OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
Doc No. Draft
Rev. A
Page 1 of 195
OPERATING MANUAL
FOR
FCC NAPHTHA HYDROTREATING UNIT
VISAKH REFINERY CLEAN FUEL PROJECT
HINDUSTAN PETROLEUM CORPORATION LIMITED
VISAKH
A
Rev No.
Issued for comments
Date
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Purpose
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Checked by
Approved by
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VRCFP, HPCL VISAKH
Doc No. Draft
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PREFACE
This operating manual for FCC Naphtha HydroTreater Unit (Unit No.-75) of
Visakh Refinery Clean Fuel Project for HPCL Visakh Refinery has been prepared
by M/s Engineers India Limited for M/s Hindustan Petroleum Corporation Limited.
The objective of FCC Naphtha Hydrotreating Unit is to process FCC
Gasoline to obtain product streams (Light gasoline and Heavy Hydrotreated
gasoline) with targeted qualities of octane number, sulphur content, benzene
content and olefins content. This manual contains process description and
operating guidelines for the unit and is based on documents supplied by the
Process Licensor (Axens). Hence the manual must be reviewed /approved
by the licensor before the start-up /operation of the unit. Operating
procedures & conditions given in this manual are indicative. These should be
treated as general guide only for routine start-up and operation of the unit. The
actual
operating
parameters
and
procedures
may
require
minor
modifications/changes from those contained in this manual as more experience is
gained in operation of the Plant.
For detailed specifications and operating procedures of specific equipment,
corresponding Vendor's operating manuals/instructions need to be referred in
addition to Process Package and Design Basis.
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TABLE OF CONTENTS
SECTION- 1
INTRODUCTION .................................................................................................................................. 9
1.1
INTRODUCTION ....................................................................................................................................................... 10
1.2
UNIT CAPACITY ...................................................................................................................................................... 10
1.3
ON-STREAM FACTOR .............................................................................................................................................. 10
1.4
TURNDOWN RATIO ................................................................................................................................................. 10
1.5
FEED CHARACTERISTICS......................................................................................................................................... 10
1.5.1
FCC Gasoline .............................................................................................................................................. 10
1.5.2
Sulfur Distribution (ppm wt)* ..................................................................................................................... 11
1.5.3
Hydrogen...................................................................................................................................................... 12
1.5.4
Lean Amine .................................................................................................................................................. 13
1.5.5
Start-up inert naphtha.................................................................................................................................. 13
1.6
PRODUCTS SPECIFICATION ..................................................................................................................................... 14
1.6.1
Light FCC gasoline: .................................................................................................................................... 14
1.6.2
Heavy desulfurized FCC gasoline ............................................................................................................... 15
1.6.3
Benzene Heartcut ......................................................................................................................................... 15
1.6.4
Splitter purge gas ......................................................................................................................................... 17
1.6.5
Selective HDS purge .................................................................................................................................... 17
1.6.6
Rich Amine ................................................................................................................................................... 17
1.6.7
Stabilizer purge ............................................................................................................................................ 18
1.7
PROPOSED TREATMENT SCHEME ................................................................................................................ 18
1.8
BATTERY LIMIT CONDITIONS OF PROCESS LINES ................................................................................................... 19
1.9
MATERIAL BALANCES ............................................................................................................................................ 20
1.9.1
SHU section overall balance ....................................................................................................................... 20
1.9.2
HDS section overall balance ....................................................................................................................... 20
1.10
SPECIFICATIONS OF CATALYSTS AND CHEMICALS ............................................................................................ 21
1.10.1
Catalyst ................................................................................................................................................... 21
1.10.2
Catalyst Bed Protections ........................................................................................................................ 22
1.10.3
Inert balls ................................................................................................................................................ 23
1.10.4
Chemicals ................................................................................................................................................ 24
1.11
UTILITY CONDITION AT UNIT BATTERY LIMIT ................................................................................... 25
1.12
UTILITY SPECIFICATION: ........................................................................................................................... 27
1.13
INTERMITTENT UTILITY CONSUMPTION ............................................................................................................. 28
1.13.1
Start-up requirement ............................................................................................................................... 28
1.13.2
Catalyst in-situ regeneration .................................................................................................................. 30
1.14
EFFLUENT SUMMARY: ....................................................................................................................................... 31
SECTION- 2
2.1
PROCESS DESCRIPTION ................................................................................................................. 33
UNIT DESCRIPTION ................................................................................................................................................. 34
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2.2
SELECTIVE HYDROGENATION ................................................................................................................................ 34
2.3
SPLITTER SECTION .................................................................................................................................................. 35
2.4
HDS SECTION ......................................................................................................................................................... 36
2.5
RECYCLE COMPRESSOR SECTION ........................................................................................................................... 37
2.6
STABILIZER SECTION .......................................................................................................................................... 37
2.7
CATALYST IN-SITU REGENERATION OPERATION .................................................................................................... 38
SECTION- 3
PROCESS PRINCIPLE ....................................................................................................................... 40
3.1
PURPOSE OF THE PROCESS ..................................................................................................................................... 41
3.2
GENERAL ................................................................................................................................................................ 41
3.3
SELECTIVE HYDROGENATION REACTOR (75-R-01)................................................................................................ 41
3.4
SPLITTER (75-C-01) ............................................................................................................................................... 42
3.5
FIRST HDS REACTOR (75-R-02) ............................................................................................................................ 43
3.6
CHEMICAL REACTIONS AND CATALYST ................................................................................................................ 43
3.6.1
Objective ...................................................................................................................................................... 43
3.6.2
Thermodynamics and kinetics ..................................................................................................................... 44
3.6.3
Catalyst activity, selectivity AND stability .................................................................................................. 44
3.6.4
Selective hydrogenation Reactions and Catalyst ........................................................................................ 45
3.6.5
Chemical reactions ...................................................................................................................................... 45
3.6.6
Hydrogenation of diolefins .......................................................................................................................... 45
3.6.7
Isomerization of olefins ............................................................................................................................... 47
3.6.8
Hydrogenation of olefins ............................................................................................................................. 47
3.6.9
Thermal and catalytic polymerization of unstable compounds .................................................................. 47
3.6.10
Thermodynamic and kinetic analysis ..................................................................................................... 47
3.6.11
Sulfur reaction ........................................................................................................................................ 48
3.7
PROCESS VARIABLES IN SELECTIVE HYDROGENATION .............................................................................. 49
3.7.1
Reactor Temperature ................................................................................................................................... 49
3.7.2
Residence time in the reactor ...................................................................................................................... 50
3.7.3
Reactor pressure .......................................................................................................................................... 51
3.7.4
Hydrogen make-up rate ............................................................................................................................... 51
3.8
CHEMICAL: HDS REACTOR REACTIONS AND CATALYST ...................................................................................... 51
3.8.1
Chemical reactions ...................................................................................................................................... 51
3.8.2
Hydrorefining............................................................................................................................................... 52
3.8.3
Hydrogenation of olefins ............................................................................................................................. 53
3.9
RELATIVE RATES OF REACTION .............................................................................................................................. 54
3.9.1
Process variables in hds reactor ................................................................................................................. 54
3.9.2
Temperature ................................................................................................................................................. 54
3.9.3
Operating pressure and H2/HC ratio ......................................................................................................... 55
3.9.4
Space velocity .............................................................................................................................................. 56
SECTION- 4
UTILITY DESCRIPTION................................................................................................................... 57
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INTRODUCTION ................................................................................................................................................. 58
4.1.1
INSTRUMENT AIR SYSTEM ...................................................................................................................... 58
4.1.2
PLANT AIR SYSTEM ................................................................................................................................... 58
4.1.3
SEA COOLING WATER SYSTEM .............................................................................................................. 58
4.1.4
BEARING COOLING WATER SYSTEM ................................................................................................... 59
4.1.5
SERVIC WATER SYSTEM ........................................................................................................................... 60
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
4.2
FUEL GAS SYSTEM ............................................................................................................................... 61
EFFLUENT SYSTEM .......................................................................................................................................... 61
SECTION- 5
PREPARATION FOR START-UP .................................................................................................... 64
5.1
GENERAL............................................................................................................................................................. 65
5.2
PRE-COMMISSIONING ACTIVITIES .............................................................................................................. 65
5.2.1
Inspection / Checking .................................................................................................................................. 65
5.2.2
Inspection of equipments ............................................................................................................................. 66
5.2.3
Piping and Accessories ................................................................................................................................ 66
5.2.4
Instruments ................................................................................................................................................... 66
5.2.5
Relief Valves................................................................................................................................................. 67
5.2.6
Rotary Equipment ........................................................................................................................................ 67
5.2.7
Drainage System .......................................................................................................................................... 67
5.3
PREPARATION FOR PRE-COMMISSIONING .............................................................................................................. 67
5.4
PRE-COMMISSIONING ............................................................................................................................................. 68
5.4.1
Commissioning of Utilities .......................................................................................................................... 68
5.4.2
Final Inspection of Vessels .......................................................................................................................... 70
5.4.3
Pressure Test Equipment ............................................................................................................................. 71
5.4.4
Wash Out Lines and Equipment .................................................................................................................. 72
5.4.5
Functional Test of Rotating Equipment ...................................................................................................... 74
5.5
INSTRUMENTS CHECKING ....................................................................................................................................... 77
5.6
SAFETY DEVICES CHECK ........................................................................................................................................ 78
5.7
HEATER REFRACTORY DRY-OUT AND REACTION SECTION DRY-OUT .................................................................... 79
5.8
PURGING AND GAS BLANKETING ........................................................................................................................... 79
5.9
TIGHTNESS TEST .................................................................................................................................................... 80
5.10
CATALYST LOADING PROCEDURE ...................................................................................................................... 83
5.11
CATALYST SPECIAL PROCEDURE ........................................................................................................................ 83
SECTION- 6
START-UP PROCEDURE .................................................................................................................. 84
6.1
INTRODUCTION ................................................................................................................................................. 85
6.2
PRE-START-UP CHECKLIST FOR PRIME G+ UNIT ................................................................................................ 85
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FIRST START-UP ...................................................................................................................................................... 87
6.3.1
Chronology of start-up operations .............................................................................................................. 87
6.3.2
Purging of air............................................................................................................................................... 87
6.4
START-UP PRELIMINARY OPERATION ..................................................................................................................... 91
6.4.1
Unit status .................................................................................................................................................... 91
6.4.2
Inert naphtha circulation (Reaction sections by-passed) ........................................................................... 91
6.4.3
Start-up of Hot Naphtha circulation in splitter and stabilizer ................................................................... 94
6.5
PRESSURIZATION OF THE REACTION SECTIONS AND HYDROGEN LEAK TESTS ....................................................... 96
6.5.1
Unit status .................................................................................................................................................... 96
6.5.2
H2 inroduction in SHU section ................................................................................................................... 97
6.5.3
H2 inroduction in HDS section ................................................................................................................... 97
6.6
CATALYST SULFIDING – DRY SULPHIDING ............................................................................................................ 97
6.6.1
Sulfiding of HR-845 Catalyst in the Diolefin Reactor (75-R-01) ............................................................... 98
6.6.2
Sulfiding of HR-806 Catalyst of first HDS Reactor (75-R-02) ................................................................... 98
6.6.3
Sulphiding Procedure .................................................................................................................................. 99
6.7
UNIT START-UP.................................................................................................................................................... 101
6.7.1
UNIT Status................................................................................................................................................ 101
6.7.2
Lining up of the SHU reaction section ...................................................................................................... 102
6.7.3
Lining up of the HDS reaction section ...................................................................................................... 103
6.7.4
Inert naphtha circulation ........................................................................................................................... 104
6.7.5
FCC Gasoline Feed ................................................................................................................................... 104
SECTION- 7
NORMAL OPERATING PROCEDURE ........................................................................................ 107
7.1
GUIDELINES FOR NORMAL OPERATION .................................................................................................. 108
7.2
INTRODUCTION ............................................................................................................................................... 108
7.3
OPERATING PARAMETER ............................................................................................................................. 108
7.4
ALARMS:............................................................................................................................................................ 115
7.5
OPEARATING CONDITIONS OF DIFFERENT CASES OF OPERATION .................................................. 120
7.6
EQUIPMENT LIST ............................................................................................................................................. 120
7.6.1
Pumps ......................................................................................................................................................... 120
7.6.2
Vessels ........................................................................................................................................................ 121
7.6.3
Columns ..................................................................................................................................................... 122
7.6.4
Reactors ..................................................................................................................................................... 122
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 ......................................................................................................................................... 126
7.7.3
Safety valves ............................................................................................................................................... 127
7.8
RELIEVE VALVE LOAD SUMMARY ............................................................................................................ 128
7.9
DETAIL OF INTERLOCK LOGIC AND TRIPS .............................................................................................. 129
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EFFECT OF OPERATING VARIABLES ON THE PROCESS ...................................................................................... 133
7.10.1
Operating parameters ........................................................................................................................... 133
7.10.2
Reactor temperature ............................................................................................................................. 133
7.10.3
other parameter .................................................................................................................................... 135
7.10.4
Make-up H2 and recycle H2 flow-rates................................................................................................. 136
7.10.5
Space velocity (feed rate)...................................................................................................................... 138
7.10.6
Feed quality........................................................................................................................................... 139
SECTION- 8
8.1
SHUTDOWN PROCEDURES .......................................................................................................... 141
NORMAL SHUTDOWN PROCEDURE ........................................................................................................... 142
8.1.1
introduction ................................................................................................................................................ 142
8.1.2
Preparations for a Planned Shutdown ...................................................................................................... 142
8.1.3
General procedure ..................................................................................................................................... 143
8.1.4
Short period shutdown ............................................................................................................................... 143
8.1.5
Long period shutdown ............................................................................................................................... 145
8.1.6
Shutdown followed by maintenance, inspection or catalyst unloading.................................................... 146
8.2
UNIT RESTART ...................................................................................................................................................... 148
SECTION- 9
9.1
EMERGENCY SHUTDOWN PROCEDURE ................................................................................ 150
EMERGENCY SHUTDOWN PROCEDURE ................................................................................................... 151
9.1.1
general ....................................................................................................................................................... 151
9.1.2
Emergency shutdown by operators ........................................................................................................... 151
9.1.3
Loss of feed ................................................................................................................................................ 153
9.1.4
Loss of cooling water ................................................................................................................................. 155
9.1.5
Lack of hydrogen make-up ........................................................................................................................ 155
9.1.6
Loss of Amine ............................................................................................................................................. 155
9.1.7
Quench pump failure ................................................................................................................................. 155
9.1.8
Fuel gas failure .......................................................................................................................................... 156
9.1.9
Steam failure .............................................................................................................................................. 156
9.1.10
Instrument air failure ............................................................................................................................ 156
9.1.11
Power failure......................................................................................................................................... 156
9.1.12
Fire or major leak ................................................................................................................................. 157
9.1.13
Automatic emergency shutdown ........................................................................................................... 158
SECTION- 10
10.1
TROUBLE SHOOTING .................................................................................................................... 160
TROUBLE SHOOTING ................................................................................................................................ 161
10.1.1
High differential pressure (∆P) in the reactor ..................................................................................... 161
10.1.2
Chemical H2 consumption increase ..................................................................................................... 161
10.1.3
Octane losses......................................................................................................................................... 162
SECTION- 11
SAMPLING PROCEDURE AND LABORATORY ANALYSIS ................................................. 163
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11.1
GENERAL ...................................................................................................................................................... 164
11.2
SAMPLING PROCEDURE ........................................................................................................................... 164
SECTION- 12
SAFETY PROCEDURE .................................................................................................................... 170
12.1
INTRODUCTION .......................................................................................................................................... 171
12.2
PLANT SAFETY FEATURES ............................................................................................................................... 171
12.2.1
General .................................................................................................................................................. 171
12.2.2
Emergency shutdown ............................................................................................................................ 171
12.2.3
Overpressure protection ....................................................................................................................... 171
12.2.4
Safety shower and eye wash ................................................................................................................. 172
12.2.5
Operational safety stations ................................................................................................................... 172
12.2.6
High pressure ........................................................................................................................................ 172
12.2.7
Reactor protection ................................................................................................................................ 172
12.2.8
Personnel protection ............................................................................................................................. 172
12.3
SAFETY OF PERSONNEL ........................................................................................................................... 175
12.4
WORK PERMIT PROCEDURE.................................................................................................................... 176
12.5
PREPARATION OF EQUIPMENT FOR MAINTENANCE ....................................................................... 178
12.6
PREPARATION FOR VESSEL ENTRY ...................................................................................................... 180
12.6.1
General procedure ................................................................................................................................ 180
12.6.2
Preparation of Vessel Entry Permit ..................................................................................................... 184
12.6.3
Checkout Prior to New Unit Start-up ................................................................................................... 184
12.6.4
Inspections during Turnarounds .......................................................................................................... 185
12.7
FIRE FIGHTING SYSTEM ........................................................................................................................... 186
12.7.1
SECTION- 13
Use of life saving device ....................................................................................................................... 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
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SECTION- 1 INTRODUCTION
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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:
AM
BH
NIT
CASE
CASE
CASE
111 666
111 666
111 666
152.3
156.0
152.8
Density at 15°C, g/cc
0.7334
0.716
0.731
Total Sulfur, wppm / RSH
2400/720
180/90
1133/229
Characteristics
Max Available Rate,
t/hr
St m3/hr
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AM
BH
NIT
CASE
CASE
CASE
RON
93
93
91.4
MON
80.6
81.6
81.2
Paraffins, vol %
29.5
29.2
24.35
Olefins, vol %
35.5
38.5
54.47
(Diolefins wt %)
(2.0)
(2.0)
(2.0)
Naphthenes, vol %
10.7
10.3
7.01
Aromatics, vol %
24.3
22.0
14.17
(Benzene, vol%)
(1.8)
(1.9)
(0.38)
46.1
46.1
40
10 % vol
56.1
56.1
57.6
30 % vol
75.5
75.5
70.6
50 % vol
95.5
95.5
92
70 % vol
124.4
124.4
123.2
90 % vol
155
155
156.4
95 % vol
167.7
167.7
168.2
180
180
187
Characteristics
PONA (vol %)
Distillation (ASTM-D86), °C
IBP
FBP
1.5.2
SULFUR DISTRIBUTION (PPM WT)*
AM case
BH case
NIT case
(ppm wt)
(ppm wt)
(ppm wt)
Methyl mercaptan
0.5
0.5
0.5
Ethyl mercaptan
200
25
118
C3 mercaptan
138
17
81
C4 mercaptan
22
3
13
C5 mercaptan
263
33
12
C6+ mercaptan
97
12
5
Carbonyle disulfide
0.5
0.1
0.5
Dimethyl sulfide
2
0.2
1
Sulphur components
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AM case
BH case
NIT case
(ppm wt)
(ppm wt)
(ppm wt)
Methyl ethyl sulfide
2.0
0.2
1.0
Methyl-t-butyl sulfide
5
0.5
3
Thiophene
236
12
100
C1 thiophene
360
24
200
Tetra hydro thiophene
51
5
20.0
C2 thiophene
262
12
128
and 773
37
451
180
1133
Sulphur components
C3+
thiophene
benzothiophenes
Total
2400
(*) Assumed from Axens data bank
1.5.3
HYDROGEN
Components / Origin
Hydrogen from CCR
H2, mol%
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:
Normal
Impurities: H2S
5ppm vol max
Start-up H2
99.9
balance
100
Start-up
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
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LEAN AMINE
Properties / Case
All cases
Type
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
<5
Bromine Number, gBr/100g
< 0.5
Diene Value
between 0.725 and 0.850
Specific Gravity
between 5 and 70
D86 5%vol, °C
between 145 and 225
D86 95%vol, °C
¾ ASTM as close as possible to the cracked feed.
¾ Typically, straight run naphtha coming from the crude distillation unit is used.
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PRODUCTS SPECIFICATION
LIGHT FCC GASOLINE:
NIT
AM
BH
CASE
CASE
CASE
49027
32000
32000
73.8
49.0
49.5
Density at 15°C, g/cc
664
654
647
MW, kg/kmol
74.3
74.1
73.9
Sulfur, wppm
240
270
15
RON (estimated)
94.6
94
94
MON (estimated)
81.8
81.1
82
RVP (kpa)
100
120
122
Paraffins, vol %
34.4
52.2
50.7
Olefins, vol %
61.2
43.2
45.5
(Diene Value)
(0.0)
(0.0)
(0.0)
Naphthenes, vol %
2.9
2.4
1.6
Aromatics, vol %
0.8
2.13
2.1
(Benzene, vol%)
(0.76)
(2.13)
(2.1)
simulated
simulated
24.5
19.0
18.8
5 % vol
39.1
33.4
33.2
10 % vol
41.2
34.6
34.4
30 % vol
45.9
37.0
36.8
50 % vol
55.3
40.4
40.1
70 % vol
61.7
46.7
44.8
90 % vol
73.3
64.4
63.8
95 % vol
77.8
69.4
68.4
84.1
77.1
75.5
Characteristics
Max Available Rate,
t/hr
ST m3/hr
PONA (vol %)
Distillation(ASTM
IBP
FBP
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HEAVY DESULFURIZED FCC GASOLINE
NIT
AM
BH
CASE
CASE
CASE
62468
63188
64350
78./8
79.6
83.8
Density at 15°C, g/cc
793.2
793.5
767.9
MW, kg/kmol
115
114.5
116.4
Sulfur, wppm
10
200
290
RON (estimated)
75.3
88.1
92.8
MON (estimated)
74.3
78.4
81.7
RVP (kpa)
6
6
6
Paraffins, vol %
62.6
25.0
16.5
Olefins, vol %
1.0
15.3
28.7
(Diene Value)
(0.0)
(0.0)
(0.0)
Naphthenes, vol %
9.9
16.3
16.6
Aromatics, vol %
26.5
43.4
38.2
(0.43)
(0.47)
Characteristics
Max Available Rate,
t/hr
St m3/hr
PONA (vol %)
(Benzene, vol%)
Distillation(ASTM D86),°C
simulated
simulated
simulated
IBP
106.0
75.2
104.7
5 % vol
112.0
111.8
110.8
10 % vol
114.9
115.0
113.6
30 % vol
125.6
125.7
124.2
50 % vol
137.2
137.3
136.2
70 % vol
149.8
149.5
148.8
90 % vol
170.7
167.2
166.9
95 % vol
178.6
173.6
173.4
182.9
178.2
178.0
FBP
1.6.3
BENZENE HEARTCUT
In order to meet the 0.9% vol benzene content in the gasoline pool in case of any
benzene upset in the feed (up to 1.9 vol %). This heart-cut is not used during normal
operation. The heart-cut properties are presented in the table hereafter.
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NIT
AM
BH
CASE
CASE
CASE
t/hr
NA
16000
15000
St m3/hr
NA
23.1
22.4
Density at 15°C, g/cc
NA
691.6
671.0
MW, kg/kmol
NA
85.4
85.4
Sulfur, wppm
NA
1116
64
Paraffins, vol %
NA
36.5
33.0
Olefins, vol %
NA
46.5
51.7
(0.0)
(0.0)
Characteristics
Max Available Rate,
PONA (vol %)
(Diene Value)
Naphthenes, vol %
NA
10.9
8.4
Aromatics, vol %
NA
6.2
6.93
(Benzene, vol%)
(5.8)
(6.85)
Distillation(ASTM D86),°C
simulated
simulated
NA
45.7
45.2
5 % vol
NA
51.8
51.6
10 % vol
NA
54.3
54.3
30 % vol
NA
NA
72.3
71.6
77.3
76.2
NA
NA
NA
81.5
80.0
88.2
85.4
91.9
88.7
99.1
94.6
IBP
50 % vol
70 % vol
90 % vol
95 % vol
FBP
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1.6.4
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Page 17 of 195
SPLITTER PURGE GAS
The splitter purge has the following estimated properties. Refer to stream 16 in material
balances for detailed composition, and other physical properties
1.6.5
Case
NIT CASE
AM CASE
BH CASE
Splitter Purge
SOR
EOR
SOR
EOR
SOR
EOR
Rate, kg/h
648
1039
537
866
562
905
H2, %mol
46.3
53.5
47.4
54.4
46.4
53.5
C1 to C4, %mol
35.3
27.1
36.9
28.7
38.4
30.3
C5+, %mol
18.4
19.4
15.7
16.9
15.2
16.2
SELECTIVE HDS PURGE
The selective HDS purge has the following estimated properties. Refer to stream 37 in
material balances for detailed composition, and other physical properties. In normal
operation, this purge is closed.
1.6.6
Case
NIT CASE
AMCASE
BH CASE
HP Purge
SOR
EOR
SOR
EOR
SOR
EOR
Rate, kg/h
216
216
56
56
NA
NA
H2, %mol
88.4
88.4
91.1
91.1
NA
NA
H2S, ppm mol
6510
6510
32
32
NA
NA
C1 to C4, %mol
10.6
10.6
7.7
7.7
NA
NA
C5+, %mol
0.35
0.35
1.2
1.2
NA
NA
RICH AMINE
The rich amine has the following estimated properties. Refer to stream 44 in material
balances for detailed composition, and other physical properties.
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Case
NIT CASE
AM CASE
Rich amine
SOR
EOR
SOR
EOR
SOR
EOR
Rate, kg/h
NA
NA
10124
10124
NA
NA
DEA, % mol
NA
NA
5.38
5.38
NA
NA
Loading,
NA
NA
0.25
0.25
NA
NA
mol H2S
BH CASE
/ mol
DEA
1.6.7
STABILIZER PURGE
The Stabilizer purge has the following estimated properties. Refer to stream 51 in
material balances for detailed composition, and other physical properties.
1.7
Case
NIT CASE
AM CASE
BH CASE
Stabilizer Purge
SOR
EOR
SOR
EOR
SOR
EOR
Rate, kg/h
855
854
428
428
NA
NA
H2, % mol
23.3
23.2
30.4
30.4
NA
NA
H2S, % mol
11.2
11.2
12.4
12.4
NA
NA
C1 to C4, % mol
60.4
60.4
51.3
51.3
NA
NA
C5+, % mol
5.1
5.2
5.9
5.9
NA
NA
PROPOSED TREATMENT SCHEME
The processing block comprise following system:
The Selective Hydrogenation facilities on the FCC gasoline consist:
¾ A FCC gasoline splitter to produce a partially de-sulfurized Light FCC gasoline
and a Heavy FCC gasoline.
¾ The PRIME G+ Selective Hydrodesulphurization of Heavy FCC gasoline.
¾ The desired product streams from the block are a light partially desulfurized
FCC cut and a heavy desulfurized gasoline stream, which should be of the
required quality to meet the pool specifications.
The basic design utilizes Axens’ Prime G+ technology. Prime G+ is a process for
hydrodesulfurization of cracked gasoline, which includes the following major unit
sections:
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¾ Selective Hydrogenation and Splitter Section
¾ Selective HDS and Stabilizer Section
The unit 75 produces:
¾ A partially desulfurized and sweet light FCC cut, routed to the MS pool
¾ A desulfurized heavy FCC cut, routed to the MS pool
1.8
BATTERY LIMIT CONDITIONS OF PROCESS LINES
Streams
Pressure
Temperature
kg/cm²g
°C
6.0
70
6.0
40
20.4
40
Normal operation
39.0 (*)
40
From CCR
22.0 (**)
40
Start-up
20.0
45
7.0
40
7.0
40
Desulfurized heavy FCC gasoline 7.0
40
Feeds: FCC gasoline
FCC gasoline from storage
Lean amine
H2 Make-up
Product(s): Light FCC gasoline
FCC heart cut
Rich amine
2.4
47
4.5
40
NIT Case
5.5
40
AM Case
4.5
40
5.0
40
Gas purges
Splitter purge
Selective HDS HP purge
Stabiliser purge
(*) At Isomerization H2 make-up compressor discharge on unit 73.
