiving liquid. Frosting will be an indication of liquid spillage. 5. Allow liquid hydrocarbon to fill the bomb. When the bomb is full up to the specified level, close both the valves on sample point. Close inlet valve on the sample point. 6. Carefully disconnect the hose from the sample bomb. To allow for some vapour space in the bomb for thermal expansion in case of overfilling, crack open the outlet valve of bomb and discharge a small part of the liquid. Close outlet valve. Template No. 5-0000-0001-T2 Rev A
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7. Closed sampling facilities are provided at some locations where it is not desirable to waste the costly product or if the material is toxic. For filling the sampling bomb, pressure drop across a control valve is usually utilised or across pump discharge & suction. Air is expelled from the bomb after it is connected to upstream of control valve or pump discharge side. The sample is then collected and bomb is detached after closing valves on both sides. 8. Send sample bomb to laboratory for analysis. Protect the bomb from heat exposure. c) Gas Sample For collection of gas sample that are not under high pressure and temperature, rubber bladders are used. For the operations under vacuum or low pressure, aspirator is used. For representative sample, purge the bladder 3 to 4 times with the gas and then take t he final sample. Use of 3 ways valve with bladder / aspirator will facilitate purging and sampling. Sample bombs are to be used for taking gas samples from high pressure and high temperature source. Procedure mentioned under high pressure liquid sampling (flashing type) is to be used. Sampling method and schedule: Sr. No. 1
Stream Feed FCC1&2
2
Cold
feed
storage
Analyse from Distillation
Method ASTM D86
Frequency/day 1
Sp. Gravity
ASTM D-1298
1
Sulphur spec
IFP 9416
As required
Total sulphur
ASTM D-2622
1
ASTM D-3227
As required
from Mercaptans Olefins
IFP
0104
/ 1
ASTM D1319
Template No. 5-0000-0001-T2 Rev A
Bromine number
ASTM D-1159
1
Diene (MAV)
IFP 9407
2 per week
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3
HDS feed
Doc No. Draft Rev. A Page 156 of 182
Diolefin content
IFP 0104
As required
Existing gum
ASTM D-381
As required
Total nitrogen
ASTM D4629
As required
RVP
NF M 07-007
As required
RON
ASTM 2699
1
MON Gas
ASTM 2700 IFP 9603
1 1
4
SHU H2 make up
5
chromatography HDS H2 make up Gas
IFP 9603
1
6
from isom unit chromatography HDS H2 make up Gas
IFP 9603
As required
7
from CCR unit Effluent 75-R-01
IFP
chromatography Olefins
0104
/ As required
ASTM D1319
8
Light
FCC
ASTM D-1159
As required
Diene (MAV)
IFP 9407
2 per week
IFP 0104 ASTM D86
As required As required
Sulphur spec
IFP 9416
As required
Sp gravity
ASTM D-1298
As required
Total sulphur
ASTM D-5453
1
ASTM D-3227
As required
Diolefin content FCC Distillation
gasoline
9
Bromine number
heart
gasoline
cut Mercaptans Olefins
IFP
0104
/ As required
ASTM D1319
10
Splitter drum off gas
Template No. 5-0000-0001-T2 Rev A
Bromine number
ASTM D-1159
1
Diene (MAV)
IFP 9407
As required
Diolefin content
IFP 0104
As required
RON
ASTM 2699
As required
MON
ASTM 2700
As required
NF M 07-007 IFP 9603
As required As required
RVP reflux Gas chromatography
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11
Stabilizer feed
Total sulphur
ASTM
Rev. A Page 157 of 182
D-2622 As required
after
H2S
washing Olefins
IFP
0104
/ As required
ASTM D1319
12
HDS purge gas
Bromine number
ASTM D-1159
As required
Diene (MAV) Gas
IFP 9407 IFP 9603
As required As required
Dragger tube IFP 9603
As required As required
Dragger tube IFP 9603
As required 1
Dragger tube ASTM D86
1 As required
Sulphur spec
IFP 9416
As required
Sp gravity
ASTM D-1298
As required
Total sulphur
ASTM D-5453
1
Mercaptans
ASTM D-3227
As required
Olefins
IFP
chromatography 13
Recycle
gas
amine 14
chromatography
H2S Recycle gas from Gas amine
15
H2S to Gas
chromatography H2S FCC Distillation
Heavy gasoline
0104
/ As required
ASTM D1319
16
Stabilizer gas
17
HDS
Bromine number
ASTM D-1159
1
Diene (MAV)
IFP 9407
As required
Diolefin content
IFP 0104
As required
RON
ASTM 2699
As required
MON
ASTM 2700
As required
IFP 9603
As required
Dragger tube ASTM D 1293
As required As required
purge Gas chromatography
H2S separator PH
sour water
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SECTION- 12 SAFETY PROCEDURE
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INTRODUCTION
Safety of personnel and equipment is very important.
Ignorance of the
details of the unit or the techniques of safe and efficient operation reduces the margin of safety of personnel and subjects the equipment to more hazardous conditions.
All the operating and maintenance crew therefore must be fully
familiar with the equipment and materials being handled in the unit, and recognise the hazards involved in handling them and the measures taken to ensure safe operations. Since the unit handles with one of the most potential source of fire and explosion like LPG; therefore adherence of safety rules should be given uphill importance. 12.2
PLANT SAFETY FEATURES
12.2.1 GENERAL Safety is the first consideration for all operations in the plant. Procedures, practices, and rules have been established as guides to assure a safe working environment. Safety also plays a major role in the efficient operation of the refinery facilities. This section is prepared to reemphasize the plant safety incorporated in the unit and equipment design. 12.2.2 EMERGENCY SHUTDOWN The emergency shutdown is already described These different shutdowns are completed by different trips to protect the main equipment and to prevent any misoperation. Alarms always precede these trips, they allow operators to have corrective actions before the automatic shutdown. 12.2.3 OVERPRESSURE PROTECTION Over pressure of equipment occurs in many ways. The basic reason of overpressure is imbalance in heat and material flow in one or more equipment. Pressure relief valves have been installed after careful evaluation of conceivable of overpressure sources. 12.2.4 SAFETY SHOWER AND EYE WASH Safety shower and eye wash stations are located in the chemical handling areas.
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12.2.5 OPERATIONAL SAFETY STATIONS The safety rules and instructions also emphasise safety hazards. Safe behaviour, practices and habits are necessary for safe and efficient operation of the unit. 12.2.6 HIGH PRESSURE On high-pressure lines, extreme caution must be taken when opening any sample or bleed valve. Improper opening or shut-off of some valves on interconnecting lines may result in exceeding pressure limits on vessels, exchangers, valves and lines. Improper isolation of lines vessels, exchangers, pumps may result in very high pressure due to thermal expansion of a liquid enclosed inside. 12.2.7 REACTOR PROTECTION Manufacturer of the reactors provides the following information necessary for the operation: Pressure versus temperature diagram, Rate of temperature increases and decreases, Rate of pressurizing and depressurizing the reactor, Risk of polythionic acids corrosion. 12.2.8 PERSONNEL PROTECTION The refinery personnel has to be aware of the different materials involved in the process: dangerous or toxic materials. Any chemical used in the plant should have its toxicity recorded and the first aid labeled. Hydrogen Hydrogen is a flammable gas, which in concentrations from 4.1 to 74% volume in air is explosive.Care must be taken to purge the air out of the unit as required before start-up and to purge hydrogen of the unit for shutdown.Tightness tests are to be made before all start-ups on every vessel containing or likely to contain hydrogen. Operators must continually inspect each equipment and flanges for leaks. All leaks require immediate action. The pressure reduction results in heating of hydrogen contrary to hydrocarbons, or other gases which are cooled down
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(Joule-Thomson effect). When heated above its ignition temperature by pressure release from high pressure the hydrogen gas starts to burn in presence of air. Hydrogen sulfide H2S a)
Physical properties
Physical state
:
gas
Color:
:
colorless
Boiling point
:
-79.2°F (-61.8°C)
Melting point
:
-117.2°F (-82.9°C)
Molecular weight
:
34.08
Specific gravity/air
:
1.189
b)
Chemical and hazardous properties Hydrogen sulfide is one of the most dangerous material handled in oil
industry. Two types of hazards must be taken into account: explosive nature, extreme toxicity when mixed with air or sulfur dioxide. The maximum safe concentration of hydrogen sulfide is about 13 ppm. Although at first this concentration can be readily recognized by its odor, hydrogen sulfide may partially paralyze the olfactory nerves to the point at which the presence of the gas is no longer sensed. Therefore, though the odor of the gas is strongly unpleasant, it is neither a reliable safeguard nor a warning against its poisonous effects. Hydrogen sulfide in its toxic action, attacks nerve centers. Early symptoms of poisoning are slight headache, burning of eyes and clouded vision. A concentration of 100 ppm of hydrogen sulfide in air causes coughing, irritation and loss of smell after 2-15 minutes and drowsiness after 15-30 minutes. A concentration of 1000 ppm of hydrogen sulfide in air can make person suddenly unconscious with early cessation of respiration and death in a few minutes. Hydrogen sulfide is a combustible material and, when mixed with air or sulfur dioxide, may be explosive. It is essential, therefore, to avoid such mixtures in the processing of hydrogen sulfide. The explosive range of hydrogen sulfide in air is from 4.5-45%. The ignition temperature of such mixtures is around 250°C.