(**) When isomerization compressor is shut down
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1.9
1.9.1
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MATERIAL BALANCES
SHU SECTION OVERALL BALANCE
Case
AM CASE
BH CASE
MIX CASE
SOR
EOR
SOR
EOR
SOR
EOR
FCC gasoline
111 666
111 666
111 666
111 666
111 666
111 666
H2 make-up
277
323
244
284
245
286
TOTAL
111 943
111 989
111 910
111 950
111 911
111 952
Splitter purge
648
1039
537
866
562
905
Light gasoline
49 027
49 027
32 000
32 000
32 000
32 000
Heart cut gasoline NA
NA
16 000
16 000
15 000
15 000
Heavy gasoline
62 268
61 923
63 373
63 084
64 350
64 047
TOTAL
111 943
111 989
111 910
111 950
111 912
111 952
Feeds kg/hr
Products kg/hr
1.9.2
HDS SECTION OVERALL BALANCE
Case
AM CASE
BH CASE
MIX CASE
SOR
EOR
SOR
EOR
SOR
EOR
Heavy gasoline
62 268
61 923
63 373
63 084
NA
NA
H2 make-up
1271
1270
470
469
NA
NA
Lean Amine
-
-
10 000
10 000
NA
NA
TOTAL
63 539
63 193
73 843
73 553
NA
NA
Separator purge
216
216
56
56
NA
NA
Stabilizer off-gas
855
854
428
428
NA
NA
62 123
63 189
62 899
NA
NA
Feeds kg/hr
Products kg/hr
Heavy
hydroteated 62 468
gasoline
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Case
AM CASE
SOR
BH CASE
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MIX CASE
EOR
SOR
EOR
SOR
EOR
sour -
-
35
35
NA
NA
Stabilizer reflux drum -
-
11
11
NA
NA
Separator drum
water
sour water
Rich amine
-
-
10 124
10 124
NA
NA
TOTAL
63 539
63 193
73 843
73 553
NA
NA
1.10
SPECIFICATIONS OF CATALYSTS AND CHEMICALS
1.10.1 CATALYST
HR 845
Relevant to
Selective Hydrogenation Reactor, 75-R-01
Trade mark
HR
845,
manufactured
by
:
Axens Procatalyse Catalysts & Adsorbents
Presentation
Spheres, diameter 3mm (2 to 4mm)
Estimated cycle length
Refer (1)
Estimated life time
Refer (1)
Loaded catalyst volume
38.2 m3, Refer (2), (3)
(1) Catalyst cycle length and estimated life time is different for each case:
¾ NIT CASE : Estimated cycle life = 3 years, Estimated life time = 5 years
¾ AM CASE : Estimated cycle life = 1.5 years, Estimated life time = 2.5 years
¾ BH CASE : Estimated cycle life = 3 years, Estimated life time = 5 years
These cycle length and life duration are defined at iso-capacity (111 666 kg/hr)
(2) The 75-R-01 is designed to have some provision in the reactor for a future
loading. Additional catalyst amount will 49.7 m3 allow to increase catalyst cycle life
and life time for AM CASE feed.
¾ AM CASE : Estimated cycle life = 3 years, Estimated life time = 5 years
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(3) Sock catalyst loading method
HR 806
Relevant to
First HDS reactor, 75-R-02
Trade mark
HR
806,
manufactured
by
:
Axens Procatalyse Catalysts & Adsorbents
Presentation
Spheres, diameter 3mm (2 to 4mm)
Estimated cycle length
Refer (1)
Estimated life time
Refer (1)
Loaded catalyst volume
23.9 m3 refer (2), (3)
(1) Catalyst cycle length and estimated life time is different for each case:
¾ NIT CASE : Estimated cycle life = 3 years, Estimated life time = 5 years
¾ AM CASE : Estimated cycle life = 1.5 years, Estimated life time = 2.5 years
These cycle length and life duration were defined at iso-capacity (111 666 kg/hr)
(2) The 75-R-02 was designed to have some provision in the reactor for a future
loading. Additional catalyst amount will be 38.2 m3 allowing to increase catalyst
cycle life and life time for AM CASE feed.
¾ AM CASE : Estimated cycle life = 3 years, Estimated life time = 5 years
(3) Sock loading catalyst method
1.10.2 CATALYST BED PROTECTIONS
Details
Total Requirements for Reactors (75-R-01 & 75-R-02)
Material
ACT-068 (Inert Alumina)
Supplier
Axens Procatalyse Catalysts & Adsorbents.
Shape
Penta rings extrudates
Outside Diameter
25 mm
Loading density
880 kg/m3 (1)
Loaded Volume
0.25 m3
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Details
Total Requirements for Reactors (75-R-01 & 75-R-02)
Material
ACT-077 (Inert Alumina)
Supplier
Axens Procatalyse Catalysts & Adsorbents.
Shape
Fluted ring
Outside Diameter
10 mm
Loading density
550 kg/m3 (1)
Loaded Volume
0.99 m3
Material
ACT-108 (Inert Ceramic)
Supplier
Axens Procatalyse Catalysts & Adsorbents.
Shape
Hollow cylinder
Outside Diameter
8 mm
Loading density
900 kg/m3
Loaded Volume
1.12 m3
Material
ACT-139 (Inert Alumina)
Supplier
Axens Procatalyse Catalysts & Adsorbents.
Shape
Sphere
Outside Diameter
5 mm
Loading density
450 kg/m3 (1)
Loaded Volume
1.38 m3
1.10.3 INERT BALLS
¾ inch inert balls
Relevant to
Selective Hydrogenation Reactor, 75-R-01
HDS Reactor ,75-R-02
Presentation
Sphere, diameter 19mm (17 to 23mm)
Loading density
1350 kg/m3
Loaded catalyst volume (1)
4.72 m3
(1)
The volume specified for inert balls ¾” does not include inert balls volume
occupied by unloading catalyst nozzles.
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¼ inch inert balls
Selective Hydrogenation Reactor, 75-R-01
Relevant to
HDS Reactor, 75-R-02
Presentation
Sphere, diameter 6.3mm (6.0 to 8.2mm)
Loading density
1400 kg/m3
Loaded catalyst volume
29.7 m3 (1)
(1)
This amount of inert balls is defined for catalyst future loading provision.
1.10.4 CHEMICALS
1.10.4.1 Chemical during normal operation - Corrosion inhibitor agent
The corrosion inhibitor agent is injected and diluted at 10% Wt in desulfurized
heavy naphtha. Once injected in process unit, the corrosion inhibitor is at 10 ppm
wt of process stream.
Type
: CHIMEC 1044
Estimated consumption
: 832 kg/year
See also enclosed CHIMEC 1044 technical datasheet.
1.10.4.2 Chemical during transient operation – sulfiding agent
The sulfiding agent is injected at reactor inlets during start-up (first start-up and
after in-situ catalyst regeneration) in order to sulfurize the catalyst. It shall be
injected pure.
Type
: DI-METHYL DI-SULFIDE, DMDS
DMDS shall be injected during two 12-hours (max 18-hours) period. Reactor
sulfiding is done one by one.
Estimated consumption for initial catalyst loading:
o 75-R-01 : 4620 kg
o 75-R-02 : 1290 kg
Estimated consumption for future catalyst loading:
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o 75-R-01 : 6012 kg
o 75-R-02 : 2061 kg
1.11
UTILITY CONDITION AT UNIT BATTERY LIMIT
Stream
Very
Steam and condensate
High
Pressure Minimum
(From CCR unit)
Medium pressure
(for
Pressure
Temperature
(kg/cm2g)
(deg.C)
thermal 33
340
Normal
35
360
Maximum
38
380
Mechanical design:
40
400
design):
Minimum
(for
thermal 9
Saturated.
design):
Low pressure
Normal:
10
250
Maximum:
11
280
Mechanical design:
12.5
300
Minimum
(for
thermal 2.5
saturated
design):
Normal:
3.0
150
Maximum:
4.0
170
Mechanical design:
5.5
190
Steam condensate (HP Normal:
5.5
100
and HP steam)
Mechanical design:
10
185
Cooling water Supply
Minimum:
-
-
Normal
5.3
33
Maximum:
-
-
Mechanical design:
7.6
65
Minimum pressure required 3.5
44
Cooling water Return
for return:
Maximum temperature for -
-
return:
Mechanical Design
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65
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Stream
Boiler
Temperature
(kg/cm2g)
(deg.C)
47/17.5
120/120
Normal:
50/20.5
120/120
Maximum:
-
-
Mechanical Design:
71/29
155/155
Minimum:
-
-
Normal:
3.0
Ambient
Maximum:
-
-
Mechanical Design:
9.0
65
water Minimum:
(VHP/HP)
Demineralised water
Plant air (oil-free and Minimum:
3.0
water
4.0
for
catalyst Normal:
regeneration)
Instrument air
Nitrogen
Fuel gas
Fuel oil
Template No. 5-0000-0001-T2 Rev A
Page 26 of 195
Pressure
Steam and condensate
feed
Rev. A
Ambient
Maximum:
5.0
Mechanical Design:
9.0
Minimum:
4.0
Normal:
5.0
Maximum:
6.0
Mechanical Design:
9.0
Minimum:
5.0
Normal:
6.0
Maximum:
7.0
Mechanical Design:
10.5
65
Minimum:
2.5
30
Normal:
3.0
40-50
Maximum:
3.5
60
Mechanical design:
9.0
100
Minimum:
7.0
100
Normal:
8.0
130
Maximum:
11
170
Mechanical design:
17
200
65
Ambient
65
Ambient
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UTILITY SPECIFICATION:
1. NITROGEN QUALITY:
Nitrogen
99.99 % vol. min
Dew point at atm. pressure
-100 deg C
CO
traces
CO2
<3 vol ppm max
Oil content
<3 vol ppm max
Oxygen
<3 vol ppm max
2. FLARE HEADER PRESSURE:
Built
up
Back- Superimposed
Total
Back-
Pressure
Back-pressure at pressure at PSV
(kg/cm2g)
BL (kg/cm2g)
outlet (kg/cm2g)
Normal Flare
0.1
1.5
1.7
Acid Gas Flare
0.1
1.5
1.7
3. BOILER FEED WATER
pH – 8.5-9.5
Cation conductivity @ 25 0C (micromho/cm) - <5
Hardness (CaCo3) (mg/l) – Nil
Dissolved Oxygen (mg/l) – 0.007
Copper (mg/l) – Nil
Total Fe (mg/l) – 0.03
Total SiO2 (mg/l) - <0.05
KMnO4 Value @ 100 0C mg/l) - <5
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4. DM WATER
pH – 6.7-7.3
Cation conductivity @ 25 0C (micromho/cm) – 1-2
Hardness (CaCo3) (mg/l) – Nil
Turbidity (NTU) – Nil
Copper (mg/l) – Nil
Total Fe (mg/l) – <0.03
Total SiO2 (mg/l) - <0.05
KMnO4 Value @ 100 0C mg/l) - <5
5. BEARING COOLING WATER
pH – 7.5-8.0
Hardness (CaCo3) (mg/l) – 140-210
Turbidity (NTU) – 20-30 (max 50)
Total dissolved solids (mg/l) – 875-1300
M. Alkalinity (mg/l) – 100-120
Chlorides as Cl (mg/l) – 225-335
Sulphates as SO4 (mg/l) – 205-466
Organophospahtes as PO4 (mg/l) – 8-10
Total Fe (mg/l) – 1 (max)
KMnO4 Value @ 100 0C mg/l) – 30-40 (Max 50)
Oil content (mg/l) – 10 (max)
Zinc Sulphate as Zn (mg/l) – 1-2
1.13
INTERMITTENT UTILITY CONSUMPTION
1.13.1 START-UP REQUIREMENT
The estimated consumption is based on a normal start-up sequence. Intermittent
operation can be assumed to occur once every 3 years.
¾ V1=100 m3 is the estimated volume of the SHU reaction section
¾ V2=260 m3 is the estimated volume of the HDS reaction section
¾ The overall volume V is considered for utility consumption is 360 m3.
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a) Start-up instrument air
The instrument air is used for tightness test after catalyst loading:
Estimated consumption: 6 V (2160 Nm3)
b) Start-up nitrogen
Nitrogen gas is required for start-up and shutdown periods in order to free the
unit of any oxygen or hydrocarbons.
Unit pressurization:
8V
Catalyst drying:
15 V (max)
Unit purge:
3V
Total:
26 V (= 8280 Nm3)
Note: Minimum required nitrogen quality (content by volume)
O2
:
5 ppm max
H2 O
:
5 ppm max
Carbon compounds :
5ppm max
H2
:
20 ppm max
CO
:
20 ppm max
CO2
:
20 ppm max
Chlorine
:
1 ppm max
N2
:
99.7 % vol min.
c) Start-up hydrogen
Unit pressurization:
20 V
Unit purge:
10 V
Total:
30 V
Total in Nm3:
10 800 Nm3
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Note: Minimum required quality (content by volume) :
H2
:
95 % min.
C1
:
5% max.
C2+ :
0.5% max.
CO
20 ppm max.
:
CO2 :
100 ppm max.
O2
100 ppm max.
:
H2S :
1 ppm max
d) Start-up steam
LP Steam: LP Steam will also be used during start-up to inertise other equipments by
steam out.
e) Start-up inert naphtha
Estimated required volume 360 m3
1.13.2 CATALYST IN-SITU REGENERATION
a) Plant air
Oil free plant air is used during catalyst regeneration to provide oxygen for coke
combustion:
Reactor No.
Burning phase
Polish
burning Overall
phase
Kg/hr
consumption
Duration Kg/hr
Duration kg
(days)
(hr)
75-R-01
358
7
2450
9
82 190
75-R-02
960
1
5908
1.5
31 900
b) MP steam
MP steam is used for catalyst in-situ regeneration:
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Stripping phase
Reactor No.
Kg/hr
Burning phase
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Polish burning
Duration Kg/hr
Duration Kg/hr
Duration
(hr)
(days)
(hr)
75-R-01
7650
8
4473
7
2485
9
75-R-02
14730
8
11 983
1
5992
1.5
1.14
EFFLUENT SUMMARY:
a) Sour water from 75-V-03 separator drum
About 5100 kg/hr during water injection in 75-A-03 for salts removal.
75-V-03
NIT CASE
AM CASE
BH CASE
Flowrates, kg/hr
5100
5100
NA
HC content, wt ppm
300
300
NA
Dissolved H2S, wt ppm
600
320
NA
Temperature, °C
40
40
NA
b) Sour Water from HDS Stripper Reflux Drum 75-V-05
This stream is less than 20 kg/h during normal operation.
75-V-05
NIT CASE
AM CASE
BH CASE
Flowrates, kg/hr
10
11
NA
HC content, wt ppm
200
200
NA
Dissolved H2S, wt ppm
2260
2100
NA
Temperature, °C
40
40
NA
c) Gas purge from Splitter Reflux Drum 75-V-02
Continuous service for light ends removal: 537 to 905 kg/hr, 40°C at operating
temperature
d) Gas purge from HDS reaction section
In NIT Case the Amine absorber is bypassed and the purge gas (216 kg/hr) is
routed to sour purge gas.
In AM Case the Amine absorber is in service and the purge gas (56 kg/hr) is
routed to sweet purge gas.
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e) Gas purge from HDS Stripper Reflux Drum 75-V-05
This stream exists during normal operation; it is sent to the sour purge for
treatment. This stream is sour (about 11.2 to12.4 % mol).
Continuous service for light ends and H2S removal: about 428 to 855 kg/hr, 40°C
as operating temperature.
f) Regeneration gas purge to atmosphere
During PRIMEG+ reactors catalyst in situ regeneration operation, waste vapour
stream is routed to heater (75-F-01) stack at safe location under pressure control.
This waste vapour stream contains, during burning and polish burning phases:
CO2
SO2
SO3
H2O
Estimated
kg/hr
kg/hr
kg/hr
kg/hr
duration
75-R-01
83
599
15
4495
16 days
75-R-02
241
1206
31
12048
2.5 days
Reactor No.
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SECTION- 2 PROCESS DESCRIPTION
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UNIT DESCRIPTION
The completed unit is in accordance with the registered Prime G+
processing scheme. The purpose of this scheme is to meet an optimized
management of the gasoline pools regarding the sulfur content, olefins content
and octane number. The purpose is to achieve an olefin control in the gasoline
pools by an adjusted blending of the segregated olefin-rich (sulfur-lean) lighter
fraction of gasoline and the olefin-lean (sulfur-rich) gasoline.
2.2
SELECTIVE HYDROGENATION
Refer PFD No.: 04-2529-75-5FD-2 sheet1/4 Rev 0
The feed is directly taken to the SHU Surge Drum 75-V-01. The pressure in
the surge drum is maintained by split range control of hydrogen and venting to
fuel gas header. The feed is pumped by SHU Feed Pumps (75-P-01A/B) under
flow control in cascade with the surge drum level control.
The hydrogen make-up from Isomerisation unit, unit 73 is sent to the unit
under ratio flow control to the hydrocarbon feed flow and mixed with the fresh
feed before entering tube side of SHU feed/HDS Effluent exchanger (75-E01A/B).
The feed and hydrogen mixture is heated by exchanging heat with the SHU
Feed / HDS Effluent Exchanger, 75-E-01. In addition, the feed is further heated
by the SHU Feed / Effluent Exchanger 75-E-02. The final heat-up of the feed to
reach the proper reactor inlet temperature is achieved in the SHU Preheater (75E-03). To allow a good control of the SHU reactor inlet temperature, a minimum
temperature increase of 50C must be done in the steam preheater. For that
purpose, a bypass of the 75-E-01 and 75-E-02 exchanger is installed and
controlled by temperature difference on 75-E-03.
The heated feed / hydrocarbon mixture flows to the top of the SHU reactor.
The reactor contains two beds of HR-845 catalyst. Operating conditions and
catalyst are optimized to provide selective hydrogenation of diolefins in the feed
and convert light mercaptans into heavier boiling temperature sulfur compounds.
A bypass line of the first bed was provided in case of any pressure drop
build-up in the 75-R-01 SHU reactor. The effluent from the SHU reactor flows
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through the SHU Feed / Effluent Exchanger 75-E-02 and into the Splitter 75-C01, under pressure control.
2.3
SPLITTER SECTION
Refer PFD No.: 04-2529-75-5FD-2 sheet 2/4 Rev 0
The Splitter has 52 trays and the feed enters the column at tray 19
(numbering from bottom). The purpose of the Splitter is to fractionate the feed
and produce a Light Cracked Naphtha (LCN) and a Heavy Cracked Naphtha
(HCN). The LCN / Heart cut gasoline cut-point is adjusted to produce a low-sulfur
LCN while simultaneously recovering a large portion of olefins. This is possible
since the heavier boiling components contain a high disproportionate amount of
sulfur relative to low olefins content.
The Splitter overhead is almost totally condensed by air-cooling in the
Splitter Overhead Air Condenser 75-A-01. Vapour (excess hydrogen and light
ends) is separated from the reflux liquid in the Splitter Reflux Drum (75-V-02).
The Splitter Post Condenser (75-E-04) cools the vapour purge to battery limit
conditions in order to recover light ends from the purge. The splitter pressure is
controlled by the split range control of pressurizing hydrogen (normally no flow)
and venting to fuel gas header. The liquid is pumped by the Splitter Reflux
Pumps (75-P-03 A/B) and returned to the top of 75-C-01 as reflux, under flow
control in cascade with the reflux drum level control.
The LCN product is drawn from the accumulator tray number 48 of the
Splitter (numbering from bottom). It is cooled with the light gasoline Air cooler
(75-A-06) under flow control in cascade with the splitter tray 44 temperature
control of lighter sulfur compounds concentrated in the LCN.
The Splitter bottom is reboiled with 75-E-07 HP steam reboiler. The
reboiling steam rate is under flow control in cascade with the Splitter reflux flow.
Heavy naphtha from the splitter bottom (75-C-01) is sent to HDS section under
flow control in cascade with the splitter bottoms level control.
One benzene heart-cut is foreseen in order to reduce benzene content in the
gasoline pool in case of high concentration benzene in the PRIME G + feed. The
heart-cut benzene is drawn from the accumulator tray number 36. The heart-cut
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stream is cooled by light gasoline air cooler 75-A-02 and pumped by 75-P-05 A/B
to storage after final cooling in 75-E-06 A/B under flow control reset by 31st tray
temperature control.
As the selective hydrogenation reactor is operated mainly in liquid phase, a
sufficient liquid velocity shall be maintained at its inlet. Therefore, the
hydrocarbon flow rate to the reactor shall be at least of 75% of the normal flow
rate. In case of turndown (50% of feed), part of the splitter bottom shall be
recycled to the SHU feed surge drum under flow control.
2.4
HDS SECTION
Refer PFD No.: 04-2529-75-5FD-2 sheet 3/4 Rev 0
The heavy naphtha from 75-C-01 Splitter is pumped by HDS Feed Pumps
(75-P-02 A/B) under flow control in cascade with the splitter level control. The
main part of HCN feed is mixed with the recycle hydrogen before entering the
First HDS Feed / Effluent Exchanger (75-E-08 A/B/C).
The HDS reactor is divided in 3 beds of HR806 catalyst. The overall temperature
rise in the reactor is controlled by two injection of recycle liquid quench from the
separator drum 75-V-03 between the three beds.
The HDS effluent is further heated in HDS heater, 75-F-01. The heater operates in
vapor phase and the feed HDS reactor inlet temperature is controlled via fuel gas
control. The effluent from the heater is then cooled by the HDS feed / effluent
exchangers 75-E-08 A/B/C and by exchanger with the SHU reactor feed/HDS
effluent exchanger 75-E-01. Final cooling is achieved in the HDS effluent air
cooler 75-A-03 and the reactor effluent trim coolers 75-E-09 A/B.
An intermittent washing water injection point upstream the HDS effluent air
condenser 75-E-03 enables to flush these equipment from salt deposit that may
have been formed at low temperature.
The hydrocarbon liquid is partially pumped back to the HDS section through 75-P06 A/B quench pumps. The remaining part of the liquid is routed to the stabilizer
section under flow control reset by 75-V-03 level control.
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RECYCLE COMPRESSOR SECTION
Refer PFD No.: 04-2529-75-5FD-2 sheet 3/4 Rev 0
The vapour enters the amine KO drum (75-V-06) where it is freed from
condensed liquid hydrocarbon particles due to a wire mesh.
In the amine absorber (75-C-02) the recycle gas is contacted with a 25 % wt
lean DEA solution coming from battery limits. The lean DEA is pre-heated in the
lean amine pre-heater (75-E-10), thus maintaining a 10°C temperature difference
between the gas and the amine.
The H2S enriched DEA, collected in the absorber bottoms, is then routed to
the DEA regeneration unit under amine absorber bottoms level control.
The sweetened gas is mixed with the H2 make up, then flows to the recycle
compressor K.O. drum (75-V-04) where it is freed from any liquid amine
entrainment that may have occurred.
Part of the gas is then purged to the fuel gas network under flow control to
prevent any light end concentration in the recycle loop. The remaining part of the
gas is compressed back to the 75-E-08 A/B/C inlet by the recycle compressor 75K-01 A/B.
2.6
STABILIZER SECTION
Refer PFD No.: 04-2529-75-5FD-2 sheet 4/4 Rev 0
The liquid from the separator is heated through the stabiliser feed/bottoms
heat exchangers (75-E-11 A/B) and enters the Stabiliser column (75-C-03). The
overhead of the stabilizer is condensed through the stabilizer overhead air
condenser (75-A-05) and additionally cooled in stabilizer overhead trim coolers
75-E-14A/B. The liquid phase, the water phase (if any) and the vapour phase
separate in the stabilizer reflux drum (75-V-05), the pressure of which is
controlled by the purge gas flow. The water collected in the boot is sent to the
sour water treatment under boot level control.
The liquid is routed back to the column as reflux by the stabilizer reflux
pumps (75-P-09 A/B) under flow control reset by reflux drum level control.
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The stabilizer overhead is protected from corrosion by corrosion inhibitor injection
from the corrosion inhibitor package (drum + metering pump) into the stabilizer
overhead line.
The stabilizer bottom is reboiled by HP steam reboiler (75-E-13), the duty of
which is adjusted by HP steam flow rate reset by stabilizer sensitive tray control.
The bottoms of the stabilizer (treated heavy gasoline) is sent to storage under
flow control reset by stabilizer bottoms level control. The cooling down of the
stabilizer is ensured first by the stabilizer feed/bottoms heat exchanger (75-E-11
A/B) and by the heavy gasoline air cooler (75-A-07) heavy gasoline trim cooler
(75-E-12 A/B).
2.7
CATALYST IN-SITU REGENERATION OPERATION
The PrimeG+ unit is equipped with catalyst in-situ facilities that involve:
¾ An air injection line to Reactor heater 75-F-01 for burning operation
¾ A steam injection to Reactor heater 75-F-01 for stripping and burning
operations,
¾ A nitrogen injection to Rector heater 75-F-01 for heating operation
The regeneration steps described below are equivalent for each reactor 75-R01 and 75-R-02 except the duration which may vary depending on the amount of
catalyst and steam and air flow rate.
The reaction section is hydrocarbon free and put under nitrogen atmosphere.
Then feed surge drum, feed pumps, splitter and stripper sections are isolated
from the reaction section.
The regeneration procedure includes:
1. A heating phase by nitrogen with 200°C catalytic bed reactor temperature.
2. A stripping phase by steam with 400°C catalytic bed reactor temperature for 8
hours.
3. A coke burning phase by steam and air with 0.3 up to 3.0 vol % oxygen in the
reactor inlet gas with 460°C catalytic bed reactor temperature
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4. A catalyst polish burning phase by steam and air with 3.0 up to 8.0 vol %
oxygen and 480°C reactor inlet temperature. (These conditions are kept
during 4 hours).
5. A first cooling down of the reactor temperature to 200°C by steam.
6. A second cooling down of the reactor temperature to 65°C. Steam is replaced
by nitrogen.
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SECTION- 3 PROCESS PRINCIPLE
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3.1
PURPOSE OF THE PROCESS
3.2
GENERAL
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The purpose of the Prime G+ unit is a deep hydrodesulfurization of a FCC
gasoline. The majority of sulfur in the typical refinery gasoline pool is coming from
the FCC gasoline. This product is also characterized by a high olefins content.
Deep hydrodesulfurization of high sulfur content gasoline means the
process producing gasoline meeting the toughest sulfur standards. The
conventional gasoline desulfurization technology makes difficult to preserve
octane number due to olefin contents while meeting gasoline specifications, for
low sulfur content. At high level desulfurization, olefins are converted to low
octane alkanes, causing the road octane, (RON + MON)/2, to drop by a 5 to 10
points which is unacceptable. This is the aim of Prime-G+ process to remove
sulfur while avoiding substantial octane losses.
The treatment process operates in three reactors, having the specific catalyst
and operating conditions.
¾ In the SHU reactor (75-R-01), diolefins are hydrogenated and light sulfur
compounds are converted into heavier sulfur species. The reactors effluent is
sent to a splitter column where it is split into three fractions: Light FCC
gasoline, FCC Heart cut gasoline and heavy FCC gasoline. FCC gasoline
heart cut is foreseen for high benzene content in the feed.
¾ In the HDS reactor (75-R-02), most of the desulphurisation of the gasoline
takes place, so that the final gasoline pool meets the sulfur specifications.
Despite the high degree of desulfurization, olefin saturation is very limited and
no aromatic hydrogenation occurs. It is followed by a stabilization column to
remove the light ends, H2S and water resulting from the reaction and from
dissolved components in hydrogen make-up and recycle gases.
3.3
SELECTIVE HYDROGENATION REACTOR (75-R-01)
The purpose of the SHU reactor is hydrogenation of diolefins in order to avoid
gum formation in HDS reactor. Moreover, it allows to convert light mercaptans
and light sulfides to heavier sulfur compounds.
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The reaction is carried out in one down flow reactor operating mainly in liquid
phase with dissolved hydrogen at low temperature.
The reactor effluent is separated into three fractions in the splitter: light gasoline,
heart cut (intermittent mode for high benzene content in the feed) and heavy
gasoline. The light stream has a very low sulfur content and does not require an
extractive sweetening to further lower the sulfur content.
The light gasoline is a final product and is blended with the stabilizer bottom
before being routed to storage tanks, while heavy gasoline is fed to the HDS
reactor for further hydrodesulfurization.
3.4
SPLITTER (75-C-01)
Before being sent to atmospheric storage, light gasoline must be blended with the
stabilizer bottoms or with an other low RVP stream due to the high RVP of the
light gasoline stream.
The FCC gasoline contains mercaptans, thiophene, alkyl thiophenes and
benzothiophene boiling in the same order, with the benzothiophenes being the
higher boiling sulfur components. As mercaptans and light sulfides are converted
into heavier sulfur species in the first reactor, thiophene becomes the first
significant sulfur component to be entrained in the light FCC gasoline product.
The TBP cut point temperature range for the thiophene boil up is about 55°C to
80°C. In general, olefins tend to concentrate in the lighter portion of the FCC
gasoline. Splitter operation is important to achieve a good balance between the
sulfur and olefin concentration present in the heavy FCC gasoline that is sent to
the HDS Reaction Section. The optimum amount of light gasoline depends on the
FCC feed sulfur content, feed thiophene content and on the product sulfur
specification. The exact amount of light FCC gasoline drawn should be precisely
controlled by monitoring the on-line light FCC gasoline sulfur analyzer.
The light FCC gasoline draw rate and the sulfur content is controlled indirectly by
a temperature controller located on the Splitter column a few trays below the light
FCC gasoline draw tray.
A lower light FCC gasoline withdrawal rate from the Splitter will produce an heavy
FCC gasoline with higher olefin concentrations and hence potentially higher
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octane losses in the HDS Reaction Section. Alternatively, a higher light FCC
gasoline withdrawal rate from the Splitter will produce an heavy FCC gasoline
with lower olefin concentrations which is initially favorable for octane losses in the
HDS Reaction Section but with increased sulfur levels in the light FCC gasoline.
As the light FCC gasoline rate in the Splitter is increased, the severity of the HDS
Reaction Section has to be increased to offset the amount of sulfur that has left
with the light FCC gasoline.
3.5
FIRST HDS REACTOR (75-R-02)
The purpose of the HDS reactor is to achieve the bulk of the hydrodesulfurization
of the heavy FCC gasoline, while limiting olefins saturation.
The reaction is carried out between the vaporized gasoline and an hydrogen rich
gas over a desulfurization catalyst bed.
Sulfur in cracked gasoline is distributed as follows:
¾ Aromatic sulfur (benzothiophene).