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Some precautions against poisoning to be taken in working with hydrogen sulfide are: Closed in areas should be well ventilated preferably with forced draft. Equipment containing hydrogen sulfide should be tightly sealed. Any leaks should be repaired immediately. At seals or stuffing boxes where leaks might occur during normal operation, means should be provided for venting the escape gas to a safe location. Vessels should be purged of hydrogen sulfide before being opened. Masks furnishing purge air should be worn by personnel who are likely to be exposed to the gas. Personnel who may be exposed to even low concentrations of this gas should frequently retire to areas of fresh air. As a good safety measure, personnel should learn to recognize the early symptoms of hydrogen sulfide poisoning. c)
Detection of hydrogen sulfide A simple test with lead acetate solution on white paper will detect the
presence of hydrogen sulfide. Depending on the concentration the paper will turn yellow or brown. Adequate Dragger tubes can be used in the same way. d)
Personal protection Gas mask of appropriate type or positive air mask should be used.
e)
First aid A person unconscious in an atmosphere which may be contaminated with
hydrogen sulfide should be assumed to have hydrogen sulfide poisoning. This is a serious medical emergency and requires immediate attention. The affected individual should be immediately removed to a clean atmosphere, so that rescuers are not also exposed to hydrogen sulfide. Artificial respiration should be resorted immediately, if necessary, and the victim should be kept warm and at rest.
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DMDS The
material
safety
data
sheet
must
be
obtained
from
the
manufacturer/supplier. Catalysts The material safety data sheets for HR 845, HR 806, HR 841, ACT 065, ACT 077 and ceramic balls are attached in Attachment 12.3
SAFETY OF PERSONNEL
General safety rules, which shall be practised and enforces for all personnel who enter the unit, are summarised below: 1. Safety helmets and boots shall be worn by all personnel at all times in the plant. They may be removed when inside rooms or buildings that do not have overhead or other hazards. 2. Smoking shall be permitted only in specified areas, which are clad as nonhazardous and are pressurized through a ventilation system. Failure of the ventilation system automatically cancels the smoking privilege until the system is repaired, inspected and authorised operation. 3. Each employees assigned to work in the unit shall know where the safety and fire suppression equipment is located and how to operate this equipment. 4. Safety glasses, goggles or face shields shall be worn while performing work, which could result in eye or face injury. 5. Operations personnel golden rule Do not open or close any valve without first determining the effect.
6. Maintenance personnel golden rule: Treat each piece of equipment or piping as if it is under pressure.
12.4
WORK PERMIT PROCEDURE
The appropriate operations group must issue a work permit system before commencing any maintenance work affecting the operation of the unit. The work permit is issued for “Hot” and “Cold” work. The “Hot” work permit must include as a minimum, a precise description and mode of execution of “Hot” works, the equipment to be used, the expected time which “Hot” works is scheduled to start and expected completion, an exact location of the “Hot “ works and precautions to be taken.
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Unit areas are generally identified as hazardous areas as far as the threat of fire is concerned. Therefore, in order to carryout works within these areas, a written work permit is required. The work permit, when approved, indicates that a specific work can be carried out in safe conditions provided that all safety precautions are observed. a) Permit for “Hot” work Permits of hot works are required for any work involving the use of or generation of heat sufficient to ignite flammable substances. Typical sources of ignition are: Electric and gas welding Any machine capable of producing a spark Not explosion-proof electrical equipment Internal combustion engines Ferrous tools, both hand operated and pneumatic or other type b) Permit for Cold-Work Permits for cold-work are required for any work not involving the use of a local ignition source. Typical examples of cold work are: Disconnecting of lines for the insertion of blinds, etc Opening of any equipment such as vessels, filters, etc. c) Entry permits Entry permits are required for entering enclosed spaces such as vessels, sewer, pits, trenches, etc. The use of any tool or machinery, which could provide a source of ignition, is forbidden. Also, prior to entry it should be ensured that area is well ventilated and the oxygen content in air is about 21% by volume. A fresh airflow to be ensured in the enclosed space through out the duration of work. A gas test for H 2S and flammable gases should also be performed before entry. A person should also be on alert outside the enclosed space for rescue in case of emergency. Procedure
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for carrying out work and rescue plan shall be formulated before commencement of work. d) Guidelines for release of permits The equipment item, on which works have to be carried out, shall be clearly indicated. During the shutdown of any system, permits covering the whole section with above-mentioned item shall be issued, if possible. The type of work permitted shall be clearly indicated. The date and the period of validity of the permit shall also be indicated. If the work does not get over within the period of validity of the permit, the permit can be extended provided that, at each start of the works the safety conditions are checked again and signed by the operator in-charge and by safety officer. Beyond this extended period, a next permit will have to be issued. The explosiveness test and the check of toxic gases shall be performed always at the last moment before each start of the work and subsequently every time the work is resumed or whenever doubts arise. The validity of the permit can be cancelled at any moment by the operator or by safety officer in case they deem that the conditions are not safe. The conditions to be complied with shall include special precautions, such as the use of protective clothing, breathing apparatus, safety equipment and the tools to be used etc. No one shall be allowed to enter the vessel or other enclosed spaces without suitable protective clothing until the vessels or the enclosed spaces become safe for entry by means of proper isolation, proper ventilation and suitable check of the atmosphere inside and availability of rescue person outside the enclosed equipment. If welding or hot work is to be done ensure that Fire fighting system is ready Close the neighbouring surface drains with wet gunny bags Keep water flowing in the neighbouring area to cool down any spark. Responsible operation supervisor should be present at the place of hot work till the first torch is lighted.