¾ Acidic sulfur (mercaptan type).
¾ Disulfide type.
¾ Sulfide type.
¾ Thiophene and alkyl thiophenes.
3.6
3.6.1
CHEMICAL REACTIONS AND CATALYST
OBJECTIVE
The objective is to help the operators to better understand the reasons of the
operating instructions and enable them to make wise decisions, should the
circumstances deviate from those covered in the Operating Instructions.
The different chapters of this section describe:
1. The various chemical reactions involved in the process as well as the effect of
the operating conditions.
2. The catalyst characteristics.
3. The catalysis mechanism.
4. The catalyst contaminants.
5. The process variables.
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THERMODYNAMICS AND KINETICS
For any chemical reaction, the thermodynamics dictates the conditions of its
occurrence and the amount of products and unconverted reactants. In fact, some
reactions are 100% completed i.e., all the reactants are converted into products.
Others are in equilibrium i. e., part of the reactants only are converted. The
amount of products and reactants at equilibrium depends upon the operating
conditions and is dictated by the thermodynamics. Note that the thermodynamics
does not involve the time required to reach equilibrium or the completion of a
reaction.
Kinetics dictates the rate of a chemical reaction (i. e., the amount of feed that is
converted to products during defined time).
Kinetics (rate of reaction) is
dependent upon the operating conditions but can also be widely modified through
the use of properly selected catalysts. One reaction (or a family of reactions) is
generally enhanced by a specific catalyst.
In other words thermodynamics dictates the ultimate equilibrium composition
assuming the time is infinite while kinetics enables the prediction of the
composition after a finite time. Since time is always limited, when reactions are
concurrent, kinetics is generally predominant.
A catalyst generally consists of a support (earth oxide, alumina, silica,
magnesia...) on which (a) finely dispersed metal(s) is (are) deposited.
The metal is responsible for the catalytic action, but very often the support has
also a catalytic action related to its chemical nature.
A catalyst is not consumed, but can be deactivated either by impurities in the
feed or by some of the products of the chemical reactions involved, resulting in
polymers or coke deposits on the catalyst.
3.6.3
CATALYST ACTIVITY, SELECTIVITY AND STABILITY
The main characteristics of a catalyst other than its physical and mechanical
properties are:
¾ The activity which is the catalyst ability to increase the rate of the reactions
involved. It is measured by the temperature at which the catalyst must be
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operated to produce a product on-specification, for a given feed, all other
operating conditions being equal.
¾ The selectivity expresses the catalyst ability to favour desirable reactions
rather than others. It is measured by the quantity of desired product.
¾ The stability characterizes the change with time of the catalyst performance
(i. e., activity, selectivity) when operating conditions and feed are stable. It
is chiefly polymers or coke deposits that affect stability since they decrease
the metal contact area. Traces of some metals in the feed also adversely
affect stability.
3.6.4
SELECTIVE HYDROGENATION REACTIONS AND CATALYST
In SHU reactor, the hydrogenation of diolefins takes place in order to avoid gum
production and in the HDS reactor, hydrodesulfurization takes place. They also
convert the light mercaptans and some other light sulfur compounds to heavier
sulfur compounds, to enable producing a light naphtha fraction almost free of
mercaptans and light sulfides.
3.6.5
CHEMICAL REACTIONS
The FCC gasoline contains the following unsaturated components:
•
Diolefins (aliphatics or cyclics).
•
Olefins.
•
Aromatics.
Several chemical reactions can take place during the diolefin hydrogenation. The
most important ones are:
•
The hydrogenation of diolefins.
•
The conversion of light sulfur compounds into heavier sulfur species.
•
The isomerization of olefins.
•
The hydrogenation of olefins.
The last reaction must be avoided as much as possible.
3.6.6
HYDROGENATION OF DIOLEFINS
Diolefins are hydrogenated into corresponding olefins and some of the olefins are
hydrogenated into corresponding paraffins.
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A) Cyclodiolefins
•
A typical example is cyclohexadiene which is hydrogenated into cyclohexene
with no further hydrogenation with the catalyst and at the operating conditions
of the first stage.
+ H2
Cyclohexadiene
Cyclohexen
B) Normal or isodiolefins
Normal diolefins:
Their hydrogenation produce several isomers, for example:
CH3 - CH2 - CH2 - CH2 - CH2 - CH = CH2
CH3 – CH = CH – CH2 – CH2 – CH = CH2 + H2
1 – 5 Heptadiene
1 Heptene
CH3 - CH = CH - CH2 - CH2 - CH2 - CH3
2 Heptene (cis and trans)
Iso-diolefins
Isodiolefins hydrogenation produces also various isomers. Moreover double bond
migration can also occur within the newly generated isomer.
Diolefins are very unstable compounds, which polymerize easily into gums.
Therefore conversion of diolefins into olefins improves the product quality: these
reactions are highly exothermic. The difference between the diene value (DV) or
the maleic anhydride value (MAV) of the feed and the DV or MAV of product
measures the yield of these reactions and could be related to the hydrogen
consumption. Refer to chapter "Operation of the unit".
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ISOMERIZATION OF OLEFINS
CH2 = CH - CH2 - CH2 - CH2 - CH3 → CH3 - CH = CH - CH2 - CH2 CH3
1 - Hexene
2 - Hexene
This reaction, thermodynamically enhanced by low temperatures (T < 200°C),
takes place when diolefins are almost completely eliminated. It offers the
advantage of leading to internal olefins that are more stable towards
hydrogenation than external olefins. Thus the selectivity is improved. In addition,
internal olefins often have a higher octane number.
3.6.8
HYDROGENATION OF OLEFINS
These reactions are undesirable because they reduce the octane number.
The hydrogenation of diolefins is faster than the hydrogenation of olefins.
Nevertheless it is difficult to avoid totally hydrogenation of olefins, particularly if
the feed contains 1-olefins which are more reactive than 2,3-olefins.
This reaction is also exothermic.
The difference between the feed bromine number (BrN) and the product bromine
number measures the conversion rate of this reaction and could be related to the
hydrogen consumption. Refer to chapter "Operation of the unit".
3.6.9
THERMAL AND CATALYTIC POLYMERIZATION OF UNSTABLE COMPOUNDS
These reactions are undesirable because polymer deposits reduce both catalyst
activity and cycle duration.
The catalytic polymerization of olefins and even diolefins remains negligible, in
the range of the selected operating conditions, when the appropriate catalyst is
used.
3.6.10 THERMODYNAMIC AND KINETIC ANALYSIS
The hydrogenation of unsaturated hydrocarbons is characterized by an important
heat release (exothermic reaction) and a reduction of volume.
Consequently
from a thermodynamic point of view, these reactions are favored by low
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The typical heats of reaction (per mole of
reactant) are respectively:
Diolefins to olefins :
26 Kcal/mole
Olefins to paraffins :
30 Kcal/mole
From a kinetic viewpoint, with a proper catalyst, at temperature in the range of
160°C, the rate of the diolefins hydrogenation is high enough for almost complete
hydrogenation.
3.6.11 SULFUR REACTION
In cracked naphthas (FCC gasoline and pyrolysis gasoline), the principal sulfur
compounds include mercaptans (RSH), aliphatic sulfides (RSR), aliphatic
disulfide
and
thiophenes.
Over
selective
hydrogenation
catalysts,
light
mercaptans and light sulfides are converted to heavier sulfur species. In addition,
H2S is also converted to heavier sulfur compounds. The combination of selective
hydrogenation and FCC naphtha fractionation allows the production of a light
naphtha stream with a very low sulfur content, provided that thiophene carry-over
in this stream is controlled. The sulfur shift reactions are faster reactions than the
diolefin hydrogenation reactions.
The heavy sulfur compounds produced over the selective hydrogenation
catalysts are essentially heavy sulfides and, to a lesser extent, heavy
mercaptans. The following mechanisms are believed to take place:
Conversion of light mercaptans to heavy sulfides
1. Conversion of light mercaptans to heavy mercaptans
2. Conversion of sulfides to heavier mercaptans
3. Conversion of H2S to mercaptans
Although some of these mechanisms involve the production of some H2S, the
H2S addition reaction is a very fast reaction. Therefore, no H2S exits the reactor.
Approximately 95-98% of the light mercaptans are converted in the Selective
Hydrogenation reactor. Carbonyl sulfide (COS) and carbon disulfide (CS2) will
also be converted to near extinction. Di-methyl sulfide (DMS) and ethyl-methyl
sulfide (EMS) conversion is limited at approximately 50-70%.
Following are examples of the reactions that occur:
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Conversion of Light Mercaptans to Heavier Sulfides
RSH +
R' (C5 to C7 olefin) ↔
RS R'
Conversion of Light Mercaptans to Heavier Mercaptans
Step 1
RSH +
H2
↔
RH
+ H2S
Step 2
H2S
+
R' (C5 to C7 olefin) ↔
R'SH
Conversion of Sulfides to Heavier Mercaptans
CH3 – S – CH3 or +
H2
→
CH4 and C2H6
+
H2 S
C2H5 – S – CH3
H2S +
R' (C5 to C7 olefin) ↔
R'SH
Conversion of H2S to Heavier Mercaptans
H2S +
3.7
R' (C5 to C7 olefin) ↔
R'SH
PROCESS VARIABLES IN SELECTIVE HYDROGENATION
There are four main process variables:
3.7.1
•
Reactor temperature,
•
Residence time in the reactor,
•
Reactor pressure,
•
Hydrogen gas rate.
REACTOR TEMPERATURE
Thermodynamics for conversion of light mercaptans and selective hydrogenation
of diolefins are very favorable. The reaction will go to completion over a wide
range of operating temperature. Diolefin hydrogenation to olefins is completed
even at relatively high temperature and low H2 content.
•
From a kinetic perspective, the mercaptan conversion and hydrogenation rate
is increased at higher temperature.
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Hydrogenation selectivity (diolefin/olefin), however, is favored by lower
temperature.
•
For catalyst stability, the operation must take place at lower temperature to
prevent polymerization of gum precursor compounds. Thermal polymerization
deactivates the catalyst by coating of the active area and is accelerated at
temperatures above 200°C.
•
Low operating temperature minimizes vaporization of the feedstock, keeping
the reactants in the liquid phase at moderate pressures.
However, as catalyst ages, polymer deposits progressively coat the selective
sites and catalyst activity decreases (i.e. at the same temperature, conversion
drops). A slight progressive increase in reactor temperature is used to
compensate for this loss of activity. The limit correspond to the end of run
temperature.
The normal inlet temperature for a feed composition as specified in the design
basis, ranges from the start of run (SOR) figure to the end of run (EOR) figure.
Refer to chapter “operation of the unit/summary of operating condition”.
3.7.2
RESIDENCE TIME IN THE REACTOR
In chemical catalysis, the residence time is expressed through the liquid hourly
space velocity (LHSV) which is defined as the ratio of the hourly liquid feed flow
rate (expressed in volume at 15°C) to the catalyst volume.
LHSV =
Liquid feed volume(at 15° C) per hour
Volume of catalyst
Both volumes must be expressed with the same unit.
For a liquid phase reaction, taking place at 15°C, the residence time of the feed
on the catalyst is then the reverse of the LHSV. A LHSV of 2 h-1 means a
residence time, at the operating temperature, close to 1/2 hour.
Increasing the residence time (i. e., decreasing the feed hourly flow) results in a
higher conversion of diolefins, and on the contrary, increasing the feed flow rate
results in a lower conversion.
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REACTOR PRESSURE
An important criterion for liquid phase hydrogenation is the content of dissolved
hydrogen. The content of dissolved hydrogen depends on the total pressure, the
hydrogen make-up flow and the hydrogen make-up purity. Complete diolefin
hydrogenation requires only a small amount of hydrogen in excess of the
stoechiometric requirement.
Higher operating pressure:
•
Improves diolefin hydrogenation.
•
Reduces the polymerization reactions/coke deposits and increases catalyst
cycle length.
•
Increases hydrogen dissolved in the liquid phase.
•
Improves liquid distribution in the reactor and reduces pressure drop due to
vaporization.
The reactor operating pressure is fixed at the design stage, operator will maintain
this maximum operating pressure during all normal operation.
3.7.4
HYDROGEN MAKE-UP RATE
An increase in H2 make-up rate will favor light mercaptans conversion and
diolefins hydrogenation. However, a large excess of hydrogen would lead to
partial saturation of olefins, in other words to higher octane loss.
Therefore, operation will aim at feeding unit with a small excess of H2 (25%)
calculated from a chemical consumption assuming 90 to 100% hydrogenation of
diolefins and 3% hydrogenation of olefins.
A 40% excess has also been foreseen at design stage corresponding to EOR
conditions.
3.8
3.8.1
CHEMICAL: HDS REACTOR REACTIONS AND CATALYST
CHEMICAL REACTIONS
Sulfur removal is the major purpose of this reactor in order to prepare a
desulfurized stock of the gasoline pool. However, partial olefin saturation
reactions and partial denitrogenation (denitrification) of a small amount of
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nitrogen compounds that are present in the feed occur simultaneously with
desulfurization.
The reaction taking place in the reactor can be grouped as follows:
•
Hydrorefining (i.e. desulfurization, denitrification).
•
Hydrogenation of olefins (which are undesirable reactions).
All these reactions are exothermic.
3.8.2
HYDROREFINING
A) Desulfurization
The typical sulfur compounds in cracked gasoline are of the thiophenic and
benzothiophenic types.
The desulfurization occurs in several phases.
Thiophene
Thiophane
Mercaptans
H2S
The desulfurization reactions are exothermic, but owing to the limited amount of
reactant involved, they do not lead to a noticeable temperature increase.
The rate of desulfurization reactions follows first-order kinetics. In the reactor, the
desulfurization reactions take place. Benzothiophenes and thiophenes are
essentially converted and the residual sulfur is essentially in the form of
thiophanes (or tetra-hydro-thiophenes) and mercaptans.
B) Denitrification (or denitrogenation)
Nitrogen is removed in catalytic hydrotreating by the breaking of the C-N bond
producing a nitrogen free aliphatic and ammonia. The breakage of the C-N bond
is much more difficult to achieve than the C-S bond in desulfurization.
Consequently denitrification occurs to a much lesser extent than desulfurization.
Nitrogen compounds typically found in cracked gasolines are methylpyrrol and
pyridine types.
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CH
+ 4H 2
CH
C
5
H
12
+
NH 3
C - CH 3
NH
Methylpyrrol
n-pentane
+ 5 H2
ammonia
C5 H12 + NH3
n- pentane ammonia
N
pyridine
The heat released by the denitrification reactions is also negligible owing to the
small amount of nitrogen compound involved.
3.8.3
HYDROGENATION OF OLEFINS
Hydrogenation or olefin saturation is the addition of a hydrogen molecule to an
unsaturated hydrocarbon to produce a saturated product. Olefinic hydrocarbons
are found in high concentrations in cracked gasolines. The olefin saturation
reaction is highly exothermic and is controlled by the process. The comparative
reactivity of olefins is the following (from more reactive to less reactive):
n α - olefins > n internal olefins > α branched olefins > cyclic olefins > internal branched
olefins
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Typical olefins hydrogenation reactions are:
+ H2
CH3 - CH2 - CH2 -CH2 -CH2 - CH = CH2
CH3 - CH2 - CH2 - CH2 - CH2
-CH2 -CH3
1-heptene (n α - olefins)
n-heptane
+ H2
CH3 - CH - CH = CH –CH3
CH3
CH3 - CH - CH2 - CH2 - CH3
4 methyl 2 pentene
CH3
2 methyl pentane
(internal branched olefins)
The reactions of this type are exothermic ( ∆ H = 30 kcal/mol).
3.9
RELATIVE RATES OF REACTION
Under the selected operating conditions and the choice of catalyst, these
reactions are classified hereafter in decreasing order of reaction rate:
hydrodesulfurization > olefins hydrogenation > > > aromatic hydrogenation
3.9.1
PROCESS VARIABLES IN HDS REACTOR
There are four main process variables:
•
Reactor temperature
•
Operating pressure and Hydrogen/hydrocarbon ratio
•
Space velocity.
For each of these variables, we have to distinguish their influence on activity and
on selectivity.
3.9.2
TEMPERATURE
Thermodynamically, as the hydrodesulfurization and olefin hydrogenation
reactions are exothermic, these reactions are favored by low temperature.
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In terms of selectivity, an increase of temperature enhances the selectivity
between hydrodesulfurization and olefin hydrogenation but the impact is very low.
Nevertheless, a control of temperature in reactors makes the process control
easier and avoids some phenomena like runaway.
Practically, temperature must be selected high enough that the naphtha is in
gaseous phase at the operating pressure but keeping a margin for temperature
increase to compensate for catalyst deactivation.
Typical operating temperatures range from 270°C (inlet T, SOR) to 300°C (inlet
T, EOR) for the high sulfur feed (first reactor).
In
term
of
activity,
a
higher
temperature
increases
the
activity
of
hydrodesulfurization and olefins hydrogenation reactions.
The target will be to operate at the minimum temperature compatible with the
level of desulfurization required.
In case a lower sulfur feed is processed in the unit, the thermal levels on the first
reactor are lowered to 245°C (inlet T, SOR) and to 275°C (inlet T, EOR), ex: BH
case.
3.9.3
OPERATING PRESSURE AND H2/HC RATIO
A) Hydrogen partial pressure
In terms of activity, an increase of the hydrogen partial pressure enhances the
hydrodesulfurization and olefins hydrogenation.
In addition, a high hydrogen partial pressure reduces the polymerization reactions
and coke deposit, increasing the cycle length.
B) Hydrocarbons partial pressure
This parameter has no impact on the hydrodesulfurization. Nonetheless, to
minimize hydrogenation of olefins, it is necessary to minimize olefin partial
pressure therefore hydrocarbon partial pressure. Hence, the operating pressure
is selected to optimize the HDS reaction rate and the HDS selectivity over the
olefin hydrogenation reactions.
C) H2 / HC ratio
As the operating pressure is selected during the design stage, the most important
operating variable is the H2/HC ratio. An increase of the H2/HC ratio enhances
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activity and selectivity in favor of hydrodesulfurization (higher ppH2 , lower ppHC,
lower ppH2S)
In practice, the recycle gas compressor must be operated at its maximum
capacity in order to maximize the H2/HC ratio.
D) Hydrogen sulfide partial pressure
The effect of H2S partial pressure on the hydrogenation of olefins is very slight,
but H2S affects the hydrodesulfurization. Therefore, an increase of the hydrogen
sulfide partial pressure has a negative effect on the selectivity. An amine washing
of recycle gas is provided to decrease the H2S content.
3.9.4
SPACE VELOCITY
As the reactor operates in the gaseous phase with a large amount of recycle
hydrogen, the residence time is only proportional (not equal) to the inverse of the
space velocity.
Space velocity is a parameter readily available to operators. Each time the feed
flow is changed, the space velocity changes in proportion to the flow. A decrease
of the space velocity (i.e. an increase of the residence time) enhances the activity
of reactions, yet without any enhancement of selectivity .
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SECTION- 4 UTILITY DESCRIPTION
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INTRODUCTION
The utility system consists of Nitrogen, Instrument Air (IA). Plant Air (AP), Sea
Cooling Water (WC), Service Water (SW), Boiler Feed Water (BFW), HP/MP/LP
Steam, LP Condensate, Bearing Cooling water (BCW) and Fuel Gas (FG).
Closed Blow down (CBD), Amine Blow down (ABD) Flare is also provided within
the unit.
Description related to various utility systems for Prime G+unit is given below.
4.1.1
INSTRUMENT AIR SYSTEM
A 2" Instrument Air header supplies IA to Prime G+ Unit. The header is provided
with isolation valve and a spectacle blind. Various Instrument air tapping are
taken from this header. In DCS FI-4502 with FQ and FAH/FAL, PI-4505 with
PAH/PAL and TI-4502with TAH/TAL and local TI, PI is provided on the 3” header
at B/L.
4.1.2
PLANT AIR SYSTEM
A 6" Plant Air header supplies PA to Prime G+ Unit. The header is provided with
isolation valve and a spectacle blind. Various Instrument air tapping are taken from
this header. Plant air is also used during in-situ regeneration. In DCS FI-4501 with
FQ, and local TI, PI is provided on the 6” header at B/L.
4.1.3
SEA COOLING WATER SYSTEM
The cooling water requirement for cooling purpose in the Prime G+ Unit is met
through Offsite Sea cooling water system. A 16” sea cooling water supply header
supplies cooling water to Prime G+ Unit. The header is provided with isolation
valve and a spectacle blind for positive isolation at the battery limit. PI-4602 with
PAH/PAL, TI-4602 with TAH/TAL and FI-4601 with FQ/FAH/FAL and local TI & PI
are provided on the 14” header at B/L.
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Cooling water from the supply header is taken to the following equipment in Prime
G+ Unit.
•
Recycle Compressor (75-K-01A/B)
•
FCC Heart cut cooler (75-E-06A/B)
•
Light Gasoline cooler (75-E-05A/B)
•
Splitter post condenser (75-E-04A/B)
•
Reactor effluent trim cooler (75-E-09A/B)
•
Heavy Gasoline cooler (75-E-12A/B)
The return water is collected in a 16” return header and sent to B/L. Individual return
line from cooler is provided with a Local temperature Indicator (TI) and Thermal
safety valve. The return header is provided with isolation valve and a spectacle
blind for positive isolation at the battery limit. The return header is also provided with
TI-4603, with TAH/TAL, PI-4603 with PAH/PAL and FI-4602 with FAL/FAH in DCS
and local PI & TI at B/L. A 6” Jump over between supply and return header is also
provided at B/L.
4.1.4
BEARING COOLING WATER SYSTEM
The cooling water requirement for cooling purpose of pump cooling in the Prime
G+ Unit is met through Offsite Bearing cooling water system. A 4” Bearing cooling
water supply header supplies BCW to Prime G+ Unit. The header is provided with
isolation valve and a spectacle blind for positive isolation at the battery limit. PI-4702
with PAH/PAL, TI-4702 with TAH/TAL and FI-4701 with FQ/FAH/FAL and local TI &
PI are provided on the 4” header at B/L.
BCW from the supply header is distributed to various pumps/equipment in Prime
G+ Unit.
The return water is collected in a 4” return header and sent to B/L. Individual
return line from cooler is provided with a Local temperature Indicator (TI) and
Thermal safety valve. The return header is provided with isolation valve and a
spectacle blind for positive isolation at the battery limit. The return header is also
provided with TI-4703 with TAH/TAL, PI-4703 with PAH/PAL, FI-4702 with
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FAL/FAH in DCS and local PI & TI at B/L. A 4” Jump over between supply and
return header is also provided at B/L.
4.1.5
SERVIC WATER SYSTEM
The 2” common service water header supplies service water to Prime G+
Unit. It is provided with an isolation valve and a spectacle blind at battery limit. In
DCS FI-4503 with FQ and Local PI/TI is provided at the battery limit. The service
water header supplies water to various hose stations in the units. Service water is
required mainly for cleaning and washing.
4.1.6
NITROGEN
A 8” header supplies N2 to Prime G+ Unit. N2 is used for various purposes
in equipment, line etc. for inertisation, blanketing, purging, in-situ regeneration
etc. The supply header is provided with DCS FI/FQ-4101 with FAH/FAL, PI-4102
with PAL/PAH along with local PI & TI at B/L.
4.1.7
LP STEAM SYSTEM
A 6” header supplies LP steam to Prime G+ Unit. FI/FQ-4401 with
FAL/FAH, PI-4402 and TI-4402 with Low and High alarm is provided in DCS to
monitor LP steam B/L condition. Also local PI & TI are provided. At B/L block
valve along with spectacle blind are provided for positive isolation.
Use of LP steam in the unit is mainly as follows:
4.1.8
•
Utility hose station
•
For Tracing Requirement
•
Various Process User
MP STEAM SYSTEM
A 10” header supplies HP steam to Prime G+ Unit. FI/FQ-4403 with
FAL/FAH, PI-4402 and TI-4402 with Low and High alarm is provided in DCS to
monitor HP steam B/L condition. Also local PI & TI are provided. At B/L block
valve along with spectacle blind are provided for positive isolation.
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Use of HP steam in the unit is mainly as follows:
4.1.9
•
Start-up ejector (75-J-01)
•
For in-situ regeneration burning phase.
•
Heater De-coking purpose
•
For Lancing steam
VHP STEAM SYSTEM
A 8” header supplies VHP steam to Prime G+ Unit. VHP PRDS (75-X-01) is
provided to reduce the steam pressure. FI/FQ-4301 with FAL/FAH, PI-4302 and
TI-4302 with Low and High alarm is provided in DCS to monitor VHP steam B/L
condition. Also local PI & TI are provided. Block valve along with spectacle blind
is provided at B/L for positive isolation.
Use of VHP steam in the unit is mainly as follows:
•
SHU Pre-heater (75-E-04)
•
Splitter Reboiler (75-E-05)
•
Stabiliser Reboiler (75-E-13)
4.1.10 FUEL GAS SYSTEM
Fuel Gas is received in Fuel gas Knock-out drum (75-V-16) and from KOD
FG is distributed to various users. The FG receiving header is of 3” size and it is
provided with double block valve and spectacle blind at B/L. FI/FQ-2201 with
FAH/FAL is provided in DCS to indicate FG consumption.
Fuel Gas is used in the following points of the unit:
• HDS Reactor Feed Heater (75-F-01)
• In Amine Blow-down Drum (75-D-18)
4.2
EFFLUENT SYSTEM
Liquid and gaseous effluents are generated in the plant. These effluents are
disposed off the plant to a safe location.
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1. Sour water from 75-V-03 separator drum
About 5100 kg/hr during water injection in 75-A-03 for salt removal.
NIT CASE
AM CASE
BH
Flow rate kg/hr
5100
5100
NA
HC content wt ppm
300
300
NA
Dissolved H2S wt 600
320
NA
40
NA
75-V-03
ppm
Temperature, C
40
2. Sour water from HDS stabilizer reflux drum 75-V-05
This stream is less than 20 kg/hr during normal operations.
75-V-05
NIT CASE
AM CASE
BH CASE
Flow rate, kg/hr
10
11
NA
HC content wt ppm
200
200
NA
2100
NA
40
NA
Dissolved H2S wt 2260
ppm
Temperature, C
40
3. Gas purge from splitter reflux drum 75-V-02
Continuous service for light ends removal: 537 to 905 kg/hr, 400C at operating
temperature.
4. Gas purge from HDS reaction section
In NIT case, the Amine absorber is bypassed and the purge gas (216 kg/hr) is
routed to sour purge gas.
In AM case, the amine absorber is in service and the purge gas (56 kg/hr) is
routed to sweet purge gas.
5. Gas purge from HDS stripper reflux drum 75-V-05
This stream exist during normal operation and is sent to the sour purge for
treatment. This stream is sour (about 11.2 to 12.4 %mol).
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Continuous sevice for light ends and H2S removal: about 428 to 855 kg/hr, 400C
at operating temperature.
6. Regeneration gas purge to atmosphere
During PRIMEG+ reactors catalyst in situ regeneration operation, waste vapour
stream is routed to 75-F-01 heater stack at safe location under pressure control.
This waste vapour stream contains, during burning and polish burning phases:
Coke burning Phase
Effluent
CO2
H2O
Duration
Kg/hr
Kg/hr
days
75-R-01
83
4495
7
75-R-02
241
12048
1
Polish burning phase
Effluent
SO2
SO3
H2O
Duration
Kg/hr
Kg/hr
Kg/hr
days
75-R-01
599
15
2485
9
75-R-02
1206
31
5992
1.5
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SECTION- 5 PREPARATION FOR START-UP
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5.1
Doc No. Draft
Rev. A
Page 65 of 195
GENERAL
As the new unit nears completion, there is a large amount of preparatory
work, which should be performed by the operating crew. A planned check of the
unit will not only set the foundation of a smooth start-up, but will also provide a
firm basis for acquainting operators with the equipment. Start-up is a critical
period and the operator must know exactly the operation of each equipment.
Some of the pre-commissioning works can be carried out simultaneously
along with construction. But, care in the organisation of this work is necessary so
that it does not interfere in the construction activities. It is most important to plan
schedule and record with checklists and test schedules all the preliminary
operation and to co-ordinate the constructions programme.
5.2
PRE-COMMISSIONING ACTIVITIES
The material in this section gives general guidelines for preparing a unit for
start-up. Some sections need to be expanded to give specific directions (water
flushing procedure, inerting procedure for example); this is prepared by
commissioning personnel prior to start of the pre-commissioning/start-up.
5.2.1
INSPECTION / CHECKING
Sections of the unit should be checked out as soon as the contractor
completes work in those areas. Immediately followed by inspection of those
areas, punch lists which indicate the deviations from the design specifications
should be written and distributed to the contractor. In this manner mistakes in
construction can be found and corrected early.
Inspection of the plant can be basically divided into the following areas:
• Vessels
• Piping
• Heaters
• Exchangers
• Pumps
• Instrumentation
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5.2.2
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INSPECTION OF EQUIPMENTS
Inspection of the interior of the vessels, columns, heaters and other
equipment normally accessible during operation should be made to ensure that
they are complete, clean and correctly installed. Tray assemblies in columns
should be checked with reference to the engineering drawings to detect any
defect in assembly or construction and to ensure cleanliness. Packing if any to be
done after internal inspection and flushing. The vessels are to be checked with
reference to engineering drawings. The demister is to be fitted after internal
cleaning and water washing.