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PREPARATION OF EQUIPMENT FOR MAINTENANCE
a) Process Equipment: Towers, Vessels etc. Before opening any equipment, it should be purged to render the internal atmosphere non-explosive and breathable. Operations to be carried out are: Isolation with valves and blinds. Draining and depressurisation. Replacement of vapours or gas by steam, water or inert gas. Take care about instrument tapping. Washing of towers and vessels with water. Ventilation of equipment. Opening of top manhole. Testing of inside atmosphere with explosive meter. Complete opening if inside atmosphere is satisfactory. Analyse the atmosphere inside for O2 content and any poisonous gas. Note:Open a vent on the upper part of the vessel to allow gases to escape during filling and to allow air inside the vessel during draining. Ensure proper ventilation inside the vessel by opening all manholes. For hydrocarbon or other gases, pressurise the vessel with N2 or gas and fill in the liquid and drain under pressure. This is to avoid hydrocarbon going to atmosphere. b) Precautions Before Handing Over Equipment A responsible operating supervisor should check following items before equipment is handed over for maintenance after it has been purged. Assure that equipment is isolated by proper valves and blinds. Ascertain that there is no pressure of hydrocarbons in the lines, vessels and equipment. Purge the system with N 2 first and later by air and check for O 2 content at vent and drain to ensure that the vessel is full of air. Check that steam injection lines and any inert line connections are disconnected or isolated from the equipment.
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Provide tags on the various blinds to avoid mistakes. Maintain a register for blinds. Check for pyrophoric iron and if existing, keep this wet with water. Keep the surrounding area cleaned up. Get explosive meter test done in vessels, lines, equipment and surrounding areas. If welding or hot work is to be done, also: Keep fire-fighting devices ready for use nearby. Close the neighbouring surface drains with wet gunny bags. Keep water flowing in the neighbouring area to cool down any spark bits etc. Keep stem lancers ready for use. After the above operations have been made, a safety permit should be issued for carrying out the work. A responsible operating supervisor should be personally present at the place of hot work till the first torch is lighted. Hot work should be immediately suspended if instructed by the supervisor or on detecting any unsafe condition. When people have to enter a vessel for inspection or other work, one person should stand outside near the manhole of the vessel for any help needed by the persons working inside. The person entering the vessel should have tied on his waist a rope to enable pulling him out in case of urgency. Detail procedure for preparation for vessel entry is given in next sub-section. 12.6
PREPARATION FOR VESSEL ENTRY
12.6.1 GENERAL PROCEDURE Whenever a Licenser technical advisor must enter a vessel a meeting should be arranged between Licenser and the plant personnel who will be involved. The meeting should include review of the Licenser vessel entry procedures, the refiner’s safety requirements and facilities, preparation of a vessel entry schedule, assignment of responsibility for the preparation of a blind list, and assignment of responsibility for the vessel entry permits.
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The most common tasks of a Licenser technical advisor that requires potentially hazardous vessel entry are: Unit Checkout Prior to Start-up Turnaround Inspections Vessel internals The precautions apply equally to entry into all forms of vessels, including enclosed areas, which might not normally be considered vessels. Positive Vessel Isolation Every line connecting to a nozzle on the vessel to be entered must be blinded at the vessel. This includes drains connecting to a closed sewer, utility connections and all process lines. The location of each blind should be marked on a master piping and instrumentation diagram (P&ID), each blind should be tagged with a number and a list of all blinds and their locations should be maintained. One person should be given responsibility for the all blinds in the unit to avoid errors. The area around the vessel man ways should also be surveyed for possible sources of dangerous gases that might enter the vessel while the person is inside. Examples include acetylene cylinders for welding and process vent or drain connections in the same or adjoining units.
Any hazards found in the
survey should be isolated or removed. Vessel Access Safe access must be provided both to the exterior and interior of the vessel to be entered. The exterior access should be a solid, permanent ladder and platform or scaffolding strong enough to support the people and equipment that will be involved in the work to be performed. Access to the interior should also the strong and solid.
Scaffolding is
preferred when the vessel is large enough to permit it to be sued. The scaffolding base should rest firmly on the bottom of the vessel and be solidly encored. If the scaffolding is tall, the scaffolding should be supported in several places to prevent sway. The platform boards should be sturdy and capable of supporting several people and equipment at the same time and also be firmly fastened down. Rungs should be provided on the scaffolding spaced at a comfortable distance for climbing on the structure. Template No. 5-0000-0001-T2 Rev A
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If scaffolding will not fit in the vessel a ladder can be used. A rigid ladder is always preferred over a rope ladder and is essential to avoid fatigue during lengthy periods of work inside a vessel. The bottom and top of the ladder should be solidly anchored. If additional support is available, then the ladder should also be anchored at intermediate locations. When possible, a solid support should pass through the ladder under a rung, thereby providing support for the entire weight should the bottom support fail. Only one person at a time should be allowed on the ladder. When a rope ladder is used, the ropes should be thoroughly inspected prior to each new job. All rungs should be tested for strength, whether they are made of metal or wood. Each rope must be individually secured to an immovable support. If possible, a solid support should pass through the ladder so that a rung can help support the weight and the bottom of the ladder should be fastened to a support to prevent the ladder from swinging. As with the rigid ladder, only one person should climb the ladder at a time. Wearing of a Safety Harness Any person entering a vessel should wear a safety harness with an attached safety line.
The harness should be strong and fastened in such a
manner that it can prevent a fall in the event the man slips and so that it can be used to extricate the man from the vessel in the event he encounters difficulty. A parachute type harness is preferred over a belt because it allows an unconscious person to be lifted from the shoulders, making it easier to remove him from a tight place such as an internal man way. A minimum of one harness for each person entering the vessel and at least one spare harness for the people watching the man way should be provided at the vessel entry. Providing a Man way Watch Before a person enters a vessel, there should be a minimum of two people available outside of the vessel, one of who should be specifically assigned responsibility to observe the activity of the people inside of the vessel. The other person must remain available in close proximity to the person watching the man way so that he can assist or go for help, if necessary. He must also be alert for events outside of the vessel, which might require the people inside to come out of
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the vessel, for example, a nearby leak or fire. These people should not leave their post until the people inside have safely evacuated the vessel. A communication system should be provided for the man way watch so that they can quickly call for help in the event that the personnel inside of the vessel encounter difficulty. A radio, telephone, or public address system is necessary for that purpose. Providing Fresh Air The vessel must be purged completely free of any noxious or poisonous gases and inventoried with fresh air before permitting anyone to enter. The responsible department, usually the safety department, must test the atmosphere within the vessel for toxic gases, oxygen and explosive gases before entry. This must be repeated every 4 hours while there are people inside the vessel. When possible the Licenser technical advisor should personally witness the test procedure. Each point of entry and any dead areas inside of the vessel, such as receiver boots or areas behind internal baffles, where there is little air circulation should be checked. Fresh air can be circulated through the vessel suing an air mover, a fan, or, for the cases where moisture is ca concern, the vessel can be purged using dry certified instrument air from a hose or hard piped connection. When an air mover is used, make certain that the gas driver uses plant air, not nitrogen, and direct the exhaust of the driver out of the vessel to guarantee that this gas does not enter the vessel. When instrument air is used, the Licenser technical adviser must confirm the checking of the supply header to ensure that it is properly lined up. It should be confirmed that there are no connections where nitrogen can enter the system (Sometimes nitrogen improperly used as a backup for instrument air by some refiners). The fresh air purge should be continued throughout the time that people are inside of the vessel. The responsible control room should be informed that instrument air is being used for breathing so that if a change to nitrogen is required the people are removed from the affected vessel. A minimum of one fresh air mask for each person entering the vessel and at least one spare mask for the Manway watcher should be provided at the vessel entry. These masks should completely cover the face, including the eyes, and have a second seal around the mouth and nose. When use of the mask is
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required, it must first be donned outside of the vessel where it is easy to render assistance in order to confirm that the air supply is safe. Each mask must have a backup air supply that is completely independent of the main supply. It must also be independent of electrical power. This supply is typically a small, certified cylinder fastened to the safety harness and connected to the main supply line via a special regulator that activates when the air pressure to the mask drops below normal. The auxiliary supply should have an alarm, which alerts the user that he is on backup supply and it should be sufficiently large to give the user 5 minutes to escape from danger. 12.6.2 PREPARATION OF VESSEL ENTRY PERMIT Before entering the vessel a vessel entry permit must be obtained. A vessel entry permit ensures that all responsible parties know that work is being conducted inside of a vessel and establishes a safe preparation procedure to follow in order to prevent mistakes, which could result in an accident. The permit is typically issued by the safety engineer or by the shift supervisor. The permit should be based on a safety checklist to be completed before it is issued. The permit should also require the signatures of the safety engineer, the shift supervisor, and the person that performed the oxygen toxic and explosive gas check on the vessel atmosphere. Four copies of the permit should be provided. One copy goes to the safety engineer, one to the shift supervisor, one to the control room, and one copy should be posted prominently on the man way through which the personnel will enter the vessel. The permit should be renewed before each shift and all copies of the permit should be returned to the safety engineer when the work is complete.