In heaters, the burner assemblies should be checked for easy operation of
air registers, contour of the burner throat, debris material etc. The heater coils
supports to be checked for proper installation.
Checklist formats are attached as Annexure
5.2.3
PIPING AND ACCESSORIES
Piping and accessories will be checked against drawings and specifications.
Piping support and hangers will be inspected to ensure that all anchorage’s are
firm. Valves will be checked for proper packing and mounting direction and
accessibility for operation and maintenance. Spring supports, if any, to be
checked for the cold setting and later for hot settings while plants is in operation.
5.2.4
INSTRUMENTS
All instrument tapings for pressure, level and flow should be clear and
Thermowells should not foul with the internals. These should be checked prior to
box up of the equipment.
Instruments will be checked, starting from the controller and proceeding
logically through the control loop. Cascade control system will be checked from
the impulse point of primary loop. Operating crew should check proper mounting
of control valves. Control valves responses should be checked for controller
outputs. The shutdown systems of the equipment and machinery will be checked
by simulating the various conditions in the control circuits.
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5.2.5
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RELIEF VALVES
Relief valves will be set in the shop and mounted before the system
pressure test. Block valves ahead and after relief valves will be checked for lock
open or lock close position as per P&ID. Relief valves will be checked against
specifications.
5.2.6
ROTARY EQUIPMENT
All rotary equipment such as pumps, fans etc. are to be checked for
bearings, internals and free movement. The auxiliaries, control systems on this
equipment should be thoroughly inspected.
5.2.7
DRAINAGE SYSTEM
Check the OWS and blow down system against drawings. Check for free
flow.
5.3
PREPARATION FOR PRE-COMMISSIONING
¾ Check the unit for completion of mechanical work against P&ID.
¾ Check list points are liquidated. Any pending point will not affect precommissioning operation.
¾ Remove all construction debris lying around in the unit and clean up the area.
¾ Install blinds as per master blind list.
¾ Safety valves should be kept blinded during flushing and re-installed
afterwards.
¾ These should be shop tested and set at the stipulated values.
¾ Ensure that underground sewerage system is in working condition. Clear
plugging, if any. Check by flushing with water.
¾ Check that communication between units, control room, offsite and utilities are
complete and in working condition.
¾ Ensure that the required lube oil, grease and other consumable are available
in the unit.
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5.4
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PRE-COMMISSIONING
Prior to the commissioning of the plant there are several pre-commissioning
operations that must be conducted to prepare the plant for the actual start-up
these are:
1. Commissioning of utilities
2. Final inspection of vessels
3. Pressure test equipment
4. Wash out lines and equipment
5. Functional test of rotating equipment
6. Instruments checking
7. Safety device checking
8. Heater Refractory dry-out
9. Purge and gas blanketing
10. Tightness test
11. Catalyst loading procedure
12. Charging of chemicals
It is important that these operations be carried out as thoroughly and as well
as possible to help achieve a smooth and trouble-free start-up and later steady
normal operation. A discussion detailing the major items to monitor in each of
these operations follows.
The above outline may be expanded somewhat as follows:
5.4.1
COMMISSIONING OF UTILITIES
The various utility lines should be tested and placed into service as soon as
the construction schedule allows. Pressure tests should be carried out on all
steam condensate, air, fuel gas, flare, and nitrogen lines as are done on all
process lines.
a) Steam Network
Network is blown through completely from battery limit with a strong steam
flow in order to clean the lines. The following steps are recommended:
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¾ Check network, all equipment will be disconnected to avoid entry of flushed
material.
¾ Drain all the low points. If necessary open steam trap inlet flanges.
¾ Open slowly battery limit valve and let the temperature rise in the header,
slowly and steadily.
¾ Check support of fixed points and expansion loops.
¾ When line is hot, blow it through completely with a strong steam flow.
¾ Close battery limit valves and prepare another network. When the blowing are
satisfactory, reconnect all equipment and remount steam traps. Recharge
header as above.
¾ To gauge the effectiveness of the steam blowing (and the amount of scale left
in the lines), target plates should be installed at the blow-down points. The
lines should be repeatedly blown down until virtually unmarked target plates
are obtained.
Condensate lines should be continually checked and traps
removed and cleaned if plugged.
Note: The following precautions to be taken while blowing / commissioning steam
header.
¾ To drain the low points of the lines before and during heating period in order
to avoid water accumulation, that causes hammering.
¾ To open drain / vent during cooling period to prevent vacuum formation
¾ To isolate the instruments, remove orifice plates and control valves; to reinstall the orifice plates and control valves after blowing is over.
b) Sea Cooling Water and Service Water:
Network shall be cleaned from battery limit with a strong water flow.
All
equipment will be disconnected at the inlet and reconnected when lines are
cleaned. Control valves and orifice plates will be removed and re-installed, after
the lines become clean. When system has been flushed, charge the lines to the
operating pressure.
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The following precautions to be taken:
¾ To open vents at high points in order to expel air from equipment and piping
¾ To open the battery limit valve, slowly and steadily.
c) Instrument Air and Plant Air:
Network shall be blown through completely from battery limit with strong flow
of air in order to clean and dry the lines. All joints and connections shall be
checked for tightness with soap solution. Header and branch lines will be blown
through with a high flow rate of air. During all tests, the instruments and control
valve shall be carefully isolated from the system.
d) Fuel Gas Networks:
Networks shall be blown through from battery limit with a strong airflow in
order to clean the lines. During the operations, orifice plates and control valves
shall be removed. Special care shall be taken to prevent water from entering the
furnace. The fuel oil and fuel gas headers will be commissioned before firing the
Heaters.
5.4.2
FINAL INSPECTION OF VESSELS
All vessels should be inspected before final closing and any loose scale,
dirt, etc. should be removed. Any line coming directly off of the bottom of a dirty
vessel should be removed.
It is very important that the internals of the hydro-treating reactor be
inspected very carefully. The hydro treating reactor internals should be checked
for holes and/or damage and repaired as required. The catalyst support basket
and unloading sleeve should be checked to ensure correct fit in the nozzles.
The separator should be checked carefully to be sure the cement lining is
installed well and that the mesh blanket is securely fastened to the support ring.
There should be no gaps in the mesh blanket.
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5.4.3
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Page 71 of 195
PRESSURE TEST EQUIPMENT
¾ It is normally the mechanical contractor’s responsibility to hydrostatically
pressure test the unit during construction. The following suggestions are
generally made by Licenser to help during the stage of start up activity.
¾ Before any vessel is filled with water, the foundation design must be checked
to see if it is rated for this load.
¾ Screens should be placed in the lines before the unit is pressure tested so
that test water can be pumped through the lines for the purpose of washing
them.
¾ Screens should be placed in a flange between the suction valve and the pump
so that the screen may be removed without de-pressuring any vessels. The
flow through the screen should preferably be downward or horizontal.
¾ Precautions should be taken to place the screen in a location where the dirt
particles will not drop into an inaccessible place in the line when the flow
through the pump stops. If this should happen, it would not be possible to
remove the dirt upon removal of the screen.
¾ An air pressure test can be placed on the sections of the unit prior to a water
test so that any open lines or flanges may be discovered and taken care of
before liquid is admitted. It would be remembered that in pressure testing
vessels, the test gauge should be placed at the bottom of the vessel so that
the liquid head will be taken into account. Before draining any liquid from a
vessel, a vent must be opened on top of the vessel to prevent a vacuum from
pulling in the vessel sides.
In pressure testing equipment, particularly in cold weather, care should be
taken that the testing of the vessels is not carried out at temperature levels so low
that the metal becomes brittle. As metal temperatures decrease, the tending for
brittleness increases. Temperatures above 17°C (60°F) are considered
satisfactory for testing to eliminate the possibility of cold fracturing of equipment.
Such temperatures can be attained by warming the testing medium.
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It will not be practical to test all of the equipment together. Thus, the unit will
be divided into sections as governed by the location of the various items of
equipment and the test pressures to which each item will be subjected. Suitable
blanks must be made up for insertion on nozzles and between flanges to isolate
the various sections of equipment as required.
Normally, the exchangers,
receivers, etc., for the various towers will be tested together with the main
vessels. Test pressures will be determined from the pressure vessel summary
for the unit. During pressure testing, all safety valves must be blinded off since
their normal relieving pressure will be exceeded.
It may be convenient to test the heaters and reactors in one group. A field
hydrostatic test on the gas compressor after installation could result in damage to
the internals, so the compressors must be isolated from the reactor system. As
the heaters are normally tested at a higher pressure than the reactors, it would be
simplest to blind off the heaters and test them first and then test the entire system
at the reactor test pressure. Blanks can be provided with connections for
introduction of water for testing and for venting of air as the system is filled with
water. It may be necessary to use Thermowells connections and pressure taps
for additional vents in the reactor system. At the completion of the hydrostatic
test, all water should be removed from the equipment. Where necessary, flanges
may be broken to drain low points and the equipment air blown to remove as
much water as possible before flanging up.
After hydrostatic pressure testing, a tightness test must be conducted to
check all flanges and fittings, especially the ones opened during hydro testing.
This final tightness test must be witnessed by Licenser representatives and is
normally done just prior to start-up.
5.4.4
WASH OUT LINES AND EQUIPMENT
After pressure test has been completed on any vessel with its connected
piping, receivers, exchangers, etc., required blanks are pulled and water is
circulated for the purpose of removing any dirt, scale, etc. Much of the dirt is
picked up in the pump screens where it is taken from the system by removing
and cleaning the screen.
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All possible lines and pumps should be used during the washing procedure for
complete clearout of the system.
Of course, no water circulation should be
carried out in the gas sections of the unit. Temporary water connections should be
provided at convenient locations in the system for carrying out water flushing. The
following points should be remembered during water flushing.
¾ Low point drains and high point vents should be purged.
¾ All instrument connection should be isolated, orifice plates removed, control
valves isolated and by-passed. In case there is no bypass, remove control
valve and flush the line. The valve will be installed after clean water starts
coming out and further flushing may be continued.
¾ If there is any heat exchanger in the line, flushing should be done up to and
around the exchanger using by-pass line. It should be ensured that dirty water
from initial flushing does not get into the exchanger. Wherever bypasses are
not available, the flanged joints at the inlet of heat exchanger should be first
opened and the line flushed till clear water starts coming out. Then reconnect
flange and flush through the exchanger.
¾ At each opening of the flanged joints, a thin metallic sheet should be inserted
to prevent dirty water from entering the equipment or piping.
¾ The flow of water should preferably be from top to bottom for flushing of heat
exchanger coolers. The bottom flange of the equipment should be opened to
permit proper flushing.
¾ The flushing should be carried out with maximum possible flow of water till
clear water starts coming out.
¾ Vertical lines, which are long and rather big (say over 100-mm dia) should
preferably be flushed from top to bottom. This will ensure better flushing.
Filling the lines and releasing from bottom is also helpful. The rundown lines
can also be flushed conveniently from the unit to the respective tanks.
¾ It should be ensured in all flushing operation that design pressure of lines and
equipment is never exceeded. After flushing of lines and equipment, water
should be thoroughly drained from all low points. Lines and equipment
containing pockets of water should not be left idle for a long time; it is
preferable to dry these lines and equipment with air after water flushing.
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Recommended air/water velocity during flushing or blowing to be
maintained for proper flushing
5.4.5
FUNCTIONAL TEST OF ROTATING EQUIPMENT
All rotary equipment (including dosing pumps) will undergo functional test to
check their performance.
a) Motors
Each motor should be checked and started to ensure that it has the correct
direction of rotation. The motor speed should be checked with tachometer to
ensure that RPM is correct. The manufacturer's lubrication schedule should be
used to ensure that all lubrication points have been serviced. After a short run
each bearing should be felt to ensure that it is free and not overheated.
b) Pumps
Prior to unit start up, all centrifugal pumps should be thoroughly checked and
run in properly (after pressure testing and water flushing) as indicated in the
following outline: The pumps will be started and operated according to the
manufacturer’s instructions.
CAUTION: Many high head pumps are not designed to pump water. To do
so can result in damage to the pump internals.
Check the vendor’s
specifications before attempting to run in pumps with water.
¾ Check to see that all necessary water piping has been made to stuffing boxes,
bearing jackets, pedestals and quench glands. Make sure that all necessary
lube oil piping is installed, and that this piping is not mistakenly connected to
the water system.
¾ Check arrangements to vent the pump for priming if the pump is not selfventing. See that special connections such as bleeds and drains are properly
installed.
¾ Check strainers in pump suction lines. Strainers must be installed before
aligning pumps. A 4-mm (three to five mesh) strainer is provided for each
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pump suction line during start-up. To avoid pump damage during flushing
with water, the strainers should temporarily be lined with 1-mm (20-mesh)
screen.
¾ Remove this screen after water flushing is completed. All strainers should be
flagged, and a list similar to the blind list should be kept, so as to prevent a
“lost” screen from plugging and upsetting unit operation later on.
¾ Check that power is available for running in the pump. Check that pressure
gauges and any special instrumentation are in working order.
¾ Water circulation on motor driven hydrocarbon pumps can result in motor
overloading if the full pumping capacity is used. In this type of equipment, the
capacity must be reduced by throttling the discharge during such periods. An
ammeter can be used to determine the required throttling.
¾ Before lubricating oil-lubricated bearings, check bearing chamber in pumps to
see that no flushing compounds or shipping grease is left in the chamber.
¾ Mechanical-type pumps should be flushed with water prior to pump operation
so no dirt gets into the seal and scores the seal faces.
¾ It is extremely important that the proper type and viscosity oil and proper
grade of grease is used to lubricate the equipment. Refer to manufacturer’s
instructions and lubricating schedule for this information.
¾ Motor should be checked and started to ensure that it has the correct direction
of rotation. The motor speed should be checked with tachometer to ensure
that RPM is correct. The manufacturer's lubrication schedule should be used
to ensure that all lubrication points have been serviced. After a short run each
bearing should be felt to ensure that it is free and not overheated.
¾ See that the driver rotates the pump in the direction indicated by the arrow on
the pump casing. Rotate the pump by hand to see that it is clear before
starting.
¾ Couple up and align the pumps, then check for cooling water availability and
start flow of cooling water to the pumps requiring external cooling, before they
are run in.
¾ Open pump suction valve and close discharge valve (crack discharge valve
for high capacity, high head pumps). Make sure the pump is full of liquid.
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¾ Start the pump. As the pump is motor driven, the pump will come up to
speed.
Immediately check discharge pressure gauge.
shown, stop the pump and find the cause.
If no pressure is
If the discharge pressure is
satisfactory, slowly open the discharge valve and give the desired flow rate.
Check the amperage of the motor. Do not run the pump with the discharge
block valve closed except for a very short time. Note any unusual vibration or
operation condition.
¾ Check bearings of pumps and drivers for signs of heating. Recheck all oil
levels.
¾ Run the pump for approximately one hour, then shut off to make any
adjustment necessary and check parts for tightness. Since it is not possible
to run the pump at operating temperature, a final check of alignment must be
made during normal operation by switching to the spare pump.
¾ Start the pump and run it for at least four hours.
¾ Shut the pump down and pull the strainer. Clean the strainer and replace it in
the suction line. Remove the temporary fine mesh liner from the strainer after
water flushing is complete.
¾ On a new unit, the screens are sometimes left in service for the first run on all
locations where spare pumps have been provided.
¾ When water is used for pressure testing and washing, it is sometimes better
to have packing in the pumps for a seal to prevent dirt from ruining the
mechanical seal.
After the lines and equipment are judged to be clean and all the pumps have
been run in, the water should be drained from the various systems.
Lines
containing low spots should be broken at the low spot if no drain is provided.
Underground lines, without drains, should be blown free of water.
Before
draining any vessel, a vent must be opened on that vessel so that a vacuum will
not be created on draining. If the towers are to be left standing for a long period
of time before steam drying or before operation, an inert gas, such as nitrogen or
sweet fuel gas, must be introduced to the vessels to prevent rusting of the
internals from oxygen in the air.
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Of course, no water circulation should be carried out through the gas
compressors.
It is important that the catalyst and the compressors are not
exposed to excessive moisture.
5.5
INSTRUMENTS CHECKING
Normally, instrument lead lines will be tested hydrostatically up to block
valves when the balance of the unit is tested. Hydrostatic test pressure will not be
made on instruments, which normally handle gas, and no pressure-measuring
element should be subjected to test pressures above its range. Also, never pull a
vacuum on a pressure instrument or gauge unless it is specifically designed for it.
All instrument air piping should be tested at 7kg/cm2g (100 psig) with compressed
air. Soap should be used on all joints to check for leakage. Care should be
taken to ensure that this high air pressure is not put on any instruments or control
valve diaphragms. Likewise, when pressure testing the unit, care must be taken
that the fuel gas pressure balance valves are blinded off to keep high pressure off
the diaphragm.
calibrated.
Before starting up, all instruments should be serviced and
This includes carefully measuring all orifice plate bores with a
micrometer.
A) Prior to unit start-up, all instruments must have been checked with regard to:
•
Proper tagging,
•
Proper location in the process,
•
Correctness of assembly,
•
Operating range consistent with the operating conditions,
•
Calibration,
•
Flow orifice size, coefficients, orientation versus flow,
•
Level instruments will be calibrated using the design liquid density,
•
Instrument wiring integrity, polarity, and grounding.
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B) The following guidelines may be adopted for checking and calibration of all
instruments.
a) Orifice Plates
Before each orifice plate is installed the orifice taps should be blown clear.
The plate should be callipered to check if the correct size orifice plate is installed.
The plate should then be installed after checking for the correct direction.
b) Differential pressure Transmitters and Receivers
Ordinarily these should be calibrated locally against a manometer. The
calibration should be checked at the receiver, which may be board or locally
mounted recorder or indicator.
c) Pressure Transmitters and Receivers
These should be checked in place. The calibration of the receiver should be
checked at the same time.
d) Alarms checking
All alarms, auto start and cut off systems should be checked by simulating the
conditions. Make sure that the field instruments actuate the corresponding light or
audible alarm in the control room or DCS printer.
e) Valves
The control valves are removed during washing operations. They should be
checked for cleanness of the seats and free movement of the plug or ball.
Check the valves motion and their response to the controller signal.
When all the single instruments have been individually checked, when all
their addresses have been verified in the DCS, then the loop checking can take
place for each loop or group of control loops.
5.6
SAFETY DEVICES CHECK
All the safety devices, Interlock(s) and Emergency shutdown devices must
be checked. These devices are designed either to protect the catalyst against
mal-operation or to fulfil safety actions.
Safety sequences (Interlocks) are sequences of actions programmed into
the DCS/PLC and designed to ensure automatically a safe sequence of operation
when selected undesirable events occur.
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5.7
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HEATER REFRACTORY DRY-OUT AND REACTION SECTION DRY-OUT
The furnace refractory must be thoroughly dried out so that it does not crack
when the Heater is brought into operation. The drying should be done by gradual
heating of the refractory so that no cracking takes place due to sudden
vaporisation of moisture from the refractory.
The refractory drying out of reactor feed heater can be done simultaneously with
the drying of the reaction section. Drying out can be done under air or nitrogen,
depending on the availability, using the recycle compressor.
Detail procedure is given in Annexure-I
5.8
PURGING AND GAS BLANKETING
It must be remembered that oil or flammable gas should never be charged
into process lines or vessels indiscriminately. The unit must be purged before
admitting hydrocarbons. There are many ways to purge the unit and ambient
conditions may dictate the procedure to be followed: nitrogen or inert gas
purging, displacement of air by liquid filling followed by gas blanketing, or
steaming followed by gas blanketing.
For the remainder of the unit other than the reactor section, steam purging
followed by fuel gas blanketing can be used to air free the unit. The following
steps will briefly outline this method.Potential problems or hazards could develop
during the steam purge are as follows:
Collapse due to vacuum: some of the vessels are not designed for vacuum.
This equipment must not be allowed to stand blocked in with steam since the
condensation of the steam will develop a vacuum. Thus, the vessel must be
vented during steaming and immediately followed up with fuel gas purge at the
conclusion of the steam out.
Flange and gasket leaks: thermal expansion and stress during warm-up of
equipment along with dirty flange faces can cause small leaks at flanges and
gasket joints. These must be corrected at this time.
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Water hammering care must be taken to prevent ‘water hammering” when
steam purging the unit.
Severe equipment damage can result from water
hammering. Block in the cooling water to all coolers and condensers.
Shutdown fans on fin-fan coolers and condensers. Open high point vents
and low point drains on the vessels to be steam purge.
Start introducing steam into the bottom of the columns, towers, and at low
points of the various vessels. It may be necessary to make up additional steam
connections to properly purge some piping which may be “dead-ended.”
Thoroughly purge all equipment and associated piping of air. Be sure to
pen sufficient drains to drain condensate, which will accumulate in low spots and
receivers.
When purging is completed, close all vents and drains. Start introducing
fuel gas into all vessels and cut back the steam flow until it is stopped completely
when the systems are pressured. Regulate the fuel gas flow and the reduction of
steam so that a vacuum due to condensing steam is not created in any vessel or
that the fuel gas system pressure is not appreciably reduced.
5.9
TIGHTNESS TEST
The guideline given below is to check the tightness of flanges, joints,
manholes etc. (except pumps and control instruments) in the unit.
The initial leak tests can be performed using air or nitrogen depending upon local
facilities. The test pressure will be the air or nitrogen system pressure or the unit (or
section of unit) design pressure, whichever is the lower. This operation can be
integrated with steam purging activity aimed at expelling air (from feed, and Product
section) prior to introducing hydrocarbon into the unit.
¾ The unit is isolated with blinds from adjacent sections containing hydrocarbons
(liquid or gaseous), and from utilities systems where pressure is lower than air
(or nitrogen) pressure.
¾ The pressure rise must be checked on several pressure gauges and possibly
checked on a pressure recorder.
Leaks must be carefully located and
tightened. Their location must be recorded. The leak test is satisfactory
when the pressure decrease is lower than 0.05 Kg/cm2/hour over a period
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of 4 consecutive hours (at approximately constant temperature). Pumps,
compressors are to be isolated to prevent leak through seals.
¾ The air (nitrogen) used for leak tests should be purged out of the unit using low
points drains to remove free water, if any.
In case of steam of steam purging:
¾ Drains at low points will be opened; after draining is over, these will be closed.
Vent will be opened; pressure gauges will be installed on each circuit.
¾ Steam is progressively admitted where connections are available.
Circuits,
which do not have direct admission of steam, will be supplied through hoses.
¾ The temperature of the whole installation is increased slowly and free expansion
of lines is checked. The condensed water is drained while the temperature of the
circuit rises.
¾ When temperature is steady, vents are progressively closed in order to get the
desired pressure by keeping a vent slightly opened. A steam make-up is
maintained. All joints will be checked for leaks. If leaks are detected, system will
be depressurised, leaks attended and the system retested.
For the purpose of leak tests the unit will be divided into sections of
approximately the same design pressure.
Air or nitrogen will be injected at
different locations depending on check valves locations.
Recommended sections for leak tests:
A) Feed section
•
Feed filters 75-X-01 A/B
•
Feed drum 75-V-01
•
This section will be isolated from the other sections by blinds and/or valves.
B) Selective hydrogenation reaction section
•
SHU feed/HDS effluent heat exchanger 75-E-01
•
SHU feed/effluent heat exchanger 75-E-02 (tube and shell sides)
•
SHU preheater 75-E-03
•
Hydrogen from isomerization make-up compressor discharge
Template No. 5-0000-0001-T2 Rev A
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•
Feed exchangers bypass lines
•
Selective hydrogenation reactor 75-R-01
•
The selective hydrogenation reaction section is isolated from the other
sections by blinds and/or valves.
C) Splitter section
•
Gasoline Splitter 75-C-01
•
Splitter reboiler exchanger 75-E-07
•
Splitter overhead air condenser 75-A-01
•
Splitter post condenser 75-E-04
•
Splitter reflux drum 75-V-02
•
Light FCC gasoline trim cooler 75-E-05
•
FCC heart cut cooler 75-E-06
•
SHU recycle air cooler 75-A-04
D) HDS section
•
HDS Feed/Effluent exchangers 75-E-08 A/B/C (shell and tube sides).
•
HDS reactor 75-R-02
•
HDS reactor feed heater 75-F-01
•
SHU feed/HDS effluent exchanger 75-E-01 (shell side).
•
HDS effluent air condenser 75-A-03
•
HDS effluent trim condenser 75-E-09 A/B(shell side)
•
Separator drum 75-V-03
•
Amine K.O. drum 75-V-06
•
Amine absorber 75-C-02
•
Lean amine preheater 75-E-10 (shell side)
•
Recycle compressor K.O. drum 75-V-04
•
The HDS section shall be isolated from other sections by blinds or valves.
E) Stabilization section
•
Stabilizer feed/bottom exchanger 75-E-11 A/B (tube and shell sides)
•
Stabilizer column 75-C-03
•
Stabilizer overhead condenser 75-A-05
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•
Stabilizer reflux drum 75-V-05
•
Stabilizer reboiler 75-E-13
•
Heavy gasoline trim cooler 75-E-12 (shell side)
5.10
Doc No. Draft
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Page 83 of 195
CATALYST LOADING PROCEDURE
Detailed catalyst loading procedure is given in Annexure-II
5.11
CATALYST SPECIAL PROCEDURE
Detailed procedure is given in Annexure-III
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SECTION- 6 START-UP PROCEDURE
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6.1
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INTRODUCTION
Start up and Operating Procedure are described in this section. Start up
and shutdown are the most critical periods in operation.
It is then that the
hazardous possibilities for fire and explosion are greatest.
The hazards encountered most frequently in start up and shut down of units
are accidental mixing of air and hydrocarbons / hydrogen and contacting of water
with hot oil. Other hazards primarily associated with start up are pressure, vacuum
and thermal and mechanical shocks.
These can result in fires, explosions,
destructive pressure surges and other damages to unit as well as injury to
personnel.
Fires occur when oxygen and fuel vapour or mists are mixed in flammable
proportions and come in contact with an ignition. They may run out of control or
touch off devastating explosion. Pressure surge from unplanned mixing of water
and hot oil may cause damage of equipment and or loss of valuable production.
Extensive, costly down time on process unit may result. Fires usually follow if the
explosion bursts lines or vessels.
Preparation for start-up begins with a complete review of the start up
procedure by the operating crew.
Activities of Prime G+ unit should be co-
ordinated with control room, other units, and utility section.
6.2
PRE-START-UP CHECKLIST FOR PRIME G+ UNIT
a) Pre start-up checklist
Prior to actual start-up of the plant it should be established that all preparatory
works have been successfully completed and all equipment are ready to function.
Ensure that:
¾ Blinds are installed as per master blind list. Each removal and insertion of a blind
should be noted and installed by the operator- in-charge.
¾ All unnecessary blind are removed.
¾ All construction tolls, debris are removed. Plant is cleaned.
¾ All vessels, piping, equipment are pressure tested, flushed and ready for service.
¾ All rotating equipment such as pumps, compressors, motors etc. have
undergone functional test successfully.
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¾ All instruments have been checked, calibrated and ready for service. Control
should be on manual.
¾ All safety valves are in position after setting and testing. Isolating valves will be
left in lock open position. Spare valves should be kept isolated.
¾ Necessary utility headers (cooling water, steam, air, fuel gas, fuel oil, water etc)
are charged.
¾ Flare, closed blow down and sewer systems are in operable condition.
¾ All related units are informed of the start-up plan.
¾ All other pre-commissioning activities such as flushing, cleaning, purging,
tightness testing etc are completed.
¾ Fire and safety related equipment are checked.
¾ All safety devices and emergency sequences have been tested.
¾ General Service system such as lighting, PA, telephone etc is in working
condition.
¾ The proper quantity and quality of nitrogen is available.
¾ The unit is under a slight nitrogen pressure.
¾ The reaction section has been dried out.
¾ The feed, splitter and stabilizer sections have been thoroughly drained of free
water.
¾ Catalysts have been loaded into the reactors.
b) The unit is isolated with blinds:
•
On the feed and product lines,
•
On the flare and fuel gas headers,
•
On sour water lines to battery limits,
•
On the sewer lines and utilities except cooling water and nitrogen,
•
On pressure relief valves to flare.
•
On amine supply and return lines
•
H2 make-up lines are isolated.
•
Gasoline feed is available.
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c) Inert naphtha is available with the following characteristics:
6.3
•
Bromine number < 5 g Br/100 g.
•
Diene Value< 0.5
•
Specific gravity between 0.725 and 0.850
•
ASTM D86 5%vol between 5°C and 70°C
•
ASTM D86 95%vol between 145°C and 225°C
•
Sulfur < 0.3 wt %
FIRST START-UP
The following describes the first start-up of a newly built unit. Any
subsequent start-up of the same unit may or may not include all of the following
steps, depending upon the status of the unit after the shutdown. For instance,
catalyst sulfiding will not be required if the catalyst was not regenerated or
replaced.
6.3.1
CHRONOLOGY OF START-UP OPERATIONS
The chronology of the various start-up tasks is shown on the attached
schedule. The duration has shown are those required to perform the tasks. The
time gap between two consecutive operations has not been taken into
consideration.
6.3.2
PURGING OF AIR
a) General
The purpose of this step is to reduce the O2 content in all the sections below
0.2% by volume prior to the introduction of hydrogen or hydrocarbons.
The air can be eliminated by two methods:
a) By repeated filling and pressuring the system with nitrogen and then releasing
the air enriched in nitrogen to atmosphere until the oxygen content reaches
the required minimum value. This method will be used in reaction section and
in compressor section where humidity has adverse effect on equipment or
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catalyst. The vacuum ejector installed in this section is used for decreasing
the number of purging and nitrogen refilling cycles.
b) By steam out and subsequent refilling the equipment with fuel gas. This
method will be used for all equipment where humidity and steam can not
deteriorate the equipment or catalyst.
Note: During steam out operation, Reaction section and Compressor
section are isolated with blinds and filled with nitrogen. It is recommended
to start filling with nitrogen on reaction section, SHU preheating section
including.
b) Purging of air in Reaction Section
This section involves the following equipment:
1. 75-R-01
Selective Hydrogenation reactor
2. 75-R-02
First HDS reactor
3. 75-E-02
SHU feed /effluent heat exchanger
4. 75-E-03
SHU feed pre heater
5. 75-E-08 A/B/C
HDS feed/effluent heat exchangers
6. 75-F-01
HDS reactor feed heater
7. 75-E-01
SHU Feed/HDS effluent exchanger (shell side)
8. 75-A-03
HDS effluent air condenser
9. 75-E-09
HDS effluent trim condenser
10. 75-V-03
Separator drum
11. 75-V-06
Amine K.O. Drum
12. 75-E-10
Lean amine preheater (shell side)
13. 75-C-02
Amine Absorber
14. 75-V-04
Recycle compressor K.O. Drum
¾ The ejector (75-J-01) is connected to the vapor outlet line from the separator
drum. Isolate Reaction section with valves and blinds from remaining sections
of the Unit.
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¾ Isolate selective hydrogenation reactor (75-R-01) from Splitter (75-C-01) and
from SHU feed/HDS effluent heat exchanger (75-E-1001) (tube) and
interconnected to HDS reaction section by start-up vacuum line.
¾ Ejector evacuation, nitrogen filling and pressuring are repeated until the
required oxygen concentration is reached (0.2% volume of O2)
¾ Usually, no more than 3 purging operations are necessary to obtain
satisfactory results.
¾ Recycle compressor must be isolated on suction and discharge lines. Purging
of compressor is usually done by repeated pressurizing with nitrogen and
releasing to atmosphere without use of vacuum which may affect the
compressor seals.
¾ Also pumps connected to reaction system such as the quench pumps 75-P-06
will be isolated by block valves.
¾ After air purge, the system is filled with nitrogen and kept under positive
pressure of 0.5 to 0.8 kg/cm² g until start-up and introduction of hydrogen.
c) Purging of air in Splitter and Stabiliser Sections
The purging of air by repeated pressuring with nitrogen and releasing to
atmosphere can be done but it is time consuming operation due to volume of
involved equipment and also the demand in nitrogen is very large.
The steam out operation is commonly used.
Feed and Splitter Section
This section involves the following equipment and interconnecting piping:
•
75-V-01
Feed surge drum
•
75-A-04
SHU recycle air cooler
•
75-C-01
Splitter
•
75-A-01
Splitter overhead air condenser
•
75-E-07
Splitter reboiler
•
75-V-02
Splitter reflux drum
•
75-A-06
Light gasoline air cooler
•
75-E-06
FCC heart cut cooler
Template No. 5-0000-0001-T2 Rev A
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•
75-E-05
Light FCC gasoline cooler
•
75-A-02
FCC heart cut air cooler
Doc No. Draft
Rev. A
Page 90 of 195
¾ This section is isolated from the SHU and HDS reaction section by valves
and/or blinds. Isolate Pumps from the section by the valves at suction and
discharge and purged separately by nitrogen pressurizing/ depressurizing.
Stabilizer section
This section involves the following equipment and interconnecting piping:
•
75-C-03
Stabilizer
•
75-E-13
Stabilizer Reboiler
•
75-A-05
Stabilizer overhead air condenser
•
75-E-14
Stabilizer overhead trim cooler
•
75-V-05
Stabilizer reflux drum
•
75-E-11 A/B
Stabilizer feed/bottom exchangers
•
75-A-07
Heavy gasoline air cooler
•
75-E-12
Heavy gasoline trim cooler
¾ Isolated this section from the HDS reaction section by valves and/or blinds
Isolate Pumps from the section by the valves at their suction and discharge
and purged separately by nitrogen pressurizing/ depressurizing.
¾ Eliminate air In the splitter and stabilizer sections by steam out and
subsequent filling with sweet fuel gas.
¾ The start-up steam hoses for LP steam should be connected to the maximum
points, usually on suction-discharge of pumps, vessel bottoms. All vents on
columns reflux drums and other high points of lines should be opened. The air
coolers should be shut-down and cooling water circulation through coolers
and condensers stopped.
¾ Introduced steam slowly to heat up slowly all parts of equipment/lines. Drain
the condensate at low points of piping and drums. The steam out operation
can be used for tightness test. This can be done by pressurizing the system
with steam and observing the flange connections to determine possible leaks.
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¾ The steam out operation for a period of 24 hours is usually sufficient to
eliminate air from the system. The steam out is followed by filling with fuel gas
or nitrogen. Ensure that fuel gas/Nitrogen is flowing without interruption and
positive pressure is maintained in all sections of the piping and equipment.
Note: Do not allow any part of the system to develop vacuum. This will
result in introduction of air and danger of explosion.
6.4
6.4.1
START-UP PRELIMINARY OPERATION
UNIT STATUS
¾
The feed and splitter sections are under nitrogen or fuel gas pressure but still
isolated from the reaction section by the block valves.
¾
The reaction sections are isolated and kept under nitrogen pressure.
¾
The stabilizer and splitter are under nitrogen pressure or fuel gas pressure,
isolated from reaction section.
¾
All blinds have been removed including those located on the start-up lines,
utilities, sewers, PSV's, etc.
¾
6.4.2
The feed control valve is closed and blocked by inlet and outlet valves.
INERT NAPHTHA CIRCULATION (REACTION SECTIONS BY-PASSED)
When starting-up the SHU and the HDS section, isolate the reaction section
and establish an oil circulation loop. This allows an efficient flushing of foreign
material from the equipment and liquid lines and a thorough checking of the
pumps, including standby's and instruments. Inert naphtha would be pumped
from storage, bypassing the reaction section to feed the splitter. See attached
block diagram.
a) Cold circulation in Splitter
¾ Put in service pressure control loop PIC-1601 on splitter reflux drum and
increase pressure in the system by introduction of nitrogen, set point as per
the Process Flow Diagram.
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¾ Start pumping inert naphtha from storage or from the upstream units and
establish a level in the feed drum (75-V-01).
¾ Put in operation the level control of the feed drum LIC-1102.
¾ When the level in the feed drum reaches 40%, start the feed pumps (75-P-01
A/B) and through the start-up lines that by pass the reactors, establish a level
in the splitter bottoms (75-C-01).
¾ When the level in the splitter reaches 40%, start the HDS feed pump 75-P-02
A/B and open the FV-1103 to recirculate the naphtha back to the feed surge
drum via SHU recycle line.
¾ Drain lines on low points to eliminate water and remove foreign materials from
lines and equipment.
¾ Provide cleaning of pumps strainers.
¾ During the circulation it is good practice to switch to the standby's to check out
both pumps.
b) Cold circulation in Stabilizer
The circulation of naphtha is recommended through Stabilizer in order to
provide flushing of the system and checking of pumps operation and instruments.
The circulation circuit should be established from HDS feed pumps (75-P-02A/B)
to the stabilizer (75-C-03) through the filling line and then back to the feed drum
via the recirculation line.
¾ Close the block valves routing the naphtha to 75-E-01 and UV-1901 with its
block valve to 75-E-08, at the same time open the startup filling line valves.
¾ When the level is established in stabilizer reflux drum (75-V-05) at around
50% start the stabilizer reflux pump (75-P-09 A/B) and start filling the
stabilizer (75-C-03).
¾ Let the stabilizer pressure floating at flare pressure
¾ Admit more inert naphtha into the unit to make the level in the stabilizer
bottoms reach 40%.
¾ When the bottoms level has reached 40%, start to recirculate the naphtha
back to the feed drum via the recirculation line.
¾ Stop the inert naphtha feed to the feed surge drum.
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¾ Adjust the circulation at a rate of 60% of design throughput.
¾ Drain lines on low points to eliminate water and to remove foreign matters
from lines and equipment. Provide cleaning of pump strainers.
Note:
1. During the circulation it is good practice to switch to the standby's to
check out both pumps.
2. During the circulation minimum flow line of pumps must be kept in line.
Start-up
Naphtha
X-01
V-01
A
a
P-01A/B
V-02
b
c
P-03A/B
e
d
C-01
f
h
m
P-02A/B
g
V-05
n
E-11A/B
E-12A/B
Template No. 5-0000-0001-T2 Rev A
l
P-07A/B
k
C-03
i
J
P-09A/B
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Naphtha feed :10”-P-75-1101-A9A-IH
A
10”-P-75-1110-A9A-IH
g)
6”-P-75-2414-B9A
a)
10”-P-75-1104-A9A-IH
h)
6”-P-75-1807-B9A-IH
b)
6”-P-75-1210-D9A-IS
i)
4”-P-75-3105-A16A
c)
10”-P-75-1602-A9A
j)
3”-P-75-3107-A16A
d)
6”-P-75-1209-B9A-IS
k)
8”-P-75-3002-A9A-IH
e)
8”-P-75-1605-A9A
l)
8”-P-75-3004-B9A-IH
f)
10”-P-75-1506-A9A-IH
m)
6”-P-75-2912-A9A
n)
6”-P-75-1908-B9A
Schematic Naphtha circulation circuit is given in the attachment
6.4.3
START-UP OF HOT NAPHTHA CIRCULATION IN SPLITTER AND STABILIZER
In order to prepare the unit for start-up with fresh feed it is recommended to put in
operation splitter and stabilizer.
This operation enables to commission instruments, air condensers, coolers and
Reboiler.
a) Splitter start-up at total reflux
¾ Commission Splitter overhead air condenser (75-A-01A~D)
¾ Start Splitter Reboiler (75-E-07)
¾ Do not increase the Reboiler outlet temperature too rapidly. Increase the
inventory temperature in the splitter very slowly so that trapped water, or
water that is emulsified in the start-up naphtha, has time to change state
(water to steam) in as controlled a manner as possible. It is recommended to
hold the Reboiler outlet temperature at 150°C for some time.
¾ Increase Splitter’s bottom temperature at a rate of 30°C per hour up to 180°C
to 200°C, depending on distillation range of used inert naphtha and operating
pressure.
¾ Commission temperature control loop TIC-1501.
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¾ As soon as the level in the reflux drum is established, start the reflux pumps
(75-P-03 A/B) and commission level and flow instruments on the reflux line,
(LIC-1601 and FIC-1601 respectively). The light FCC gasoline draw off and
the FCC heart cut draw off are closed.
¾ The splitter is left operating at total reflux for several hours as necessary to
commission all involved equipments and instruments.
¾ The pressure in the reflux drum must be kept at constant value by injecting N2
at the reflux drum if necessary.
¾ Shutdown the splitter Reboiler heater while keeping circulation until the
temperature decreases in the splitter column bottom to 50°C. Splitter should
be kept under pressure with nitrogen.
b) Stabilizer at total reflux
¾ Put in service pressure control loop PIC-3101 on stabilizer reflux drum.
¾ Commission the overhead air condenser 75-A-05 and overhead trim cooler
75-E-14 with set point as per the Process Flow Diagram. Pressurize with
nitrogen.
¾ Start stabilizer Reboiler (75-E-13)
¾ Do not increase the Reboiler outlet temperature too rapidly. Increase the
inventory temperature in the stabilizer very slowly so that trapped water, or
water that is emulsified in the start-up naphtha, has time to change state
(water to steam) in as controlled a manner as possible. It is recommended to
hold the Reboiler outlet temperature at 150°C for some time.
¾ Increase temperature on stabilizer bottom at a rate of 30°C per hour up to
150°C to 180°C depending on distillation range of used inert naphtha and
actual operating pressure in the column.
¾ As soon as the level is established in Stabilizer reflux drum (75-V-05), start
the Stabilizer reflux pumps (75-P-09 A/B) and commission level and flow
instruments on the reflux line (LIC-3102 and FIC-3001).
¾ Keep constant the pressure in the stabilizer by admission of nitrogen.
¾ Adjust a make up of inert naphtha coming from the splitter to fill the stabilizer
bottoms and the stabilizer reflux drum at 60 % of the design throughput.
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¾ The stabilizer (now isolated from the splitter) is left operating at total reflux for
several hours as necessary to commission all involved equipments and
instruments.
¾ Shutdown the stabilizer heater while keeping circulation until the temperature
decreases in the stabilizer column bottom to 50°C. Stabilizer should be kept
under pressure with nitrogen.
6.5
PRESSURIZATION OF THE REACTION SECTIONS AND HYDROGEN
LEAK TESTS
6.5.1
UNIT STATUS
The reaction sections are still under nitrogen pressure. Selective
hydrogenation and HDS reaction sections have to be filled with hydrogen. The
selective hydrogenation reactor (75-R-01) is isolated from naphtha circuit by
block valves on the feed valve FV-1201 and on the reactor outlet PV-1501 and
PV 1401.
− HDS feed/effluent heat exchangers (75-E-08 A~C),
− First HDS reactor (75-R-02),
− HDS Reactor feed Heater (75-F-01),
− Air condenser (75-A-03 A/B),
− Trim cooler (75-E-09 A/B),
− Separator drum (75-V-03),
− Amine absorber (75-C-02),
− Amine Preheater (75-E-10),
− Recycle compressors KO drum (75-V-04) and
− Recycle compressors (75-K-01 A/B)
are isolated from naphtha circuit and stabilizer by the following block valves
-
Feed valve FV 1901, and UV-1901
-
On UV 2401 and block valves of FV 2402
-
and H2 make-up line to 75-V-04 Recycle compressor KO drum (on FV-2701 &
FV-2702).
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6.5.2
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H2 INRODUCTION IN SHU SECTION
¾ Gradually introduced H2 through the H2 makeup line to 75-E-01.
¾ Increased the pressure up to 7 Kg/cm2/g.
¾ Carry out the leak test at this pressure on all flange joints, couplings, valves.
The test duration is minimum 4 hours. The checking of tightness should be
checked with explosive meter. The pressure drop should not exceed 0.05
Kg/cm2/h.
6.5.3
H2 INRODUCTION IN HDS SECTION
¾ Gradually introduced H2 through the make-up hydrogen line to Recycle
compressors KO drum (75-V-04) (by-pass of recycle compressor 75-K-01 A/B
should be opened), and then to other lines and equipment involved in the
HDS reaction section.
¾ Increased the pressure up to 7 Kg/cm2/g at the first step.
¾ Carry out the leak test at this pressure on all flange joints, couplings, valves.
The test duration is minimum 4 hours. The checking of tightness should be
checked with explosive meter. The pressure drop should not exceed 0.05
Kg/cm2/h.
¾ Once all leaks have been tightened, resume hydrogen injection and
pressurize up to the normal operating pressure.
¾ Perform a final leak test (two hours).
¾ Commission the reaction section pressure controller PIC-2409.
¾ Close the by-pass of 75-K-01 A/B.
¾ Start the recycle compressor 75-K-01A/B and circulate hydrogen through the
reaction section.
6.6
CATALYST SULFIDING – DRY SULPHIDING
The metals of the catalysts HR-845, HR 806, as delivered are in the oxide
form. As the active catalytic component is the metal sulfide, the catalysts must
therefore be sulfided. DMDS, which thermally decomposes into H2S, is used for
this purpose.
Template No. 5-0000-0001-T2 Rev A
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VRCFP, HPCL VISAKH
Doc No. Draft
Rev. A
Page 98 of 195
It is important that sulfiding of the catalyst metal is complete. If not, the
catalyst metals convert to their reduced form (metal) which could lead to metal
sintering resulting in agglomeration and consequently poor activity due to a
decrease in metallic area. In addition, the reduced metals will act as
hydrocracking catalysts with the gasoline and could cause local overheating and
heavy coke deposits.
The sulfiding of HR-845 catalyst in the Diolefin Reactor, HDS catalyst in first
HDS reactor should be performed separately.
¾ Ensure there is adequate supply of DMDS for each catalyst, the facilities are
operational and the pump is calibrated. Remove the blind on the injection line
but keep blocked in.
¾ Both recycle gas compressors 75-K-01 A/B (one for SHU reactor) need to be
operated in order to get sufficient flow through catalytic bed.
6.6.1
SULFIDING OF HR-845 CATALYST IN THE DIOLEFIN REACTOR (75-R-01)
The sulfiding flow scheme for the SHU Reactor catalyst is:
Recycle compressor (75-K-01 A&B) → HDS feed / effluent exchangers
shell side → Heater (75-F-01) → SHU reactor (75-R-01) → HDS feed / effluent
exchangers tube side → HDS effluent air condenser (75-A-03)
→ HDS
effluent trim cooler (75-E-09)→ Separator drum (75-V-03)→ Recycle
compressor KO drum (75-V-04) → Recycle compressor (75-K-01 A&B).
¾ The recycle compressor is operating with Hydrogen at lower pressure than
the normal operating pressure.
¾ HP Amine Absorber (75-C-02), is isolated and its by-pass open.
6.6.2
SULFIDING OF HR-806 CATALYST OF FIRST HDS REACTOR (75-R-02)
Unit status is:
¾ The SHU Reactor (75-R-01) sulfiding is complete.
¾ The recycle gas compressor is operating with Hydrogen at normal operating
pressure.
¾ Amine Absorber, 75-C-02, is isolated and its by-pass open.
Template No. 5-0000-0001-T2 Rev A
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Doc No. Draft
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Page 99 of 195
The sulfiding flow scheme for the first HDS reactor catalyst is:
Recycle compressor 75-K-01 A&B → HDS feed / effluent exchangers
shell side → Heater 75-F-01 → First HDS reactor 75-R-02 → HDS feed /
effluent exchangers tube side → HDS effluent air condenser 75-A-03 →
HDS effluent trim cooler → Separator drum 75-V-03 → Recycle compressor
K.O. drum 75-V-04 → Recycle compressor 75-K-01 A&B.
6.6.3
SULPHIDING PROCEDURE
The sulphiding procedure is the same for both catalysts HR 845, HR 806 is as
described below:
¾ Ensure that 75-E-01 has not been filled by mal-operation with SR Naphtha
during cold circulation. Open the bypass of the exchanger and isolate it.
¾ Isolate and bypass of the Amine Absorber.
¾ Start recycle compressor to circulate hydrogen in the reaction section at
maximum flow rate.
¾ Fire the HDS reactor heater 75-F-01 and increase the reactor inlet
temperature up to 180°C at a rate of 30°C/h.
¾ Start the sulfiding agent injection at the inlet line of reactor (outlet of sulfiding
agent pump). Adjust the injection flow rate.
¾ Increase the reactor inlet temperature up to 220°C.
¾ Keep these conditions. After 3 hours at 220°C, check every hour at least the
H2S content of the recycle gas. Normally H2S appears after 3 to 5 hours
from the beginning of sulfiding agent injection.
¾ When the H2S breakthrough occurs (H2S > 0,2 % vol.) or after four hours at
220°C, whichever is the later, continue the sulfiding agent injection and
increase the reactor inlet temperature up to 315°C at a rate of 30°C/h.
¾ Hold this temperature for a minimum of 4 hours.
¾ During sulfurization:
− The reactor ∆T must not exceed 30°C.
Should it happen, decrease the
sulfiding agent injection.
Template No. 5-0000-0001-T2 Rev A
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Page 100 of 195
− From the actual recycle gas flow and the sulfiding agent injection, one can
calculate the H2S percent volume at reactor inlet which should be within 0.5%
to 1%. If required, adjust the sulfiding agent injection to match this range.
− The sulfurization reactions produce water and the amount of water recovered
in the separator confirms the progress of the sulfurization. Drain the separator
when necessary.
Note: Proceed with caution, since the water is saturated with H2S.
− The decomposition of sulfiding agent (DMDS), in addition to H2S, gives
butane which accumulates in the recycle gas. A purge of the reaction section
and a make-up of hydrogen could be necessary to keep the recycle gas
hydrogen purity above 50% volume.
¾ Stop the sulfiding agent injection when the required amount is reached.
However proceed to intermittent injections if the H2S content in the recycle
gas was to fall below 0.5% volume.
¾ Then:
− Check that the H2S contents inlet and outlet of the reactor are equal.
− Check that an injection of sulfiding agent results instantaneously in an
increase of the H2S content in the recycle gas.
¾ The catalyst sulfurization is then considered as completed.
Decrease the
reactor inlet temperature down to 100°C at a rate of 30°C/h.
¾ At 100°C, stop the HDS heater 75-F-01.
Remark:
During sulfiding operation, the recycle gas is highly toxic and
flammable owing to its H2S content. It must not be vented to atmosphere.
The operators must be equipped with H2S protective masks when checking
the H2S content. Access to the unit must be forbidden to non-operating
personnel.
Template No. 5-0000-0001-T2 Rev A
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6.7
6.7.1
Doc No. Draft
Rev. A
Page 101 of 195
UNIT START-UP
UNIT STATUS
¾ The sulfiding of the all the reactors is completed.
¾ The H2 recycle are flowing through the HDS Reactor.
¾ Recycle gas rate is set at 100% of design value.
¾ The Diolefin (SHU) Reactor is under hydrogen gas pressure.
¾ The Stabilizer is under N2 atmosphere.
¾ The Splitter is under N2 atmosphere.
¾ Filling up of the SHU reactor
The procedure is as followed:
1. Line up from SHU feed pumps (75-P-01 A/B) to SHU reactor (75-R-01) via 75E-01 tube side, 75-E-02 tube side, 75-E-03 tube side.
2. Open all valves and blind from 75-R-01 bottom up to PV-1404, which is kept
closed but can be operated if needed.
3. Open slowly safety valve PSV-1401 bypass located at top of 75-R-01 reactor.
This is to allow flaring of the gas while filling up the system.
4. Crack open the globe valve located on the bypass of FV-1201 and start filling
and pressurising the SHU preheating system and reactor. Proceed slowly in
order to soak efficiently the catalyst bed. (SHU reactor pressure should be
controlled at least 2 to 3 Kg/cm2 below the normal operating pressure in
order to avoid risk of overpressure during filling up).
5. When the pressure in the reactor reaches the pressure of the system, open
completely the bypass globe valve of the PSV-1401 in order to flare hydrogen
and complete the filling.
6. When the hissing of the gas escaping through the PSV-1401 bypass stops,
the filling of the reactor is over.
7. Close the bypass of the reactor PSV-1401, but keep the filling globe valve
slightly open to maintain the pressurisation with 75- P-01 A/B.
8. Maintain these conditions for 4 hours in order to soak the catalyst. Check and
confirm that no gas remains at the top of the reactor using the PSV-1401
bypass.
Template No. 5-0000-0001-T2 Rev A
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6.7.2
Doc No. Draft
Rev. A
Page 102 of 195
LINING UP OF THE SHU REACTION SECTION
¾ Commission the pressure controller, PIC-1501, at the outlet of reactor 75-R01. Put on auto at a setpoint.
¾ Pressurize the Splitter to 6 kg/cm2g using nitrogen and put PIC-1601 on auto
at a setpoint of 6.0 Kg/cm2g.
¾ Commission the Splitter Overhead Air Condenser (75-A-01A~D), Splitter
Reboiler (75-E-07), Light FCC gasoline cooler (75-E-05A/B) and the splitter
post condenser (75-E-04A/B).
¾ Commission the FIC-1203 ratio control loop on hydrogen make-up line. Start
to inject H2 at the nominal SOR H2/HC flowrate.
¾ Circulate through the reactor in once through mode (no recycling) until the
sample collected at splitter bottom is found clear (no more scales or catalyst
fines). The splitter bottom is sent to stabilizer (via pumps 75-P-02 A/B) from
where it is sent to slop/off spec.
¾ Gradually increase the operating temperature in the reactor at a rate of 20°C
per hour by increasing steam flowrate to SHU Reactor heater (75-E-03) to
reach the required SOR temperature.
¾ Re-start splitter (75-C-01).
¾ Put in operation the pressure controller in the splitter overhead system by the
pressure control loop PIC-1601. Ensure that Hydrogen make-up gas sent to
the reaction section should be sufficient to keep pressure in the splitter, if not,
N2 can be used.
¾ Draw-off of light cut and heart cut is closed. When SHU effluent is found clear,
start routing splitter bottoms to the feed surge drum via the hydrogenated
naphtha recycle line through SHU recycle air condenser (75-A-04).
¾ Since SHU feed is plso preheated via 75-E-02 SHU feed/splitter bottom
exchanger, decrease 75-E-03 steam preheater duty as much as possible
while maintaining SHU inlet SOP temperature.
¾ Wait until all temperature(s) indicators in the reactor give a steady indication
and maintain this circulation for 6 hours.
Template No. 5-0000-0001-T2 Rev A
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6.7.3
Doc No. Draft
Rev. A
Page 103 of 195
LINING UP OF THE HDS REACTION SECTION
¾ By using 75-P-02 A/B send inert naphtha to HDS reaction section.
Commission FV-1901 control valves and flow controller FIC-1901. As flow is
increased to HDS section, reduce bypass flow from splitter to stabilizer (as set
during SHU section lining up).
¾ The inert naphtha is then routed to the HDS Feed/Effluent Exchangers (75-E08 A/B/C) shell side, First HDS reactor (75-R-02), HDS Reactor heater (75-F01), , HDS Feed/Effluent Exchangers (75-E-08 A/B/C) Tube side, SHU reactor
feed / HDS effluent exchanger (75-E-01), HDS effluent air condenser (75-A03A/B/C/D), Reactor effluent trim cooler (75-E-09A/B) and to the separator
drum (75-V-03).
¾ When the level in the separator drum (75-V-03) has reached 40%,
commission the level flow control instrument FIC-2402 and LIC-2404.
¾ Start injecting wash water upstream of the reactor effluent air cooler. When a
water interface is appeared in the separator boot, commission the interface
level controller LIC-2401 and check it operates correctly.
¾ At this step, check the proper functioning of instrumentation, control valves
and pumps.
¾ The recycle compressor remains in operation and hydrogen gas is recycled
through the HDS feed/effluent exchangers (75-E-08 A/B/C shell side), First
HDS reactor (75-R-02), HDS reactor heater (75-F-01), HDS feed/effluent
exchangers (75-E-08 A/B/C tube side), SHU feed / HDS effluent exchanger
(75-E-01), HDS effluent air cooler (75-A-03), Reactor effluent trim cooler (75E-09), Separator drum (75-V-03) and the Recycle compressor KO drum (75V-04). Keep the Amine KO drum (75-V-06) and Amine Absorber (75-C-02) still
bypassed.
¾ The pressure in HDS reaction section separator should be maintained at
approximately 15 Kg/cm2g by hydrogen gas make-up. Recycle compressor is
operating at full load.
¾ Light burners of HDS reactor heater (75-F-01) and commission control loops
on reactor
Template No. 5-0000-0001-T2 Rev A
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Doc No. Draft
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Page 104 of 195
¾ Gradually increase the operating temperature of the HDS reactor at a rate of
30°C per hour in order to reach 180° C.
6.7.4
INERT NAPHTHA CIRCULATION
¾ After the commissioning of FIC-2402, inert naphtha is sent to Stabiliser
column (75-C-03).
¾ Re-start to Stabiliser column (75-C-03).
¾ An open loop circulation through the HDS reactor at 150-200° C will allow an
efficient cleaning of the reactor as the naphtha will be mainly in liquid phase.
This naphtha circulation in open loop has to be done with H2 circulation and
gradual warming of the reactor. After 4 hours of open loop, naphtha should be
circulated in close loop.
¾ Send inert naphtha back to the SHU feed surge drum (75-V-01) from the
bottom of stabiliser via recirculation line. Commission flow controller FIC2901.
¾ Commission SHU feed pumps (75-P-01 A/B) for a continuous use in the
overall inert naphtha circulation around unit in order to reach 60% of the
design unit capacity.
¾ Line up Amine Absorber with other equipment of the HDS reaction section,
which is currently filled with hydrogen.
¾ Open the Lean and Rich amine block valves at B.L and start circulation of
solution through the HP Amine Absorber. Allow the HP Amine Absorber to fill
until a level is established at the bottom. Commission the level control loop,
LIC-2601, as well as flow control loops on the lean amine FIC-2501. The
recycle gas is gradually circulated through the absorber by cutting back on the
bypass gas stream.
6.7.5
FCC GASOLINE FEED
¾ After establishing smooth operating conditions with inert naphtha, the unit is
ready for introduction of FCC gasoline.