The refiner may impose additional
requirements or procedures, but the foregoing is considered the minimum acceptable for good safety practice. 12.6.3 CHECKOUT PRIOR TO NEW UNIT START-UP The risk of exposure to hydrocarbon, toxic or poisonous gases, and catalyst dust is low during a new unit checkout; the primary danger is nitrogen. There will be pressure testing, line flushing, hydro testing, and possibly chemical cleaning being conducted in the unit and nitrogen may be used during any of these activities. Some of the equipment may have been inventoried with nitrogen to
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An additional hazard is imposed by
operations in other parts of the plant, which may be beyond the control of the people entering the vessel. For these reasons vessel entry procedures must still be rigorously followed during the checkout of a new unit. The oxygen content of the atmosphere inside of the vessel should be checked before every entry and the vessel should be blinded.
Independent
blinds at each vessel nozzle are preferred. However, in the event that many vessels are to be entered in a new unit, which is separate from the rest of the plant, the entire unit can be isolated by installing blinds at the battery limits rather than by individually isolating every vessel nozzle. 12.6.4 INSPECTIONS DURING TURNAROUNDS In turnaround inspections, the possibility that vessels will contain dangerous gases is much higher. Equipment that has been in service must be thoroughly purged before entry. The vessel should have been steamed out unless steam presents a hazard o the internals and then fresh airs circulated through it until all traces of hydrocarbons are gone.
If liquid hydrocarbon remains or if odours
persist afterwards, repeat the purging procedure until the vessel is clean. The service history of the vessel must also be investigated before entry so that appropriate precautions may be taken. The service may require a neutralisation step or a special cleaning step to make the vessel safe. Internal scale can trap poisonous gases such as hydrogen sulfide or hydrogen fluoride that may be released when the scale is disturbed. If this sort of danger is present, fresh air masks and protective clothing may be required to worn while working inside of the equipment. In a turnaround inspection, every vessel nozzle must be blinded at the vessel with absolutely no exceptions. There will always be process material at the low and high points in the lines connecting to the vessel because it is not possible to purge them completely clean. The blinds must all be in place before the vessel is purged. Another factor to be cautious of, especially if entering a vessel immediately after the unit has been shut down, is heat stress. The internals of the vessels can still be very hot from the steam-out procedure or from operations prior to the shutdown. If that is the case, the period of time spent working inside of the Template No. 5-0000-0001-T2 Rev A
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vessel should be limited and frequent breaks should be taken outside of the vessel.