¾ Start introduction of light gasoline from the FCC unit to SHU feed surge drum
(75-V-01) at approximately 10% of the normal flow rate through FIC-1201. At
Template No. 5-0000-0001-T2 Rev A
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Doc No. Draft
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Page 105 of 195
the same time reduce the recirculation rate from the 75-V-01 by the same
amount.
¾ Adjust the make-up hydrogen gas as necessary to keep the pressure in the
Splitter and SHU Reactor at the normal operating values.
¾ Ensure that the pressure difference between the reactor and the Splitter is
maintained through pressure control loop (PIC-1501).
¾ Gradually increase the flow of raw FCC light gasoline to the feed surge drum
75-V-01, by increments of 10% of the normal flow rate. In the same
proportion, decrease the recirculation of naphtha from cooler 75-E-12 to the
feed surge drum (75-V-01). Excess naphtha is sent to off-spec storage tank.
¾ Stabilize operating conditions after each increase of FCC light gasoline in the
feed.
¾ Watch carefully the temperature gradient on the reactors. Decrease the inlet
temperature to the reactors if the temperature rise is too fast.
¾ If there is no temperature rise in the reactors, increase the reactor inlet
temperature in steps of 2°C maximum.
¾ Monitor the temperature rise on each catalyst bed.
¾ Adjust the operating conditions according to the analysis of the product
(MAV).
¾ The Gasoline Splitter (75-C-01), light FCC gasoline draw-off, is put into
operation when the column top temperature reaches the design value and
reflux drum (75-V-02) liquid level is stabilized.
¾ The FCC heart cut gasoline draw-off is put into operation if required (high
benzene content in FCC feed) when TIC-1502 reaches the operating value.
Gasoline should be sent to slop if it is not on-specification.
¾ Once draw-off has started, start to add FCC gasoline to the SHU feed surge
drum (75-V-01).
¾ The Stabilizer is operated with vapor distillate product only. The condensate is
returned to the column as reflux. The RVP of Hy. Gasoline and the H2S
stripping required to be monitored to define the proper operating pressure and
Reboiler temperature in the column.
¾ Send off-spec Hydrotreated gasoline to slop until it is on-specification.
Template No. 5-0000-0001-T2 Rev A
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Doc No. Draft
Rev. A
Page 106 of 195
¾ When the product is on-specification slowly increase unit feed flow rates in
steps of 5% up to 100%.
System is now ready for normal operation.
Template No. 5-0000-0001-T2 Rev A
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Doc No. Draft
Rev. A
Page 107 of 195
SECTION- 7 NORMAL OPERATING PROCEDURE
Template No. 5-0000-0001-T2 Rev A
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OPERATING MANUAL FOR
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7.1
Rev. A
Page 108 of 195
GUIDELINES FOR NORMAL OPERATION
This section deals with normal operating procedures of Prime G+ Unit
7.2
INTRODUCTION
Normal operation implies that the unit is lined out at the desired capacity
and the products meet the required specifications. However it is possible, to
optimize the unit so that utility consumption is reduced. This is accomplished by
adjusting the parameter while maintaining the desired product qualities. The
reflux flow rate and the heat input to the column are directly related as discussed
in process description section.
7.3
OPERATING PARAMETER
Operating Conditions and Parameter are given in the table below.
S.
Description
No.
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
FCC Gasoline from FCC unit to SHU FEED
SURGE DRUM.
SHU Feed Surge Drum
FCC Gasoline feed to SHU feed surge drum.
FCC Gasoline Feed to SHU Feed Surge Drum
FCC Gasoline from storage to SHU FEED
SURGE DRUM
Recycle Heavy Gasoline from SHU recycle air
Condenser
Cold Gasoline feed from storage to SHU feed
surge drum
Mixed stream of FCC Gasoline from FCC unit &
Storage to SHU FEED SURGE DRUM
FCC Gasoline cold feed filters
Gasoline from SHU FEED PUMP to SHU
FEED/HDS Effluent Exchanger
Gasoline SHU Feed
Gasoline after SHU feed pumps.
Template No. 5-0000-0001-T2 Rev A
Tag no.
TI-1101
Unit
o
C
Value
70
PIC-1101
Kg/cm2g
3
FI-1101
3
M /hr
163.5
FIC-1102
3
163.5
TI-1103
M /hr
o
C
40
FIC-1103
M3/hr
*
FIC-1104
M3/hr
157.0
TI-1105
PDI-1106
TI-1201
o
C
Kg/cm2g
o
C
40
0.3
40-70
FIC-1201
M3/hr
163.5
FIC-1202
3
163.5
M /hr
Copyrights EIL- All rights reserved
Doc No. Draft
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
S.
Description
No.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
23.
24.
25.
26.
27.
28.
29.
30.
31.
32.
33.
Gasoline mixed with H2 to SHU FEED/HDS
Effluent Exchanger
H2 to SHU section
H2 from Isomerisation Make-up Compressor
Discharge
Gasoline & H2 stream from SHU FEED PUMPS
to SHU FEED/HDS Effluent Exchanger
Gasoline bypass before SHU Feed/HDS Effluent
Exchanger
Gasoline & H2 stream from SHU FEED PUMPS to
SHU FEED/HDS Effluent Exchanger
Gasoline & H2 after SHU Feed/HDS Effluent
Exchanger
Gasoline & H2 stream before & after 1ST SHU
Feed/HDS Effluent Exchanger
Gasoline & H2 at the inlet of SHU
FEED/EFFLUENT EXCHANGER
VHP condensate from SHU Preheater
Reactor Effluent (Gasoline & H2) after passing
through SHU FEED/EFFLUENT EXCHANGER
Gasoline & H2 stream before & after SHU
Feed/Effluent Exchanger
Gasoline & H2 stream before SHU Preheater
Reactor feed from SHU FEED/Effluent Exchanger
to SHU Preheater
Reactor feed from SHU Preheater to SHU
Reactor
VHP steam inlet to SHU Preheater
Reactor feed from SHU FEED/Effluent Exchanger
to SHU Preheater
Gasoline & H2 stream after SHU Preheater
Gasoline & H2 stream before & after SHU
Preheater
Reactor feed stream before & after the Preheater
Reactor feed stream from SHU Preheater to SHU
Reactor
Template No. 5-0000-0001-T2 Rev A
Tag no.
TI-1203
FIC-1203
TI-2701
Rev. A
Page 109 of 195
Unit
o
C
Nm3/hr
o
C
Value
66
1513
40
PI-1206
Kg/cm2g
66
FIC-1204
M3/hr
31.3
PI-1206
Kg/cm2g
33.4
PI-1207
Kg/cm2g
32.9
PDI-1208
Kg/cm2g
0.4
TI-1301
FIC-1301
TI-1302
o
C
65-162
M3/hr
15.4
o
C
162-189
PDI-1302
Kg/cm2g
0.4
PI-1303
Kg/cm2g
32.4
TI-1304
o
C
86-189
TI-1305
o
C
160-200
PI-1306
TI-1303
Kg/cm2g
o
C
31.9-37.6
189
PI-1307
Kg/cm2g
32
PDI-1308
Kg/cm2g
0.4
TDIC-1306
o
C
5-74
TIC-1401
o
C
160-200
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OPERATING MANUAL FOR
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VRCFP, HPCL VISAKH
S.
Description
No.
34.
35.
36.
37.
38.
39.
40.
41.
42.
Gasoline & H2 stream by pass to SHU Reactor
A Bypass line of reactor feed stream to SHU
reactor
Gasoline & H2 stream Inside SHU Reactor on the
first bed of catalyst
Gasoline & H2 stream before entering SHU
Reactor
Gasoline & H2 stream Inside SHU Reactor on the
first bed of catalyst
Gasoline & H2 stream by pass
Gasoline & H2 stream Inside SHU Reactor on the
first bed of catalyst
Gasoline & H2 stream by pass
Gasoline & H2 stream after passing through the
1st bed of catalyst in SHU Reactor
Rev. A
Page 110 of 195
Tag no.
Unit
Value
PDIC-1401
Kg/cm2g
0.8
TIC-1402
o
C
160-200
TI-1403
o
C
160-219
PI-1403
TI-1404
PI-1404
TI-1405
Kg/cm2g
o
C
160-219
Kg/cm2g
o
30
C
30
160-219
PI-1405
29
PI-1407
Kg/cm2g
30
PDI-1408
Kg/cm2g
0.5
PI-1409
Kg/cm2g
28
PDI-1410
Kg/cm2g
0.5
PI-1411
Kg/cm2g
28
Gasoline & H2 stream before entering SHU
43.
Reactor & after passing through the 1st bed of
catalyst in SHU Reactor
44.
45.
46.
47.
48.
49.
50.
51.
52.
53.
54.
55.
56.
SHU Reactor Effluent
Gasoline & H2 stream after 1st bed of catalyst in
SHU Reactor & Effluent from SHU reactor
SHU Reactor Effluent
Gasoline & H2 stream Inside SHU Reactor on the
second bed of catalyst
Gasoline & H2 stream Inside SHU Reactor on the
second bed of catalyst
Gasoline & H2 stream Inside SHU Reactor on the
second bed of catalyst
Effluent from the SHU Reactor
Effluent from the SHU Reactor
Effluent from the SHU Reactor
Gasoline & H2 stream inside the Splitter
SHU Reactor Effluent to Gasoline Splitter
VHP Steam to Reboiler Splitter
Gasoline & H2 stream inside the Splitter
Template No. 5-0000-0001-T2 Rev A
TI-1407
o
C
160-219
TI-1410
o
C
160-219
TI-1414
o
C
160-219
TI-1415
o
C
160-219
TI-1416
o
C
160-219
TI-1417
o
C
160-219
TIC-1501
o
C
107-117
2
PKIC-1501
Kg/cm g
6.3
FIC-1501
3
26.7
TIC-1502
M /hr
o
C
139-142
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Doc No. Draft
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
S.
Description
No.
57.
SHU Reactor Effluent to Gasoline Splitter
58.
Heavy Naphtha at the bottom of Gasoline Splitter
59.
60.
61.
62.
63.
64.
65.
66.
67.
68.
69.
70.
71.
72.
73.
Inert Naphtha in Start-up filling line from SHU
Feed pump to Splitter inlet
Heavy naphtha from the splitter bottom to HDS
section
Splitter overhead i.e. Gasoline vapour
Inside the Splitter column above the heart cut
naphtha plate at 37th tray
Reboiler outlet to Splitter bottom
Inside the Splitter column above the feed plate at
20th tray
Splitter outlet to Reboiler inlet
Inside the Splitter column below 1st tray
Gasoline & H2 stream on the 19th tray inside the
Splitter column
Splitter overhead & splitter underflow
Gasoline & H2 stream to the Splitter Feed
Light gasoline vapor in splitter reflux drum
Splitter overhead (vapor gasoline)
Splitter overhead to Splitter Reflux drum after
Splitter overhead air condenser
Fuel gas from Splitter Reflux Drum to Fuel gas
header
Rev. A
Page 111 of 195
Tag no.
Unit
Value
PI-1502
Kg/cm2g
6.3
LIC-1502
Mm
*
FI-1502A/B
M3/hr
*
TI-1504
o
C
174-181
PI-1505
Kg/cm2g
6
PI-1507
Kg/cm2g
6.2
TI-1507
PI-1508
TI-1508
PI-1511
TI-1505
PDI-1506
TI-1504
PIC-1601
o
C
218-221
Kg/cm2g
o
C
214-217
2
Kg/cm g
o
C
6.5
181-199
Kg/cm2g
o
6.5
C
0.5
122-160
2
Kg/cm g
5.5
TI-1602
o
C
93-97
TI-1603
o
C
55
TI-1605
o
C
40
74.
Fuel gas to FCC inlet
PI-1610
Kg/cm2g
4.5
75.
Splitter overhead to splitter reflux drum
PI-1603
Kg/cm2g
5.5
76.
77.
78.
79.
80.
Light FCC Gasoline to MS POOL
Light Gasoline from Accumulator tray no.48 of
Splitter
Light Gasoline after light gasoline cooler to light
gasoline MS POOL
FCC HEART CUT GASOLINE
FCC Heart cut gasoline from accumulator tray
no.36
Template No. 5-0000-0001-T2 Rev A
TI-1706
o
C
40
PI-1703
Kg/cm2g
7.6
PI-1704
Kg/cm2g
7.7
TI-1702
PI-1707
o
C
Kg/cm2g
65
7.6
Copyrights EIL- All rights reserved
Doc No. Draft
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
S.
Description
No.
81.
82.
83.
84.
85.
86.
FCC Heart cut gasoline after FCC Heart cut
cooler to storage
FCC Heart cut gasoline after FCC Heart cut
cooler to storage
Light Gasoline to storage after light gasoline
cooler
Gasoline & H2 at the inlet of First HDS Feed /
Effluent Exchanger
HDS feed & HDS recycle to HDS feed / effluent
exchanger.
Vapor gasoline to HDS feed
Rev. A
Page 112 of 195
Tag no.
Unit
Value
PI-1714
Kg/cm2g
7
TI-1713
o
C
40
PI-1710
Kg/cm2g
7
PI-1901
Kg/cm2g
23.5-30
TI-1901
o
C
148-176
PI-1904
Kg/cm2g
22-28.5
PDI-1905
Kg/cm2g
1.2
Gasoline & H2 at the inlet of 1st HDS
87.
Feed/Effluent Exchanger & at the outlet of 3rd
HDS Feed/Effluent Exchanger
HDS feed from First HDS Feed/Effluent
88.
Exchanger to second HDS Feed/Effluent
TI-1902
o
C
210-240
TI-1903
o
C
242-271
Exchanger
89.
90.
91.
92.
93.
94.
95.
96.
97.
HDS feed from second HDS Feed/Effluent
Exchanger to third HDS Feed/Effluent Exchanger
Gasoline & H2 at the outlet of 2nd HDS
FEED/EFFLUENT Exchanger
HDS Reactor Effluent after 3rd HDS Feed/Effluent
Exchanger
HDS rector effluent from HDS feed/effluent
exchanger tube side outlet.
HDS rector effluent from HDS feed/effluent
exchanger tube side outlet.
Heavy FCC Gasoline after 3rd HDS Feed/Effluent
Exchanger to first HDS Reactor
Heavy FCC Gasoline before entering first HDS
Reactor
Heavy FCC Gasoline after third HDS
Feed/Effluent Exchanger to first HDS Reactor
Heavy FCC Gasoline before entering first HDS
Reactor
Template No. 5-0000-0001-T2 Rev A
PI-1903
Kg/cm2g
22.5-29
PI-1904
Kg/cm2g
22-28.5
TI-1906
PI-1908
TIC-2001
PI-2001
TI-2002
PI-2002
o
C
Kg/cm2g
o
C
Kg/cm2g
o
C
Kg/cm2g
207-227
16.3-22.8
275-312
22.9
275-312
22.9
Copyrights EIL- All rights reserved
Doc No. Draft
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
S.
Description
No.
98.
99.
100.
101.
102.
On the First bed of catalyst inside first HDS
Reactor
Liq. Gasoline on 2nd bed of catalyst in 1st HDS
Reactor
On the First bed of catalyst inside first HDS
Reactor
Liq. Gasoline on 1st bed of catalyst in 1st HDS
Reactor
Gasoline after passing through first bed of catalyst
in first HDS Reactor
103. First HDS Reactor Effluent
104.
On the 2nd bed of catalyst inside first HDS
Reactor
105. First HDS Reactor Effluent
106. First HDS Reactor Effluent to HDS Fired Heater
107. First HDS Reactor Effluent to HDS fired heater
108. Effluent of HDS Fired Heater
109. HDS fired heater outlet to second HDS Reactor
110.
111.
112.
HDS Reactor Effluent from SHU feed/HDS
Effluent Exchanger to HDS Effluent Air Condenser
Gasoline from SHU Feed/HDS Effluent Exchanger
to HDS Effluent air condenser
HDS Reactor Effluent after HDS Effluent Air
Condenser
Gasoline after passing through HDS Effluent air
Tag no.
TI-2003
PDI-2006
TI-2004
Rev. A
Page 113 of 195
Unit
o
C
275-355
Kg/cm2g
o
Value
C
0.5
275-355
PDI-2004
Kg/cm2g
0.5
PI-2003
Kg/cm2g
28.4
PI-2007
Kg/cm2g
28.4
TI-2010
o
C
275-355
TI-2019
o
C
275-355
TI-2102A/B
o
C
PI-2102A/B
TI-2104A/B
PI-2103A/B
TI-2301
PI-2301
TI-2303
301-355
2
Kg/cm g
o
C
336-373
2
Kg/cm g
o
C
17.8-24.3
144-157
Kg/cm2g
o
19.8-26.3
C
16-22.5
65
PI-2303
Kg/cm2g
15.6-22.0
PI-2409
Kg/cm2g
15-21.5
FIC-2402
3
M /hr
82.3
116. Off gas from Separator Drum
PIC-2403
2
Kg/cm g
15
117. separator drum boot drain
LIC-2401
M3/hr
*
113.
condenser
114. Separator drum outlet
115. Stabilizer feed from separator drum
118.
Lean Ammine from ARU after being pre-heated in
the lean amine pre-heater
119. Lean Ammine from ARU
120.
OFF GAS from Amine K.O. Drum to Amine
Absorber
Template No. 5-0000-0001-T2 Rev A
TI-2501
o
C
50
TI-2504
o
C
40
TI-2502
o
C
40
Copyrights EIL- All rights reserved
Doc No. Draft
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
S.
Description
No.
121. LP Steam to Lean Amine Preheater
122. Off gas to Amine Absorber
123. Amine & Fuel gas in Amine Absorber
124. Fuel gas from Amine Absorber
125. Rich amine from amine absorber
126. Amine & Fuel gas inside Amine Absorber
127. Rich Amine from Amine Absorber
128. Make-up H2 to Recycle Compressor K.O. Drum
Tag no.
TDIC-2503
PI-2601
PDI-2602
Rev. A
Page 114 of 195
Unit
o
C
Value
10
2
14.8
2
0.3
2
Kg/cm g
Kg/cm g
PI-2603
Kg/cm g
14.7-21.5
LIC-2601
3
*
PI-2608
PI-2609
TI-2701
M /hr
2
14.7
2
6
Kg/cm g
Kg/cm g
o
C
40
2
129. Make up H2 to Recycle Compressor K.O. Drum
PI-2701
Kg/cm g
38.9
130. make up H2 to Recycle Compressor K.O. Drum
FIC-2701
Nm3/hr
6944
PI-2705
Kg/cm2g
14.4-21.4
132. H2 from Recycle Compressor to HDS Section
FI-2803
Nm3/hr
35145
133. H2 to HDS section
FI-2804
Nm3/hr
35145
131.
134.
Recycle gas from Recycle Compressor K.O. drum
to Recycle compressor
Gasoline from Separator to Stabilizer
Feed/Bottom Exchangers
135. Stabilizer Feed from Separator Drum
136.
137.
Heavy Gasoline from Heavy Gasoline Trim Cooler
to MS POOL
Gasoline after Stabilizer Feed/Bottom Exchangers
to stabilizer
Heavy Gasoline from Stabilizer Bottom to
TI-2901
o
C
41
PI-2901
Kg/cm2g
9
FI-2901
M3/hr
*
PI-2903
Kg/cm2g
7
TI-2903
o
C
225-226
TI-2903
o
C
40
TI-2905
o
C
106-107
141. Heavy Gasoline to MS POOL via Storage
TI-2909
o
C
40
142. Heavy Gasoline from Stabilizer Bottom Pumps
PI-2909
Kg/cm2g
9.5
LIC-3001
mm
*
FIC-3001
M3/hr
15
138.
Stabilizer Feed/Bottom Exchangers
139. Heavy Gasoline after Heavy Gasoline Trim Cooler
140.
143.
Heavy Gasoline from Stabilizer Feed/Bottom
Exchanger to Heavy Gasoline Trim Cooler
Heavy Gasoline at the bottom of Stabilizer
Column
144. Stabiliser reflux from, stabiliser Reflux Pumps
145. Stabilizer Feed
146. VHP Steam to Stabilizer Reboiler
147. Vap. Gasoline from Stabilizer overhead
Template No. 5-0000-0001-T2 Rev A
TI-3002
FIC-3002
PI-3003
o
C
168-169
3
M /hr
9.7
2
6.8
Kg/cm g
Copyrights EIL- All rights reserved
Doc No. Draft
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
S.
Description
No.
148.
149.
From Stabilizer bottom to Stabilizer Feed/Bottom
Exchangers
Stabilizer overhead to Stabilizer overhead
150. Vap. Gasoline below 1st tray in Stabilizer
151. VHP Condensate Pot for Stabilizer column
Value
FIC-3003
M3/hr
106
157.
Stabilizer
Heavy Gasoline from the bottom of Stabilizer to
VHP steam reboiler
Heavy Gasoline from VHP steam reboiler to
Stabilizer
134-140
7
LIC-3004
MM
*
PI-3005
Treated Heavy Gasoline from the bottom of
C
Kg/cm2g
153. Gasoline vapour at the top of Stabilizer column
156.
o
PI-3004
TI-3005
155.
7.4
Unit
152. Top of Stabilizer column
154. Inside Stabilizer column below the feed plate
Page 115 of 195
Tag no.
TI-3004
Condenser
Rev. A
o
C
160-200
Kg/cm2g
6.9
TI-3006
o
C
203-217
TI-3013
o
C
225-226
TI-3009
o
C
221
TI-3010
o
C
225
ALARMS:
S. No.
1.
Descriptions
Tag no.
Mixed stream of FCC Gasoline from
Unit
Value
TAHH-1105
o
C
77
TAL-1301
o
C
60
TAL-1304
o
C
80
FCC unit & Storage to SHU FEED
DRUM
2.
Gasoline & H2 at the inlet of SHU
FEED/EFFLUENT EXCHANGER
3.
Reactor feed from SHU FEED/Effluent
Exchanger to SHU Preheater
4.
from
SHU
TAH-1401
o
C
TAH-210
from
SHU
TAL-1401
o
C
TAL-150
A Bypass line of reactor feed stream to
TAH-1402
o
C
TAH-210
TAH-1403
o
C
TAH-225
TAHH-1403
o
C
TAHH-230
Reactor
feed
stream
Preheater to SHU Reactor
5.
Reactor
feed
stream
Preheater to SHU Reactor
6.
SHU reactor
7.
Gasoline & H2 stream Inside SHU
Reactor on the first bed of catalyst
8.
Gasoline & H2 stream Inside SHU
Reactor on the first bed of catalyst
Template No. 5-0000-0001-T2 Rev A
Copyrights EIL- All rights reserved
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
S. No.
9.
Descriptions
Gasoline & H2 stream Inside SHU
Tag no.
Unit
Doc No. Draft
Rev. A
Page 116 of 195
Value
TAH-1404
o
C
TAH-225
TAHH-1404
o
C
TAHH-230
TAH-1405
o
C
TAH-225
TAHH-1405
o
C
TAHH-230
TAH-1407
o
C
TAH-225
TAHH-1407
o
C
TAHH-230
TAH-1408
o
C
TAH-225
TAHH-1408
o
C
TAHH-230
TAH-1409
o
C
TAH-225
TAHH-1409
o
C
TAHH-230
TAH-1410
o
C
TAH-225
TAHH-1410
o
C
TAHH-230
TAH-1411
o
C
TAH-225
TAHH-1411
o
C
TAHH-230
TAH-1412
o
C
TAH-225
TAH-1412
o
C
TAHH-230
TAH-1413
o
C
TAH-225
TAH-1413
o
C
TAHH-230
Reactor on the first bed of catalyst
10.
Gasoline & H2 stream Inside SHU
Reactor on the first bed of catalyst
11.
Gasoline & H2 stream Inside SHU
Reactor on the first bed of catalyst
12.
Gasoline & H2 stream Inside SHU
Reactor on the first bed of catalyst
13.
Gasoline & H2 stream Inside SHU
Reactor on the second bed of catalyst
14.
Gasoline & H2 stream Inside SHU
Reactor on the second bed of catalyst
15.
Gasoline & H2 stream Inside SHU
Reactor on the second bed of catalyst
16.
Gasoline & H2 stream Inside SHU
Reactor on the second bed of catalyst
17.
Gasoline & H2 stream Inside SHU
Reactor on the second bed of catalyst
18.
Gasoline & H2 stream Inside SHU
Reactor on the second bed of catalyst
19.
Gasoline & H2 stream Inside SHU
Reactor on the second bed of catalyst
20.
Gasoline & H2 stream Inside SHU
Reactor on the second bed of catalyst
21.
Gasoline & H2 stream Inside SHU
Reactor on the second bed of catalyst
22.
Gasoline & H2 stream Inside SHU
Reactor on the second bed of catalyst
23.
Gasoline & H2 stream Inside SHU
Reactor on the second bed of catalyst
24.
Gasoline & H2 stream Inside SHU
Reactor on the second bed of catalyst
25.
Gasoline & H2 stream Inside SHU
Reactor on the second bed of catalyst
26.
Gasoline & H2 stream Inside SHU
Reactor on the second bed of catalyst
Template No. 5-0000-0001-T2 Rev A
Copyrights EIL- All rights reserved
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
S. No.
27.
Descriptions
Gasoline & H2 stream Inside SHU
Tag no.
Doc No. Draft
Rev. A
Page 117 of 195
Unit
Value
TAH-1414
o
C
TAH-225
TAH-1414
o
C
TAHH-230
TAHH-1415
o
C
TAH-225
TAH-1501
o
C
127
TAH-1502
o
C
152
TAH-1503
o
C
170
TAH-1505
o
C
204
TAH-1504
o
C
170
TAH-1603
o
C
60
TAH-1605
o
C
*
TAH-2001
o
C
322
TAH-2003
o
C
TAH-360
TAHH-2003
o
C
TAHH-365
TAH-2004
o
C
TAH-360
TAHH-2004
o
C
TAHH-365
TAH-2013
o
C
TAH-360
TAHH-2013
o
C
TAHH-365
TAH-2019
o
C
TAH-360
TAHH-
o
C
TAHH-385
TDAL-2506
o
C
TDAL-5
TAH-3002
o
C
TAH-179
Reactor on the second bed of catalyst
28.
Gasoline & H2 stream Inside SHU
Reactor on the second bed of catalyst
29.
Effluent from the SHU Reactor
TAHH-230
30.
31.
32.
33.
Gasoline & H2 stream inside the Splitter
Gasoline & H2 stream inside the Splitter
Gasoline & H2 stream to the Splitter
Gasoline & H2 stream below the FEED
TRAY at the 19th tray inside the Splitter
34.
35.
Gasoline & H2 stream feed to splitter
Splitter overhead to Splitter Reflux drum
after Splitter overhead air condenser
36.
Fuel gas from Splitter Reflux Drum to
Fuel gas header
37.
Heavy FCC Gasoline after 3rd HDS
Feed/Effluent Exchanger to first HDS
Reactor
38.
On the First bed of catalyst inside first
HDS Reactor
39.
On the First bed of catalyst inside first
HDS Reactor
40.
On the First bed of catalyst inside first
HDS Reactor
41.
On the First bed of catalyst inside first
HDS Reactor
42.
On the 2nd bed of catalyst inside first
HDS Reactor
43.
On the 2nd bed of catalyst inside first
HDS Reactor
44.
First HDS Reactor Effluent
TAHH-365
45.
HDS Fired Heater Effluent
2103A/B
46.
47.
LP Steam to Lean Amine Preheater
Stabilizer Feed
Template No. 5-0000-0001-T2 Rev A
Copyrights EIL- All rights reserved
Doc No. Draft
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
S. No.
48.
49.
Descriptions
Tag no.
Rev. A
Page 118 of 195
Unit
Value
TAL-3002
o
C
TAL-163
plate of Stabilizer
TAH-3006
o
C
227
Above the 12th plate of Stabilizer
TAH-3007
o
C
227
PAH-1101
Kg/cm2g
Stabilizer Feed
th
Above the 17
column
50.
column
51.
52.
Feed Surge Drum pressure control
FCC Gasoline from FCC unit to SHU
2
3.5
PDAH-1106
Kg/cm g
0.5
PDAH-1208
Kg/cm2g
0.7
PDAH-1302
Kg/cm2g
0.6
PDAH-1308
Kg/cm2g
0.6
PAL-1403
Kg/cm2g
29.2
PAL-1407
Kg/cm2g
28
PDAH-1408
Kg/cm2g
1.75
PAL-1409
Kg/cm2g
27
Feed Surge Drum
53.
Gasoline & H2 stream before & after
1ST
SHU
Feed/HDS
Effluent
Exchanger
54.
Gasoline & H2 stream before & after
SHU Feed/Effluent Exchanger
55.
Gasoline & H2 stream before & after
SHU Preheater
56.
Gasoline & H2 stream before entering
SHU Reactor
57.
Gasoline & H2 stream after passing
through the 1st bed of catalyst in SHU
Reactor
58.
Gasoline & H2 stream before entering
SHU Reactor & after passing through
the 1st bed of catalyst in SHU Reactor
59.
60.
SHU Reactor Effluent
Gasoline & H2 stream after 1st bed of
2
PDAH-1410
Kg/cm g
1.75
PDAH-1506
Kg/cm2g
1
catalyst in SHU Reactor & Effluent from
SHU reactor
61.
62.
Splitter overhead & splitter underflow
Light gasoline vapour in splitter reflux
2
PAH-1601
Kg/cm g
PAH-6.5
PAL-1601
Kg/cm2g
PAL-5.2
PALL-1604
Kg/cm2g
4.2
PAL-1904
Kg/cm2g
21
drum
63.
Light gasoline vapour in splitter reflux
drum
64.
Gasoline from splitter reflux pumps to
top of splitter column
65.
Vapour gasoline to HDS feed
Template No. 5-0000-0001-T2 Rev A
Copyrights EIL- All rights reserved
Doc No. Draft
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
S. No.
66.
Descriptions
Tag no.
Gasoline & H2 at the inlet of 1st HDS
Rev. A
Page 119 of 195
Unit
2
Value
PDAH-1905
Kg/cm g
1.5
PDAH-2004
Kg/cm2g
0.75
PDAH-2006
Kg/cm2g
0.75
Feed/Effluent Exchanger & at the outlet
of 3rd HDS Feed/Effluent Exchanger
67.
Liq. Gasoline on 1st bed of catalyst in
1st HDS Reactor
68.
Liq. Gasoline on 2nd bed of catalyst in
1st HDS Reactor
69.
Off gas from Separator Drum
PAH-2409
Kg/cm2g
PAH-22.5
70.
Off gas from Separator Drum
PAL-2409
Kg/cm2g
PAL-14.2
71.
Part of liq. From Separator to 1st HDS
2
PALL-2407
Kg/cm g
22
Reactor
72.
Amine & Fuel gas in Amine Absorber
PDAH-2602
Kg/cm2g
0.5
73.
Recycle gas from Recycle Compressor
PAH-2705
Kg/cm2g
PAH-22
PAL-2705
Kg/cm g
PAL-13.6
PAH-7.8
K.O. drum to Recycle compressor
74.
Recycle gas from Recycle Compressor
2
K.O. drum to Recycle compressor
75.
Vap. Gasoline from Stabilizer overhead
PAH-3003
Kg/cm2g
76.
Vap. Gasoline from Stabilizer overhead
PAL-3003
Kg/cm g
77.
Vap.
Gasoline
below
1st
tray
2
PAL-6.5
2
7.8
in
PAH-3004
Kg/cm g
FCC Gasoline Feed to SHU Feed
FAL-1102
M /hr
117.6
FAL-1202
M3/hr
*
Stabiliser
78.
3
Surge Drum
79.
80.
81.
82.
83.
84.
Gasoline SHU Feed
Gasoline SHU Feed
H2 to SHU section
VHP Steam to Reboiler Splitter
Separator drum boot drain
Make up H2 to Recycle Compressor
FALL-1205
FAL-1203
3
M /hr
3
Nm /hr
3
FAH-1501
M /hr
FAH-2403
3
M /hr
3
111.7
1000
30.7
5.6
FAL-2701
Nm /hr
1284
FALL-2802
Nm3/hr
20832
FAL-2803
Nm3/hr
20832
FALL-2801
Nm3/hr
13020
K.O. Drum
85.
H2 from Recycle Compressor to HDS
FEED/EFFLUENT Exchanger
86.
H2 from Recycle Compressor to HDS
Section
87.
H2 to HDS section
Template No. 5-0000-0001-T2 Rev A
Copyrights EIL- All rights reserved
Doc No. Draft
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
S. No.
Descriptions
Tag no.
88.
VHP Steam to Stabilizer Reboiler
89.
Heavy
Naphtha
Rev. A
Page 120 of 195
Unit
Value
FAH-3002
M3/hr
10.7
at
the
bottom
of
LAH-1502
MM
LAH-3750
at
the
bottom
of
LAL-1502
MM
LAL-700
Heavy Gasoline at the bottom of
LAH-3001
MM
LAH-3190
LAL-3001
MM
LAL-1630
LALL-3002
MM
300
Gasoline Splitter
90.
Heavy
Naphtha
Gasoline Splitter
91.
Stabilizer Column
92.
Heavy Gasoline at the bottom of
Stabilizer Column
93.
Heavy Gasoline at the bottom of
Stabilizer Column
7.5
OPEARATING CONDITIONS OF DIFFERENT CASES OF OPERATION
Refer to enclosed PFDs as attachment for operating conditions for different
cases.
7.6
7.6.1
EQUIPMENT LIST
PUMPS
Item No.
75-P-01
Item Description
Norma
Rated
Disc.
Diff.
NPSHA
l Cap.
Cap.
Press
Head
(m)
(m³/hr)
(m³/hr)
(Kg/cm²g)
(m)
SHU FEED PUMPS
167.1
183.8
36.5
498
>8
HDS FEED PUMPS
112.3
123.5
34.8
472
4
166.6
200
11.3
95.7
3.3
79.7
96
10.5
45.5
>8
A/B
75-P-02
A/B
75-P-03
SPLITTER
A/B
PUMPS
75-P-04
A/B
REFLUX
LIGHT GASOLINE PUMPS
Template No. 5-0000-0001-T2 Rev A
Copyrights EIL- All rights reserved
Doc No. Draft
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
Page 121 of 195
Norma
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.
°C
Kg/cm²g
75-P-07
STABILIZER
A/B
PUMPS
75-P-08
CORROSION
A/B
PUMPS
75-P-09
STABILIZER
A/B
PUMP
7.6.2
Rev. A
BOTTOM
INHIBITOR
REFLUX
VESSELS:
Tag No.
Item Description
(mm)
75-V-01
SHU FEED SURGE DRUM
3900
11000
70
3.0
75-V-02
SPLITTER REFLUX DRUM
2400
6800
55
5.5
75-V-03
SEPARATOR DRUM
2500
8400
40
21.5
75-V-04
RECYCLE COMP. KOD
900
2800
40
21.4
75-V-05
STABILIZER REFLUX DRUM
1100
3300
40
6.3
75-V-06
AMINE KOD
900
2500
40
21.5
600
1950
AMB
1.0
1600
5000
AMB
1.0
75-V-09
75-V-10
CORROSION
INHIBITOR
DRUM
SULFIDING AGENT DRUM
Template No. 5-0000-0001-T2 Rev A
Copyrights EIL- All rights reserved
Doc No. Draft
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
7.6.3
Rev. A
Page 122 of 195
COLUMNS:
Tag
Item
No.
Internal
TL-TL
Oper. Temp
Oper Press
No.
Description
of
Dia
(mm)
°C
Kg/cm²g
tray
(mm)
52
3100
41550
116
20
900
14150
50
30
2100
26750
177
75-C-
GASOLINE
01
SPLITTER
75-C-
AMINE
02
ABSORBER
75-T-
STABILISER
1003
COLUMN
Top
Bottom
199
Top
Bottom
6.03
6.47
14.8
203
7.85
8.08
(Btm);
1100
(top)
7.6.4
REACTORS:
Item Description
Tag No.
7.6.5
TL-TL
Oper. Temp
Oper Press
Dia (mm)
(mm)
°C
Kg/cm²g
75-R-01
SHU REACTOR
1800
23420
200
30
75-R-02
HDS REACTOR
2500
12950
355
28.4
HEAT EXCHANGERS (TUBULAR):
Sr.
Tag
No.
No.
1
Internal
75-E-01
Service
SHU
Feed
/
Shell side
Tube side
Shell side
Tube side
fluid
fluid
temp (C)
temp (c)
IN
OUT
IN
OUT
HDS
HDS Effluent
SHU Feed
211
156
66
155
SHU Feed / Effluent
SHU Effluent
SHU Feed
219
188
155
188
VHP Steam
SHU Feed
238
238
128
200
Effluent exchanger
2
75-E-02
exchanger
3
75-E-03
SHU preheater
4
75-E-04
Splitter post condensor
HC+H2
Cooling water
55
40
33
40
5
75-E-05
Light Gasoline cooler
Light Gasoline
Cooling water
65
40
33
40
6
75-E-06
FCC Heartcut cooler
Gasoline
Cooling water
65
40
33
40
7
75-E-07
Splitter reboiler
VHP Steam
HC
238
238
216
221
HDS Feed
HDS Effluent
174
312
370
207
HC
Cooling water
65
40
33
40
8
9
75-E-08
HDS Feed / Effluent
A/B/C
Exchanger
75-E-09
Reactor
effluent
Template No. 5-0000-0001-T2 Rev A
trim
Copyrights EIL- All rights reserved
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
Doc No. Draft
Rev. A
Page 123 of 195
cooler
10
11
12
13
75-E-10
Lean Amine preheater
Lean Amine
LP steam
40
50
128
128
Stabilizer Feed
Stabilizer
225
107
41
169
Cooling water
65
40
33
40
Stabilizer
238
238
221
225
65
40
33
40
75-E-11
Stabilizer Feed/Bottom
A/B
exchanger
75-E-12
Heavy
A/B
cooler
gasoline
75-E-13
Stabilizer reboiler
VHP steam
Bottom
gasoline
trim
Heavy
bottom
14
75-E-14
7.6.6
Stabilizer overhead trim
Stabilizer
cooler
overhead
Cooling water
AIR COOLERS
Sr. No. Tag
Service
Temp. - in
Temp. - out
1
75-A-01
Splitter overhead air condenser
97
55
2
75-A-02
FCC heart cut air cooler
142
65
3
75-A-03
HDS Effluent air condenser
158
65
4
75-A-04
SHU recycle air condenser
218
65
5
75-A-05
Stabilizer overhead condenser
135
65
6
75-A-06
Light gasoline air cooler
116
65
7
75-A-07
Heavy gasoline air cooler
107
65
7.7
LIST OF 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
No
Action of CV
on Air failure
.
SHU FEED SURGE DRUM:
1.
PV-1101A
Gases from FSD to Flare
FC
2.
PV-1101B
Nitrogen to FSD
FC
3.
LV-1101
FSD boot draining
FC
Template No. 5-0000-0001-T2 Rev A
Copyrights EIL- All rights reserved
Doc No. Draft
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
S.
Tag No.
Rev. A
Page 124 of 195
Description
Action of CV
No
on Air failure
.
4.
FV-1103
Heavy
Gasoline
Recycle
from
SHU
Recycle
Air FC
Condenser
5.
FV-1104
Feed from storage
FC
SHU FEED SECTION:
6.
FV-1201
SHU feed to 75-E-01
FC
A/B
7.
FV-1202
Charge pump MCF
FO
8.
FV-1203
Hydrogen to reaction section
FC
9.
FV-1204
SHU Feed/Effluent Exchanger bypass to SHU Preheater
FO
A/B
SHU FEED PREHEATING SECTION:
10. FV-1301
VHP steam to SHU Preheater
FC
SHU Reactor first bed bypass
FC
A/B
SHU REACTOR:
11. PDV-1401
SHU SPLITTER SECTION:
12. PV-1404
Splitter feed
FC
13. PV-1501
Depressurization line
FO
14. FV-1501
VHP steam condensate from Splitter Reboiler
FC
15. PV-1601
Splitter reflux drum pressure control
FC
16. LV-1601
Reflux line
FO
17. FV-1701
Light gasoline to storage
FC
18. FV-1702
FCC Heart cut gasoline to storage
FC
19. FV-1703
Light gasoline pump min. fliow line
FO
A/B
HDS FEED SECTION:
20. FV-1801
HDS feed pump min. flow line
FO
21. FV-1901
HDS feed to HDS feed/Eff. Exchanger
FC
22. FV-1902
HDS Feed / Eff Exchanger bypass
FC
23. FV-1904
HDS recycle
FC
HDS REACTION SECTION
Template No. 5-0000-0001-T2 Rev A
Copyrights EIL- All rights reserved
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
S.
Tag No.
Description
Doc No. Draft
Rev. A
Page 125 of 195
Action of CV
No
on Air failure
.
24. FV-2001
Quench to reactor
FO
25. FV-2002
Quench to reactor
FO
26. FV-2003
Diluant line for start up
FO
27. FV-2101
Plant air to HDS Reactor Feed Heater
FC
HDS SEPARATOR SECTION
28. FV-2401
Quench pump min. flow line
FO
29. FV-2402
Stabilizer feed line
FC
30. LV-2401
Sour water boot
FC
RECYCLE GAS KOD AND AMINE ABSORBER SECTION:
31. FV-2501
Lean amine to preheater
FC
32. TV-2501
LP steam to preheater
FC
33. LV-2501
HC liquid from Amine KOD
FC
34. LV-2601
Rich amine to amine unit
FC
35. FV-2601
Sweet purge gas to FG header
FC
36. LV-2701
Amine from Recycle compressor K.O. drum to ARU
FC
37. FV-2701
Make up H2 to Recycle Compressor K.O. Drum
FC
38. FV-2702
Make up H2 to Recycle Compressor K.O. Drum
FC
STABILISER COLUMN:
39. FV-3001
Reflux to Splitter
FO
40. FV-3002
VHP condensate from stabilizer reboiler
FC
41. FV-3003
Stabilizer bottom pump min. flow line
FO
42. LV-3001
VHP Condensate from Condensate Pot
FC
43. FV-2901
Heavy gasoline to stabilizer feed / bottom exchanger
FC
44. PV-3101
Sour purge gas From stabilizer reflux drum
FC
45. LV-3101
Sour water to sour water treater
FC
Template No. 5-0000-0001-T2 Rev A
Copyrights EIL- All rights reserved
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
7.7.2
SL
Doc No. Draft
Rev. A
Page 126 of 195
ON-OFF VALVES
TAG NO.
DESCRIPTION/LOCATION
ACTION
NO.
ON
AIR FAILURE
SHU FEED SURGE DRUM:
1.
UV-1101
FCC Gasoline Feed to SHU Feed Surge Drum
2.
UV-1102
Heavy
Gasoline
Recycle
from
SHU
FC
Recycle
Air FC
Condenser
3.
UV-1103
SHU Feed Surge Drum Boot Drain
FC
4
UV-1104
Feed from FSD to Charge pump
FC
SHU FEED SECTION:
5.
UV-1201
Gasoline from SHU Feed pumps to SHU Feed/HDS FC
Effluent Exchanger
6.
UV-1202
H2 from Recycle Compressors to SHU Feed/Effluent FC
Exchanger
SHU FEED PREHEATING SECTION:
7.
UV-1301
VHP steam to SHU Preheater
FC
SHU SPLITTER SECTION:
8.
UV-1501
SHU emergency depressurisation to flare
FO
9.
UV-1502
Heavy Gasoline from Splitter bottom
FC
10.
UV-1503
Splitter Reboiler steam inlet
FC
11.
UV-1701
Light gasoline to storage
FC
12.
UV-1702
FCC Heart cut gasoline to storage
FC
HDS FEED SECTION
13.
UV-1901
HDS Feed to HDS Feed / Eff. Exchanger
FC
HDS REACTION SECTION
14.
UV-2101
Plant air to feed heater
FC
15.
UV-2301
BFW injection at HDS Eff. Air condenser
FC
SEPARATOR DRUM:
16.
UV-2401
Stabiliser Feed from Separator Drum
FC
17.
UV-2402
Separator Drum Boot Drain
FC
18.
UV-2403
Flare from Separator Drum for depressurisation
FO
AMINE ABSORBER:
19.
UV-2501
HC liquid from amine KOD
Template No. 5-0000-0001-T2 Rev A
FC
Copyrights EIL- All rights reserved
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
SL
TAG NO.
Doc No. Draft
Rev. A
Page 127 of 195
DESCRIPTION/LOCATION
ACTION
NO.
ON
AIR FAILURE
20.
UV-2502
LP steam to Amine preheater
FC
21
UV-2503
Lean amine to preheater
FC
22
UV-2504
LP condensate To 75-V-19
FC
23
UV-2505
LP condensate To OWS
FC
24.
UV-2601
Rich Amine from Amine Absorber
FC
RECYCLE COMPRESSOR SECTION:
25.
UV-2701
H2 from Recycle Compressor K.O. Drum
FC
26.
UV-2702
Make up H2 to Recycle Compressors K.O. Drum
FC
27.
UV-2703
Amine as Recycle Compressors K.O. Drum Drain
FC
28.
UV-2801
Recycle gas comp. discharge
FC
STABILISER COLUMN:
29.
UV-3001
Heavy Gasoline from Stabiliser bottom to Stabiliser Bottom FC
Pumps
30.
7.7.3
UV-3002
Stabiliser Reboiler Steam Inlet
FC
SAFETY VALVES:
S. No.
Tag No.
Description/Location
Set Pressure
(Kg/cm2g)
1.
PSV-1101 A/B
Feed Surge Drum
5.0
2.
PSV-1102 A/B
Cold Feed Filter
15
3.
PSV-1201 A/B
Feed pump discharge
37
4.
PSV-1202 A/B
SHU Feed to 75-E-03
37
5.
PSV-1301
SHU preheater condensate pot
40
6.
PSV-1401
SHU Reactor
35.1
7.
PSV-1501A/B
From Gasoline Splitter to Flare
8
8.
PSV-1502
Splitter reboiler condensate pot
40
9.
PSV-1601/1602
Sea water return from 75-E-04
7.6
10.
PSV-1701/02
Sea water return from 75-E-05A/B
7.6
11.
PSV-1703/04
Sea water return from 75-E-06A/B
7.6
12.
PSV-2001
First HDS Reactor
36.5
13.
PSV-2101
First HDS heater outlet
31
14.
PSV-2201
Fuel gas KOD
9.0
Template No. 5-0000-0001-T2 Rev A
Copyrights EIL- All rights reserved
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
S. No.
Tag No.
Description/Location
Doc No. Draft
Rev. A
Page 128 of 195
Set Pressure
(Kg/cm2g)
15.
PSV-2301/2301
Sea water return from 75-E-09A/B
7.6
16.
PSV-2401A/B
Flare from Separator drum
27.5
/2402
17.
PSV-2601
Flare from Amine Absorber
27.5
18.
PSV-2701A/B
Flare from Recycle Compressor K.O. Drum
27.5
19.
PSV-2801A/B
Recycle Compressor 75-K-01A Discharge
38.5
20.
PSV-2802A/B
Recycle Compressor 75-K-01B Discharge
38.5
21.
PSV-2803
Recycle Compressor 75-K-01A Discharge 13
(Regen. Case)
22.
PSV-2804
Recycle Compressor 75-K-01B Discharge 13
(Regen. Case)
23.
PSV-2901/2902
Sea water return from 75-E-12 A/B
7.6
24.
PSV-3001A/B
Flare from Stabiliser Column
9.0
25.
PSV-3002
Stabilizer reboiler condensate pot
40
26.
PSV-3101/3102
Sea water return from 75-EE-14A/B
7.6
27.
PSV-3201/3202
Corrosion inhibitor pump discharge
13.7
28.
PSV-3203/3204
Sulfiding agent injection pump discharge
32
29.
PSV-3205
Corrosion inhibitor drum
10.5
7.8
RELIEVE VALVE LOAD SUMMARY
List of safety valves is already given in the previous section. Detail of relive
load summary such as relieve valve tag, location, set pressure, capacity, failure
scenarios considered are given in Flare Load Summary.
Flare Load Summary is given in Annexure IV.
Template No. 5-0000-0001-T2 Rev A
Copyrights EIL- All rights reserved
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
7.9
Rev. A
Page 129 of 195
DETAIL OF INTERLOCK LOGIC AND TRIPS
Sr.
CAUSE
No.
1
Doc No. Draft
EFFECT
ACTUATOR
DESCRIPTION
DEVICE
75-LAHH-1103
Very high level in 75-UV-
ACTION
DESCRIPTION
Close
FCC gasoline feed
Close
Hydrogenated
SHU feed surge 1101
drum
75-UV1102
2
75-PALL-1604
Very low pressure 75-P-03
at
gasoline recycle
stop
75-P-03A/B operating
discharge
75-P-03
protection
Start
spare
3
75-LALL-1701
Low level
75-P-
5
6
75-LALL-1505
C-01
chimney 75-P-05
tray level low
A/B
75-AT-2101
High O2 content
75-UV-
75-TAHH-
Very High temp in 2101
1403-1415
75-R-01
75-HS-1102A
Case of fire
75-UV-
Spare pump auto
start
Stop
04A/B
4
Pump 75-P-03 A/B
Light
gasoline
pump stops
Stop
FCC
heart
cut
pump stop
close
Air make up during
regeneration
Close
Close
SHU
feed
surge drum bottom
1104
inventory valve
75-HS-1102A
75-P-
Stops
Stop 75-P-01 A/B
Close
Boot drain to OWS
Close
VHP steam to 75-
01A/B
7
75-LALL-1106
Very low level in 75-UVSHU feed surge 1103
drum boot
8
75-PAHH-1510 Very
pressure
high 75-UVat 1503
E-07 stop
splitter overhead
Template No. 5-0000-0001-T2 Rev A
Copyrights EIL- All rights reserved
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
9
75-TAHH-2103 Very high temp in 75-F-01
10
75-HS-
any of the pass at
2102A/B
heater O/L
75-HS-
HDS
2401A/B
section
2502
depressurization
75-UV-
reaction 75-UV-
Rev. A
Page 130 of 195
Stop
Heater shutdown
Close
LP steam to lean
amine preheater
Lean
Close
amine
to
Amine absorber
2503
75-UV-
Doc No. Draft
HDS
Open
reaction
section
2403
depressurization
75-UV-
Stop feed to HDS
Close
reaction section
1901
75-UV-
Close
H2 make up
Stop
HDS heater burning
2702
75-F-01
off
75-UV-
Close
HC to stabilizer
Close
Rich
2401
75-UV-
to
amine unit
2601
75-UV-
amine
Close
3001
Close
stabilizer
bottom
product
valve
75-UV-
Recycle
Close
isolation
2701
75-UV-
Recycle
Close
comp
isolation
2801
75-P-
comp
Stop
Stop 75-P-01A/B
Actuate
Recycle comp KOD
07A/B
I-117
interlock
Template No. 5-0000-0001-T2 Rev A
Copyrights EIL- All rights reserved
OPERATING MANUAL FOR
FCC NAPHTHA HYDRO TREATER UNIT,
VRCFP, HPCL VISAKH
I-122
Actuate
Doc No. Draft
Rev. A
Page 131 of 195
Amine
Low
absorber
Low
level
interlock
11
75-LALL-2403
Very low level in 75-UVseparator drum
12
75-LAHH-2406
HC to stabilizer
Close
BFW feed
Close
Rich
2401
Very high level in 75-UVseparator
Close
drum 2301
boot
13
75-LALL-2602
Very low level in 75-UVAmine absorber
14
75-LAHH-2704
Very high level in 75-Kcomp KOD
15
75-FALL-2801
2601
Very low flow at 75-UV-
amine unit
Stop
Stop Recycle comp
Close
Stop feed to HDS
1901
75-F-01
75-LALL-3002
to
01A/B
comp discharge
16
amine
Very low level in 75-UVstabilizer bottom
reaction section
Stop
Heater shutdown
Close
Close
3001
75-P-
stabilizer
bottom valve
Stop
Stop 75-P-07A/B
Actuate
Recycle
01A/B
17
75-HS-2801A
Case of fire
I-117
comp
shutdown
75-UV-
75-HS-2801B
Close
Close
75-PALL-3107
Very low pressure 75-P-09
at
75-P-09
discharge
Stop
A/B operating
75-P-09
75-HS-3002A
Case of fire
75-UV3001
Template No. 5-0000-0001-T2 Rev A
comp
Pumps 75-P-09A/B
protection
Start
spare
19
Recycle
isolation
2801
18
comp
isolation
2701
75-UV-
Recycle
Spare pump auto
start
Close
Close
stabilizer
bottom valve
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OPERATING MANUAL FOR
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75-HS-3002B
20
75-LALL-2502
75-P-07
Very low level in 75-UVamine KOD
21
75-LALL-2702
RGC KOD
22
75-FALL-1903
Close
Hydrocarbon liquid
drain
Close
75-UV-
Close
Stop feed to HDS
reaction section
Close
H2 make up from
OSBL
75-TALL-2003- Very high temp in 2702
23
Hydrocarbon/Amine
liquid drain
HDS feed pump 1901
discharge
Page 132 of 195
Stop 75-P-07A/B
2703
Very low flow at 75-UV-
Rev. A
Stop
2501
Very low level in 75-UV-
Doc No. Draft
2019
first HDS reactor
75-F-01
Stop
Heater shutdown
75-AT-2101
High O2 content
75-UV-
Stop
Air to heater during
75-TAHH-
Very high temp in 2101
2003-2019
HDS reactor 75-
regeneration
R-02
24
75-LALL-2407
Very low level in 75-UVseparator
Close
drum 2402
Close sour water to
SWS
boot
25
75-PALL-2407
Very low pressure 75-P-
Stop
at quench pump 06A/B
discharge
protection
Start
spare
LAL-3301
75-P-06
operating
75-P-06
26
Pump
Low level in CBD 75-P-11
Spare pump auto
start
Stop
CBD pump
Start
CBD pump
Close
CBD Drain line
Open
CBD Drain line
drum
LAH-3301
High level in CBD 75-P-11
drum
27
LAL-3401
Low level in Flare UV-3401
KOD
LAH-3401
High level in Flare UV-3401
KOD
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28
PAHH-
High-high
3012A/B/C
pressure
UV-3002
Close
at
Doc No. Draft
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Page 133 of 195
VHP steam supply
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.
¾ The purpose of process:
− To perform the desulfurization of the gasoline. Regarding product
specifications, refer to the process book.
− To limit octane losses.
¾ The operating parameters used to meet these specifications with an optimum
catalyst life are the following:
− Reactors inlet temperature
− Make-up hydrogen and recycle hydrogen flowrates leading to the hydrogen
partial pressure at outlet of the reactors, the hydrocarbon partial pressure, the
hydrogen sulfide partial pressure.
− The space velocity (i. E. Feed rate).
Operator action on these parameter enables the unit to match different feed
and product qualities provided they are within the basis of design of the unit.
7.10.2 REACTOR TEMPERATURE
1. Selective Hydrogenation section:
A temperature increase favors di-olefin hydrogenation but also olefin
hydrogenation and coking, which reduces the cycle length. Moreover a high
temperature can lead to excessive vaporization in the reactor which is
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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 500C
and controlled by the liquid quench between the first and second bed and
between second and third bed. Some part of the hydrogenated product from the
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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.
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b) Higher sulfur content
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 H2 excess is too high, it
could lead to excessive vaporization of naphtha creating problems in distribution
and pressure drop in the reactor. It would result in excessive loss of light FCC
gasoline at the splitter vent gas and excessive olefin saturation.
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The hydrogen rate is set to decrease the MAV in the heavy FCC gasoline
product below 2.
b) Second section - HDS reactor 75-R-02
The hydrogen partial pressure is defined by the following formula
ppH2 = reactor outlet pressure ×
number of H 2 moles
number of total moles
The ppH2 at reactor outlet is a function of:
¾ The total pressure (which is fixed at the design stage and is beyond the reach
of operators).
¾ 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).
¾ 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 ×
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number of moles of hydrocarbons
number of total moles
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The ppHC is a function of:
¾ The total pressure.
¾ The hydrocarbon contents i.e. feed rate.
The hydrocarbon partial pressure has no impact on the hydrodesulfurization.
On the other hand, to minimize hydrogenation of olefins, it is necessary to
minimize olefin partial pressure therefore hydrocarbon partial pressure. For
instance, if the feed flowrate is 60% of the normal flowrate, it would be better not
to decrease the H2 flowrate. Indeed, the ratio H2/HC will increase and the
selectivity will be enhanced.
3. Hydrogen sulfide partial pressure
The ppH2S is a function of:
¾ The total pressure.
¾ The H2S content.
H2S
has
no
real
impact
on
olefin
hydrogenation
but
affects
hydrodesulfurization. Therefore, it is necessary to have a low H2S content to
enhance selectivity; this means to maximize the performance of the amine
absorber.
7.10.5 SPACE VELOCITY (FEED RATE)
Space velocity coupled with reactor inlet temperature defines the severity of
the hydrotreatment. Severity is increased when either the space velocity is
decreased or the temperature is increased.
Space velocity as defined earlier is the amount of liquid feed (expressed in
weight or volume) which is processed per hour divided by the amount of catalyst
(in weight or volume). The inverse of the space velocity is related to the
residence time or contact time in the reactor.
As the quantity of catalyst is fixed, the space velocity will change by varying
the feed rate. Decreasing the feed rate decreases the space velocity. At constant
temperature this increases the activity as there are now more catalyst active sites
per unit of feed. This will improve the hydrotreatment efficiency. For small
changes in the feed rate, no action is required by the operator. For large
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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:
¾ In case of feed is to be increased: first increase the temperature, then
increase the feed rate.
¾ 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.
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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.
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.
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SECTION- 8 SHUTDOWN PROCEDURES
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8.1
8.1.1
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NORMAL SHUTDOWN PROCEDURE
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:
¾ Exposing personnel to toxic or noxious conditions when equipment is drained
or depressurised.
¾ 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:
¾ Prepare blind lists and blind list accounting procedures for required isolations.
¾ Have test equipment onsite for:
− Explosive Gas and Hydrogen Analyzers
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− Oxygen Analyzers (If Vessel Entry is Planned)
¾ If inert atmosphere entry into the vessels is planned, have the necessary
personnel protective equipment on hand.