12.7
FIRE FIGHTING SYSTEM
The operating personnel should be fully conversant with Fire fighting system provided in the unit. All of them should have adequate fire fighting training and will serve as an auxiliary Fire Squad in the event of a fire breakout. It will be the primary responsibility of unit personnel to fight the fire at the very initial stage and, at the least, localise it. Major Fire fighting facilities provided in the unit comprising the following: a) Fire Water System Water is most important fire fighting medium. Water is used to extinguish the fire, control, equipment cooling & exposure protection of equipment/personnel from heat radiation. An elaborate firewater distribution network is provided around unit. Firewater Hydrants/Monitors are provided around unit, which give coverage to most of equipment. b) Foam System For containing large Hydrocarbon fires, foam systems are useful. They have inherent blanketing ability, heat resistance and security against burn back. Low expansion foam is used for hydrocarbon oil fire. Foam can be applied over burning oil pool with the help of foam tenders/foam delivery system. c) Portable Fire Extinguishers Fire should be killed at the incipient stage. Portable fire extinguishers are very useful in fighting small fires. All extinguishers in the unit must be located in specified places only. Template No. 5-0000-0001-T2 Rev A
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location of the extinguishers. They also must know most suitable type, which, when and how to use an extinguisher. For example, electrical fires should be put out with CO2 or dry power extinguishers; water and foam should not be used. The used extinguishers should be checked and restored by fire station personnel. d) Fire Signal Break Glasses have been provided at strategic locations of unit to see fire alarm in fire station. If a fire is sighted, glass of window should be smashed, causing fire alarm switch to actuate. This is an emergency call & should be periodically tested for proper functioning. e) Steam Smothering LP Steam hose connections have been provided at every convenient point inside unit. Steam lances of standard 15M length can be fitted with these hose stations. Wherever hydrocarbon leakage is detected which is likely to catch fire, Steam blanketing may be done. Apart from diluting combustible Hydrocarbons, steam prevents atmospheric oxygen from taking part in combustion & thus help in extinguishing fire. However, steam should never be applied on large pool of hydrocarbon fire. Direct application of steam on burning oil may result in spillage of burning hydrocarbon & spread of fire. Similarly use of firewater on hot oil surfaces may cause sputtering & spread of fire. 12.7.1 USE OF LIFE SAVING DEVICE Safety of the personnel should the prime concern. Life saving device is to be used for personnel protection. Important life saving devices which are required to be used are given below: Head protection:
Safety helmets shall be worn by all personnel at all times in the plant for protection of the head. They may be removed when inside rooms or buildings that do not have overhead or other hazards. Eye and face protection Safety glasses, goggles or face shields shall be worn while performing work, which could result in eye or face injury. Hand Protection Proper hand protective gloves should be worn.
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Foot protection Safety shoes are to be worn for foot protection. Ear protection Whenever persons are required to be work in noisy areas proper ear protection device such as earplug etc, is to be used. Breathing apparatus Whenever persons are required to work or enter an area of high toxic/aromatic/hydrocarbon vapour concentration, wear appropriate respiratory protection, such as self-contained breathing apparatus or an air mask with an external air supply.
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SECTION- 13 GENERAL OPERATING INSTRUCTIONS FOR EQUIPMENT
13.1
GENERAL
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This section covers the general procedure for operation and trouble shooting of commonly used equipment like pumps, heat exchangers and furnace etc. For specific information and more detail refer to vendor's manuals. 13.2
CENTRIFUGAL PUMPS
Start-up Inspect and see if all the mechanical jobs are completed. Establish cooling water flow where there is such provision. Also open steam for seal quenching in pumps having such facilities. Check oil level in the bearing housing, flushing may be necessary if oil is dirty or contains some foreign material. Rotate the shaft by hand to ensure that it is free and coupling is secure. Coupling guard should be in position and secured properly. Open suction valve. Ensure that the casing is full of liquid. Bleed, if necessary, from the bleeder valve. Energise the motor. Start the pump and check the direction of rotation. Rectify the direction of rotation if it is not right. Check the discharge pressure. Bleed if necessary to avoid vapour locking. Open the discharge valve slowly. Keep watch on the current drawn by the motor, if ammeter is provided. In other cases check at motor control centre. In some pumps a by-pass has been provided across the check valve and discharge valve to keep the idle pump hot. In such pumps, the by-pass valve should be closed before starting the pump. It should be ensured that casing of these pumps are heated up sufficiently prior to starting of the pump to guard against damage of the equipment and associated piping due to thermal shock. Shutdown Close discharge valve fully. Stop the pump a) If pump is going to remain as standby and has provision for keeping the pump hot, proceed as follows:
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Open the valve in the by-pass line across the discharge valve and check valve. The circulation rate should not be so high to cause reverse rotation of idle pump and also overloading of the running pump. b) If pump is to be prepared for maintenance, proceed as follows: Close suction and discharge valves. Close valve on check valve by-pass line, if provided. Close cooling water to bearing, if provided.
Also shut off steam for seal
quenching, if provided. Slowly open pump bleeder and drain liquid from pump if the liquid is very hot allow sufficient time before draining is started.