¾ Have the necessary materials onsite to complete the shutdown.
¾ Inform all interested parties of shutdown plans.
¾ Have temporary piping spools, blinds, gaskets, etc., onsite.
¾ Erect staging (scaffolding).
¾ Ensure adequate storage space is available in the off plot storage system.
¾ 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:
¾ Lower the capacity and if necessary the severity.
¾ Switch the product to off-spec. or raw storage.
¾ Shutdown the Reaction section.
¾ Drain all hydrocarbons.
¾ Depressurize and purge.
¾ Several shutdown cases are considered :
¾ Short duration shutdowns (i.e. less than 24 hours).
¾ Long duration shutdowns.
¾ Shutdowns to be followed by catalyst regeneration or inspection of equipment.
8.1.4
SHORT PERIOD SHUTDOWN
This shutdown is typically less than 24 hours to carry out minor repairs without
opening any major equipment.
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¾ Reduce unit capacity to 60% of normal feed rate. It should not be necessary
to adjust the reactor inlet temperatures immediately before the shutdown.
¾ Maintain hydrogen gas flow rate and make-up hydrogen through selective
hydrogenation reactor.
¾ Disconnect the level cascaded controllers on the separator drum 75-V-03, and
on the Stabilizer bottom while keeping normal flow rates.
¾ Switch the products to off-spec storage. (light cut, heart cut and heavy FCC
gasoline)
¾ 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.
¾ The make-up H2 supply to the selective hydrogenation reactor is also
stopped.
¾ 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.
¾ Close block valves on liquid flow outlet from the separator drum 75-V-03 when
level decreases below 30%.
¾ Shutdown DEA solution circulation through the Amine absorber and open the
bypass line of absorber.
¾ 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.
¾ Stop the fresh feed to the selective hydrogenation reactor 75-R-01.
¾ Close the block valves on the Splitter bottom. The SHU and HDS sections are
now isolated.
¾ The circulation of hydrogen through the HDS reaction section is continued for
a period of two hours to strip out hydrocarbons from the catalyst.
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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.
¾ The procedure described above for short period shutdown is followed, but
completed to full cooling of equipment to ambient temperature.
¾ 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.
¾ At temperature of 100°C at inlet to reactors 75-R-01, 75-R-02, the firing in
heater 75-F-01 stopped.
¾ 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.
¾ 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.
¾ Splitter and stabilizer sections are shutdown by closing steam to reboiler. The
air cooled condensers are shutdown and water flow to trim coolers closed
when pressure drops below 2 to 3 Kg/cm2g. The extended period of shutdown
requires to introduce nitrogen to the feed drum 75-V-01, and reflux drums 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
¾ 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.
¾ 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.
¾ The recycle compressor 75-K-01 A/B is isolated depressurized and purged
with nitrogen.
¾ The block valves on amine absorber are closed. The remaining amine
solution is drained to sewer. The absorber is filled with demineralized water.
¾ 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.
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The repeated operation allows to reach the decrease of hydrogen and
hydrocarbon concentration below the explosive limits. The explosive meter is
used to check the limit at which vessels can be opened for entry of atmospheric
air.
¾ 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.
¾ 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.
¾ 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.
¾ 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.
¾ 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.
¾ The stabilizer bottom should be sent to off-spec storage. The remaining liquid
must be drained. Take care not to pass hydrogen.
¾ 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.
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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
metal. These sulfides are pyrophoric and may release H2S. The forced
ventilation and permanent supervision is required on vessels subject to work
of personnel inside these vessels.
2. The nitrogen purge does not mean that vessel is ready for entering of
personnel. Nitrogen is suffocating gas leading to death. The vessels must be
fully vented and tested for oxygen content before admission of personnel
entry. The "dead" spaces in vessels such as down comers, separation weirs,
etc. must be considered.
8.2
UNIT 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:
¾ Start the columns at total reflux by admission of steam to reboiler and inert
naphtha via start-up lines.
¾ Re-pressurize the reaction section to the operating pressure.
¾ Start the 75-P-01 A/B pumps and feed the selective hydrogenation section at
60% of normal flow with raw gasoline.
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¾ The 75-E-03 feed steam heater is started by admission of steam.
¾ 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.
¾ The HDS reaction section is started with circulation of hydrogen gas through
the recycle compressor 75-K-01 A/B.
¾ The heater 75-F-01 is put in service and temperature gradually increased up
to 180°C.
¾ 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.
¾ 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.
¾ When the product is on specification, slowly increase feed flowrate in steps of
5% up to 100%.
¾ 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
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EMERGENCY SHUTDOWN PROCEDURE
GENERAL
Emergencies must be recognised and acted upon immediately. The
operators and supervisory personnel should carefully study in advance, and
become thoroughly familiar with, the steps to be taken in such situations. While
some of the emergencies listed in this section may not only result in a unit
shutdown, they could cause serious trouble on the unit if not handled properly. In
addition, damage to the catalyst might occur. In general the objective of the
emergency procedures is to avoid damage to equipment and catalyst.
Hard and fast rules cannot be made to cover all situations, which might arise.
The following outline lists those situations, which might arise and suggested
means of handling the situation.
¾ Emergency shut down by Operators
¾ Loss of feed
¾ Loss of cooling water
¾ Lack of hydrogen make-up
¾ Loss of Amine
¾ Quench pump failure
¾ Fuel gas failure
¾ Steam failure
¾ Instrument air failure
¾ Power Failure
¾ 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:
¾ Stop the feed steam heater 75-E-03.
¾ Close the H2 make-up supply.
¾ Shut-off the liquid feed to the reaction section.
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¾ Fully bypass SHU preheat train exchanger 75-E-01 and 75-E-02.
¾ Stop LCN pump 75-P-04A/B
¾ Stop FCC heart cut pump 75-P-05 A/B.
HDS reaction section:
¾ Shut-off the heater 75-F-01.
¾ Stop the feed to the reactor.
¾ If necessary, cool the reactor down through circulation of hydrogen.
¾ When possible, the H2 circulation is maintained.
¾ Otherwise, stop the compressor 75-K-01 A/B.
¾ Close the H2 make-up.
¾ Close the inlet/outlet lines on the Amine absorber.
¾ Close the liquid outlet on the separator 75-V-03.
¾ Close the purge gas on outlet of 75-C-02.
¾ Close water outlet on the separator and BFW feed at upstream of 75-A-03air
cooler.
¾ 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:
¾ Personnel having a satisfactory knowledge of the safe operating and
shutdown procedures.
¾ A compliance with the safety rules in plant construction i.e. safety distances,
adequate orientation etc.
¾ The installation of adequate fire and gas detection devices and fire fighting
equipment.
¾ Adequate operator safety awareness and procedures training.
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Concerning the catalyst preservation, operators must avoid :
¾ 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.
¾ 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 startup.
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:
¾ Stop the heater 75-E-03.
¾ Close the H2 make-up supply.
¾ Reduce the unit capacity to 60% of the feed capacity.
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¾ Switch the products to off-spec storage.
¾ Stop the unit feed when the reactor temperature is at least 10°C below the
normal temperature.
¾ Close the LCN line (from draw off tray) to storage and stop LCN pump 75-P04A/B.
¾ Close the FCC heart cut line (from draw off tray) to storage and stop FCC
heart cut pump 75-P-05A/B.
¾ Allow the splitter to operate on total reflux.
If interruption is to take place for several hours, short shutdown procedure
should be implemented.
When flow to the reactor is re-established, start H2 feed and return to previous
operating temperatures if the feed is shortly recovered.
HDS section:
In case of short period loss of feed to the HDS section,
¾ Maintain H2 circulation.
¾ Allow the stabilizer to operate on total reflux.
¾ When the level in the stabilizer starts to fall, close the valves on the stabilizer
bottom and heavy FCC gasoline line to storage.
¾ Maintain these conditions until feed is available again. Maintain pressure in
the HDS reaction section by hydrogen make-up.
Start-up again from former current reactor operating temperature if the feed is
recovered shortly. If not proceed with the normal shutdown as previously
explained (Refer to section “Shutdown of the unit/ Normal shutdown/ Short
duration shutdowns”). Do not leave catalyst under a hot hydrogen circulation for
more than 12 hours, unless the H2S content in the recycle is maintained between
100-200 ppm vol. Note also that an increased H2S content while circulating hot
hydrogen would be the sign of a catalyst desulfiding and would require the
cooling down of the catalyst bed.
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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.
¾ 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.
¾ Increase the air coolers to their maximum capacity if possible.
¾ Increase vapor purge in HDS section to recover H2 recycle purity as much as
possible.
¾ 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 H2S 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.
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FUEL GAS FAILURE
The HDS reactor feed heater will shutdown shutdown as well as the reboiling
of the splitter and stabilizer.
¾ Cut raw gasoline feed immediately and proceeds as per loss of feed.
¾ 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.
¾ Cut raw gasoline feed completely, as unstable gasoline product with H2S
cannot be sent to storage.
¾ 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:
¾ Initiate the I-102 for stopping H2 make up and steam to steam heater 75-E03.
¾ 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.
¾ Isolation of the feed and make-up gases
¾ Isolation of the product lines by closing control and block valves.
¾ Closing of block valve downstream control valve FV-2901 on stabilizer bottom
outlet line.
¾ Shut-off steam to the reboiler of stabilizer and splitter.
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¾ Maintain pressure in the reaction section. If necessary, inject nitrogen in the
stabilizer to maintain pressure.
¾ 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.
¾ 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.
¾ In addition, the general philosophy is to restart the equipment in the following
order:
-
Air fin cooler
− The compressor, in order to resume the hydrogen circulation and cool down
the reactors or to maintain the reactors inlet temperature after restarting the
heater.
− The reflux pumps of the column, in order to bring under control the overhead
temperature and pressure.
¾ 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.
¾ Shut-off fuel to heater by activating the fuel gas emergency shutdown system
from the control room.
¾ Shutdown the raw gasoline feed pump, close the splitter and stabilizer feed
and block-in.
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¾ Shut-off steam to the reboiler of the splitter and stabilizer, and to the SHU
feed steam 75-E-03.
¾ Isolate the unit: Block the feed, product and hydrogen make-up gas lines.
¾ Isolate the reaction section from the feed, splitter and stabilizer sections.
¾ 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.
¾ Depressurize the splitter and stabilizer sections to the flare.
¾ Drain all the vessels to the hydrocarbon blowdown.
¾ As the depressurized hot vessels cool down, watch the pressure and inject N2
as necessary to avoid a vacuum.
¾ 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:
¾ Protecting the operators.
¾ Protecting the equipment and the catalyst.
¾ 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
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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
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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.
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
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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.
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
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uncontrolled rate. Never tap the line to release the plugging. Call the
maintenance gang to properly unplug the line. In case of congealing type
samples, sample point should be equipped with copper coil type steam tracer.
It should be ensured that steam tracing line is functioning normally.
4. The operator taking the sample should be careful to stand in a position such
that the liquid does not splash on him and he has unobstructed way out from
the sample point in case of accident.
5. While taking dangerous toxic material for sampling, it will act as an observer
for safety. Proper gas mask is to be used. It is advisable to stand opposite to
wind direction in case of volatile toxic liquid.
6. Sample should be collected in clean, dry and stoppered bottle. In case of
congealing samples use clean dry ladle.
7. Rinsing of the bottle should be thorough before actual collection.
8. Before collecting, ensure that the line content has been drained and fresh
sample is coming.
9. Gradually warm up the sample bottle / metallic can by repeated rinsing before
collecting the sample.
10. Stopper the bottle immediately after collection of sample.
11. Attach a tag to the bottle indicating date, time, and name of the product and
tests to be carried out.
12. A few products suffer deterioration with time.
For example, the colour of the heavier distillates slowly deteriorates with time.
So these sampls should be sent to laboratory at the earliest after collection.
1. The samples after collection should be kept away from any source of ignition
to minimise fire hazard.
2. Volatile samples (e.g. naphtha) should be collected in bottles and kept in ice
particularly for some critical test like RVP.
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b) High Pressure Hydrocarbon Liquid Samples (Flashing Type)
The person who is taking sample should use personal protection appliances
like apron, gas mask and hand gloves to protect himself.
1. Ensure that sample bomb is empty, clean and dry.
2. Connect the sample bomb inlet valve to the sample point with a flexible hose.
3. Open the inlet and outlet valves of the sample bomb. Hold the sample bomb.
Hold the sample bomb outlet away from person. Keep face away from
hydrocarbon vapour and stand in such a way that prevalent wind should blow
hydrocarbon vapour away. Open the gate valve of sample point slowly till full
open. Then slowly cracks open the regulating valve. One should be careful at
the time of draining, because chance of icing is there. As a result, the
formation of solid hydrates is a continuing process that leads to the plugging
of valves.
4. When all the air in the hose and bomb are displaced as seen by the
hydrocarbon vapour rising from the outlet of sample bomb close the sample
outlet valve. Allow a little quantity of liquid to spill to make sure that the bomb
is receiving liquid. Frosting will be an indication of liquid spillage.
5. Allow liquid hydrocarbon to fill the bomb. When the bomb is full up to the
specified level, close both the valves on sample point. Close inlet valve on the
sample point.
6. Carefully disconnect the hose from the sample bomb. To allow for some
vapour space in the bomb for thermal expansion in case of overfilling, crack
open the outlet valve of bomb and discharge a small part of the liquid. Close
outlet valve.
7. Closed sampling facilities are provided at some locations where it is not
desirable to waste the costly product or if the material is toxic. For filling the
sampling bomb, pressure drop across a control valve is usually utilised or
across pump discharge & suction. Air is expelled from the bomb after it is
connected to upstream of control valve or pump discharge side. The sample
is then collected and bomb is detached after closing valves on both sides.
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8. Send sample bomb to laboratory for analysis. Protect the bomb from heat
exposure.
c) Gas Sample
For collection of gas sample that are not under high pressure and
temperature, rubber bladders are used. For the operations under vacuum or low
pressure, aspirator is used. For representative sample, purge the bladder 3 to 4
times with the gas and then take t he final sample. Use of 3 ways valve with
bladder / aspirator will facilitate purging and sampling.
Sample bombs are to be used for taking gas samples from high pressure and
high temperature source. Procedure mentioned under high pressure liquid
sampling (flashing type) is to be used.
Sampling method and schedule:
Sr. No.
Stream
1
Feed
Cold
Method
Frequency/day
ASTM D86
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 Distillation
FCC1&2
2
Analyse
feed
storage
from Mercaptans
Olefins
IFP
0104
/ 1
ASTM D1319
3
HDS feed
Template No. 5-0000-0001-T2 Rev A
Bromine number
ASTM D-1159
1
Diene (MAV)
IFP 9407
2 per week
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
ASTM 2700
1
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SHU H2 make up
Gas
Rev. A
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IFP 9603
1
IFP 9603
1
IFP 9603
As required
chromatography
5
HDS H2 make up Gas
from isom unit
6
7
chromatography
HDS H2 make up Gas
from CCR unit
chromatography
Effluent 75-R-01
Olefins
IFP
0104
/ As required
ASTM D1319
8
Light
FCC
ASTM D-1159
As required
Diene (MAV)
IFP 9407
2 per week
Diolefin content
IFP 0104
As required
ASTM D86
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
FCC Distillation
gasoline
9
Bromine number
heart
cut Mercaptans
gasoline
Olefins
IFP
0104
/ As required
ASTM D1319
10
11
Splitter
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
RVP
NF M 07-007
As required
IFP 9603
As required
reflux Gas
drum off gas
chromatography
Stabilizer feed
Total sulphur
D-2622 As required
ASTM
after
H2S
washing
Olefins
IFP
0104
/ As required
ASTM D1319
Template No. 5-0000-0001-T2 Rev A
Bromine number
ASTM D-1159
As required
Diene (MAV)
IFP 9407
As required
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12
HDS purge gas
Gas
Doc No. Draft
Rev. A
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IFP 9603
As required
Dragger tube
As required
IFP 9603
As required
Dragger tube
As required
IFP 9603
1
Dragger tube
1
ASTM D86
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
H2S
13
Recycle
gas
amine
to Gas
chromatography
H2S
14
Recycle gas from Gas
amine
chromatography
H2S
15
Heavy
FCC Distillation
gasoline
0104
/ As required
ASTM D1319
16
Stabilizer
gas
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
As required
ASTM D 1293
As required
purge Gas
chromatography
H2S
17
HDS
separator PH
sour water
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SECTION- 12 SAFETY PROCEDURE
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12.1
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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.
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12.2.4 SAFETY SHOWER AND EYE WASH
Safety shower and eye wash stations are located in the chemical handling areas.
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:
¾ Pressure versus temperature diagram,
¾ Rate of temperature increases and decreases,
¾ Rate of pressurizing and depressurizing the reactor,
¾ 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.
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Operators must continually inspect each equipment and flanges for leaks.
All leaks require immediate action. The pressure reduction results in heating of
hydrogen contrary to hydrocarbons, or other gases which are cooled down
(Joule-Thomson effect). When heated above its ignition temperature by pressure
release from high pressure the hydrogen gas starts to burn in presence of air.
Hydrogen sulfide H2S
a)
Physical 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.
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A concentration of 1000 ppm of hydrogen sulfide in air can make person
suddenly unconscious with early cessation of respiration and death in a few
minutes.
Hydrogen sulfide is a combustible material and, when mixed with air or
sulfur dioxide, may be explosive. It is essential, therefore, to avoid such mixtures
in the processing of hydrogen sulfide. The explosive range of hydrogen sulfide in
air is from 4.5-45%. The ignition temperature of such mixtures is around 250°C.
Some precautions against poisoning to be taken in working with hydrogen
sulfide are:
¾ Closed in areas should be well ventilated preferably with forced draft.
¾ Equipment containing hydrogen sulfide should be tightly sealed. Any leaks
should be repaired immediately.
¾ 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.
¾ Vessels should be purged of hydrogen sulfide before being opened.
¾ Masks furnishing purge air should be worn by personnel who are likely to be
exposed to the gas.
¾ Personnel who may be exposed to even low concentrations of this gas should
frequently retire to areas of fresh air.
¾ 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.
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e)
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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.
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:
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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.
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:
¾ Electric and gas welding
¾ Any machine capable of producing a spark
¾ Not explosion-proof electrical equipment
¾ Internal combustion engines
¾ 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:
¾ Disconnecting of lines for the insertion of blinds, etc
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¾ 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 H2S and
flammable gases should also be performed before entry. A person should also be
on alert outside the enclosed space for rescue in case of emergency. Procedure
for carrying out work and rescue plan shall be formulated before commencement
of work.
d) Guidelines for release of permits
¾ 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.
¾ 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.
¾ 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.
¾ 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.
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¾ 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.
¾ If welding or hot work is to be done ensure that
− Fire fighting system is ready
− Close the neighbouring surface drains with wet gunny bags
− Keep water flowing in the neighbouring area to cool down any spark.
− Responsible operation supervisor should be present at the place of hot work
till the first torch is lighted.
12.5
PREPARATION OF EQUIPMENT FOR MAINTENANCE
a) Process Equipment: Towers, Vessels etc.
Before opening any equipment, it should be purged to render the internal
atmosphere non-explosive and breathable. Operations to be carried out are: ¾ Isolation with valves and blinds.
¾ Draining and depressurisation.
¾ Replacement of vapours or gas by steam, water or inert gas.
¾ Take care about instrument tapping.
¾ Washing of towers and vessels with water.
¾ Ventilation of equipment.
¾ Opening of top manhole.
¾ Testing of inside atmosphere with explosive meter.
¾ Complete opening if inside atmosphere is satisfactory.
¾ 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,
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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.
¾ Assure that equipment is isolated by proper valves and blinds.
¾ Ascertain that there is no pressure of hydrocarbons in the lines, vessels and
equipment.
¾ Purge the system with N2 first and later by air and check for O2 content at vent
and drain to ensure that the vessel is full of air.
¾ Check that steam injection lines and any inert line connections are
disconnected or isolated from the equipment.
¾ Provide tags on the various blinds to avoid mistakes. Maintain a register for
blinds.
¾ Check for pyrophoric iron and if existing, keep this wet with water.
¾ Keep the surrounding area cleaned up.
¾ Get explosive meter test done in vessels, lines, equipment and surrounding
areas.
If welding or hot work is to be done, also:
¾ Keep fire-fighting devices ready for use nearby.
¾ Close the neighbouring surface drains with wet gunny bags.
¾ Keep water flowing in the neighbouring area to cool down any spark bits etc.
¾ 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.
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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.
The most common tasks of a Licenser technical advisor that requires
potentially hazardous vessel entry are:
¾ Unit Checkout Prior to Start-up
¾ Turnaround Inspections
¾ 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
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drain connections in the same or adjoining units.
Doc No. Draft
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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.
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.
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Wearing of a Safety Harness
Any person entering a vessel should wear a safety harness with an
attached safety line.
The harness should be strong and fastened in such a
manner that it can prevent a fall in the event the man slips and so that it can be
used to extricate the man from the vessel in the event he encounters difficulty. A
parachute type harness is preferred over a belt because it allows an unconscious
person to be lifted from the shoulders, making it easier to remove him from a tight
place such as an internal man way.
A minimum of one harness for each person entering the vessel and at least
one spare harness for the people watching the man way should be provided at
the vessel entry.
Providing a Man way Watch
Before a person enters a vessel, there should be a minimum of two people
available outside of the vessel, one of who should be specifically assigned
responsibility to observe the activity of the people inside of the vessel. The other
person must remain available in close proximity to the person watching the man
way so that he can assist or go for help, if necessary. He must also be alert for
events outside of the vessel, which might require the people inside to come out of
the vessel, for example, a nearby leak or fire. These people should not leave
their post until the people inside have safely evacuated the vessel.
A communication system should be provided for the man way watch so that
they can quickly call for help in the event that the personnel inside of the vessel
encounter difficulty. A radio, telephone, or public address system is necessary
for that purpose.
Providing Fresh 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
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procedure. Each point of entry and any dead areas inside of the vessel, such as
receiver boots or areas behind internal baffles, where there is little air circulation
should be checked.
Fresh air can be circulated through the vessel suing an air mover, a fan, or,
for the cases where moisture is ca concern, the vessel can be purged using dry
certified instrument air from a hose or hard piped connection. When an air mover
is used, make certain that the gas driver uses plant air, not nitrogen, and direct
the exhaust of the driver out of the vessel to guarantee that this gas does not
enter the vessel. When instrument air is used, the Licenser technical adviser
must confirm the checking of the supply header to ensure that it is properly lined
up. It should be confirmed that there are no connections where nitrogen can enter
the system (Sometimes nitrogen improperly used as a backup for instrument air
by some refiners). The fresh air purge should be continued throughout the time
that people are inside of the vessel. The responsible control room should be
informed that instrument air is being used for breathing so that if a change to
nitrogen is required the people are removed from the affected vessel.
A minimum of one fresh air mask for each person entering the vessel and at
least one spare mask for the Manway watcher should be provided at the vessel
entry. These masks should completely cover the face, including the eyes, and
have a second seal around the mouth and nose. When use of the mask is
required, it must first be donned outside of the vessel where it is easy to render
assistance in order to confirm that the air supply is safe. Each mask must have a
backup air supply that is completely independent of the main supply. It must also
be independent of electrical power. This supply is typically a small, certified
cylinder fastened to the safety harness and connected to the main supply line via
a special regulator that activates when the air pressure to the mask drops below
normal. The auxiliary supply should have an alarm, which alerts the user that he
is on backup supply and it should be sufficiently large to give the user 5 minutes
to escape from danger.
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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
protect the internals from corrosion.
An additional hazard is imposed by
operations in other parts of the plant, which may be beyond the control of the
people entering the vessel. For these reasons vessel entry procedures must still
be rigorously followed during the checkout of a new unit.
The oxygen content of the atmosphere inside of the vessel should be
checked before every entry and the vessel should be blinded.
Independent
blinds at each vessel nozzle are preferred. However, in the event that many
vessels are to be entered in a new unit, which is separate from the rest of the
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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
vessel should be limited and frequent breaks should be taken outside of the
vessel.
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12.7
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Page 186 of 195
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.
The operating crew should be acquainted with exact
location of the extinguishers. They also must know most suitable type, which,
when and how to use an extinguisher. For example, electrical fires should be put
out with CO2 or dry power extinguishers; water and foam should not be used.
The used extinguishers should be checked and restored by fire station personnel.
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Doc No. Draft
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Page 187 of 195
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.
Foot protection
Safety shoes are to be worn for foot protection.
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Page 188 of 195
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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Page 189 of 195
SECTION- 13 GENERAL OPERATING INSTRUCTIONS FOR
EQUIPMENT
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13.1
Doc No. Draft
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Page 190 of 195
GENERAL
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
¾ Inspect and see if all the mechanical jobs are completed.
¾ Establish cooling water flow where there is such provision. Also open steam
for seal quenching in pumps having such facilities.
¾ Check oil level in the bearing housing, flushing may be necessary if oil is dirty
or contains some foreign material.
¾ Rotate the shaft by hand to ensure that it is free and coupling is secure.
Coupling guard should be in position and secured properly.
¾ Open suction valve. Ensure that the casing is full of liquid. Bleed, if necessary,
from the bleeder valve.
¾ Energise the motor. Start the pump and check the direction of rotation. Rectify
the direction of rotation if it is not right.
¾ Check the discharge pressure. Bleed if necessary to avoid vapour locking.
¾ 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
¾ Close discharge valve fully.
¾ Stop the pump
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a) If pump is going to remain as standby and has provision for keeping the pump
hot, proceed as follows:
¾ Open the valve in the by-pass line across the discharge valve and check
valve.
¾ 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:
¾ Close suction and discharge valves.
¾ Close valve on check valve by-pass line, if provided.
¾ Close cooling water to bearing, if provided.
Also shut off steam for seal
quenching, if provided.
¾ 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.
¾ Blind suction and discharge and check valve by-pass line and flare connection
if any.
¾ Cut-off electrical supply to pump motor prior to handling over for maintenance.
Trouble Shooting
a) Pump not developing pressure
¾ Bleed to expel vapour/air
¾ Check the lining up in the suction side.
¾ Check the suction strainer.
¾ Check the liquid level from where the pump is taking the suction the suction.
¾ Check pump coupling and rotation.
¾ Get the pump checked by a technician.
b) Unusual Noise
¾ Check the coupling guard if it is touching.
¾ Check for proper fixing of fan and fan cover.
¾ Check for pump cavitations.
¾ Get the pump checked by a technician.
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c) Rise of Bearing Temperature
Generally the bearing oil temperature up-to 800C or 500C above ambient
whichever is lower, can be tolerated.
¾ Arrange lubrication if bearing is running dry or oil level is low.
¾ Adjust cooling water to the bearing housing, if there is such provision.
¾ Stop the pump, if temperature is too high, call the pump technician.
d) Hot Gland
¾ Adjust cooling water if facility exists.
¾ Slightly loosen the gland nut, if possible.
¾ Stop the pump and hand over to maintenance.
¾ Arrange external cooling if pump has to be run for sometime.
e) Unusual Vibration
¾ Check the foundation bolts.
¾ Check the fan cover for looseness.
¾ Stop the pump and hand over to maintenance.
f) Leaky Gland
¾ Check the pump discharge pressure.
¾ Tighten the gland nut slowly, if possible.
¾ Prepare the pump for gland packing or adjustment/replacement of mechanical
seal as the case may be.
g) Mechanical Seal Leak
¾ Stop and isolate the pump and hand over to maintenance.
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13.3
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Page 193 of 195
HEAT EXCHANGERS
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:
¾
Water Coolers/condensers
¾
Steam heaters (Reboiler)
¾
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.
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START-UP
After the heat exchanger has been pressure tested and all blinds removed,
proceed as follows:
¾ 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.
¾ 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.
¾ 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.
¾ 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.
¾ 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.
¾ Check for normal inlet and outlet temperatures. Check that TSVs are not
popping.
¾ The operation of inlet and outlet valves should be done carefully ensuring that
the exchangers are not subjected to thermal shock.
¾ In case of coolers/condensers, adjust the water flow to maintain the required
temperature at the outlet.
¾
For avoiding fouling, velocity of water should be at least 1 m/sec in a
cooler/condenser.
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¾
Doc No. Draft
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Page 195 of 195
Shutdown
Shut down of an exchanger, coolers, condenser is considered when the equipment
is to be isolated for handling over to maintenance while the main plant is in
operation. The following is the suggested procedure for isolation of the piece of
equipment
•
Isolate the hot medium first. In case both hot and cold medium are from
process streams, exchanger shall remain in service till the hot stream has
cooled down enough.
•
In case of a cooler, adjust cooling water flow to the cooler, which is in line so that
product temperature is within allowable unit.
•
Isolate the cold medium next.
•
Drain out the shell and tube sides to OWS/Sewer/Closed blow down system as
applicable. In case flushing oil connection is given flush the exchanger to CBD.
Ensure that the CBD drum has sufficient usage to receive the flushing of the
exchanger
•
Depressurise the system to atmosphere/flare/blow down system as applicable.
•
Purge/flush if required. This is particularly important in congealing services.
•
Blind inlet and outlet lines before handing over the equipment for maintenance.
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