Ensure that there is no
pressure in the pump. Also drain pump casing. Blind suction and discharge and check valve by-pass line and flare connection if any. Cut-off electrical supply to pump motor prior to handling over for maintenance. Trouble Shooting a) Pump not developing pressure Bleed to expel vapour/air Check the lining up in the suction side. Check the suction strainer. Check the liquid level from where the pump is taking the suction the suction. Check pump coupling and rotation. Get the pump checked by a technician. b) Unusual Noise Check the coupling guard if it is touching. Check for proper fixing of fan and fan cover. Check for pump cavitations. Get the pump checked by a technician. c) Rise of Bearing Temperature
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Generally the bearing oil temperature up-to 80 0C or 500C above ambient whichever is lower, can be tolerated. Arrange lubrication if bearing is running dry or oil level is low. Adjust cooling water to the bearing housing, if there is such provision. Stop the pump, if temperature is too high, call the pump technician. d) Hot Gland Adjust cooling water if facility exists. Slightly loosen the gland nut, if possible. Stop the pump and hand over to maintenance. Arrange external cooling if pump has to be run for sometime. e) Unusual Vibration Check the foundation bolts. Check the fan cover for looseness. Stop the pump and hand over to maintenance. f) Leaky Gland Check the pump discharge pressure. Tighten the gland nut slowly, if possible. Prepare the pump for gland packing or adjustment/replacement of mechanical seal as the case may be. g) Mechanical Seal Leak Stop and isolate the pump and hand over to maintenance.
13.3
HEAT EXCHANGERS
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13.3.1 GENERAL The unit has a number of heat exchangers, air coolers. Suitable valves for bypassing and isolation were provided wherever necessary to offer the required operational flexibility. The exchangers have been provided with draining and flushing connections. The coolers and condensers have been provided with TSV's on the cooling waterside to guard against possible rise of pressure due to faulty operations with the safety release to atmosphere. Temperature gauges or Thermowells have been provided at the inlet and outlet of exchangers. Where water is the cooling medium, no temperature measurement is provided for water inlet temperature, which is the same as cooling water supply header temperature. 13.3.2 AIR COOLERS Air coolers/condensers comprise of a fin tube assembly running parallel between the inlet and outlet headers. These are of the forced draft type. The forced draft fans provided have auto variable speed rotors in which the fan speeds are adjusted during rotation. This allows variation in airflow as per the cooling requirements. A high vibration switch is provided with alarm to indicate any mechanical damage. 13.3.3 EXCHANGERS Shell and Tube type heat exchangers can be broadly classified into following types:
Water Coolers/condensers
Steam heaters (Reboiler)
Exchangers
Start-up/shut down procedures for each unit shall vary slightly from case to case. However, general start-up/shut-down procedures are discussed in the following paragraphs. START-UP After the heat exchanger has been pressure tested and all blinds removed, proceed as follows:
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Open cooling medium vent valve to displace non-condensable (air, fuel gas, inert gas etc.) from the system. Ensure the drain valves are capped. For highpressure system, drain valves should be flanged. This activity is not required if gas is the medium. Open cooling medium inlet valve. Close vent valve when liquid starts coming out through it, then open cold medium outlet valve and fully open the inlet valve also. Where cold medium is also hot, warming up of cold medium side gradually is also essential. Open hot medium side vent valve to displace non-condensable (air, fuel inert gas etc.). Check that the drain is closed and capped. This activity is not required if gas is the medium. Crack open hot medium inlet valve. When liquid starts coming out from the vent valve, close it. Open hot medium inlet valve and then open the outlet valve fully. In case of steam heaters, initially the condensate shall be drained to sewer till pressure in the system builds up to a level where it can be lined up to the return condensate header. In case by passes are provided across shells and tube side, gradually close the bypass on the cold medium side and then the bypass across the hot medium side. Check for normal inlet and outlet temperatures. Check that TSVs are not popping. The operation of inlet and outlet valves should be done carefully ensuring that the exchangers are not subjected to thermal shock. In case of coolers/condensers, adjust the water flow to maintain the required temperature at the outlet.
For avoiding fouling, velocity of water should be at least 1 m/sec in a cooler/condenser.
Shutdown Shut down of an exchanger, coolers, condenser is considered when the equipment is to be isolated for handling over to maintenance while the main plant is in
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operation. The following is the suggested procedure for isolation of the piece of equipment
Isolate the hot medium first. In case both hot and cold medium are from process streams, exchanger shall remain in service till the hot stream has cooled down enough.
In case of a cooler, adjust cooling water flow to the cooler, which is in line so that product temperature is within allowable unit.
Isolate the cold medium next.
Drain out the shell and tube sides to OWS/Sewer/Closed blow down system as applicable. In case flushing oil connection is given flush the exchanger to CBD. Ensure that the CBD drum has sufficient usage to receive the flushing of the exchanger
Depressurise the system to atmosphere/flare/blow down system as applicable.
Purge/flush if required. This is particularly important in congealing services.
Blind inlet and outlet lines before handing over the equipment for maintenance.
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