Description
2500-15-00-80-001
Operating Manual LGO Hydrotreating unit (Unit 15)
Revision : R – 1 Date : 19/03/2020 Page : 1 of 185
INTEGRATED MANAGEMENT SYSTEM REFINING OPERATIONS
Operating Manual LGO Hydrotreating unit (Unit 15)
1
19/03/2020
Changes as per Corporate Internal Audit July 2019
OPK/1
OPK/2
OPK
0
28 /11 / 18
Issued For Review and Approval
OPK/1
OPK/2
OPK
REV.
DATE
PRPD
CHKD
APPD
DESCRIPTION
Operating Manual LGO Hydrotreating unit (Unit 15)
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CHAPTER 1: TABLE OF CONTENTS Chapter 1 Table of Content Chapter 2
Unit Design Basis
Chapter 3
Theoretical Description of the Process
Chapter 4
Process Flow Description
Chapter 5
Material and Heat Balances with Physical and Thermal Properties of the Streams
Chapter 6
Major Equipment Items and Their Purpose or Functions
Chapter 7
Description of Process Instrument Interlocks
Chapter 8 Chapter 9 Chapter 10
Preparation for Initial Start-Up Unit Start-Up Procedure Unit Normal Operation
Chapter 11
Normal Shutdown Procedure
Chapter 12
Emergency Shutdown Procedure
Chapter 13
Detailed Description of All Unit Utilities
Chapter 14
Special Procedures
Chapter 15
Quality and Analytical Control Including Sampling Procedure
Chapter 16
Trouble Shooting
Chapter 17
Advanced Process Control (APC) Strategies
Chapter 18
Corrosion Aspects
Chapter 19 Chapter 20 Chapter 21 Chapter 22 Chapter 23 Chapter 24
Environmental Aspects Safety Recommendations Unit Performance Monitoring Equipment Summary Lists Instrument Summary Lists Drawings
Chapter 25
H2S Monitoring
Chapter 26
List of Vendor’s Operating Instruction Manuals
Operating Manual LGO Hydrotreating unit (Unit 15)
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CHAPTER 2: UNIT DESIGN BASIS 2.1 UNIT CAPACITY The hydrotreater is designed to process 17,000 BPSD (112.7m3/hr) of light gas oil from the crude unit 11. ( currently the unit is running above design capacity by 10% more after simulation calculations confirmed equipment capability). 2.2 DESIGN FEED Light gas oil feed properties are shown on Table 1. Hydrogen makeup properties are also shown on Table 1. Hydrogen makeup will normally be supplied from the Naphtha Hydrotreater Unit 12. 2.3 DESIGN PRODUCT LGO product calculated properties are shown on Table 2. 2.4 MODES OF OPERATION The hydrotreater will process LGO from the crude unit during crude runs on blends ranging from 50/50 to 80/20 Dukham D/Dukham C respectively. For design, the gas oil feed volume is the same for both cases. The hydrotreater is designed for start of run (SOR) and end of run (EOR) modes of operation charging gas oil from the 50/50 blend crude. All equipment designed for this case will be capable of processing 80/20 blend gas oil. Operating conditions are shown in the Haldor Topsoe Basis for Design, Hydrotreating Unit 15. 2.5 ONSTREAM FACTOR AND TURNDOWN RATIO Onstream factor is 90% (330 days per year). All equipment has been specified to enable operation at 50% of normal flow. 2.6 BATTERY LIMIT CONDITIONS Battery limit conditions are shown in Table 4.
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Operating Manual LGO Hydrotreating unit (Unit 15) TABLE 1
LIGHT GAS OIL HYDROTREATER, UNIT 15 FEED AND MAKEUP GAS COMPOSITION
Makeup Gas Vol. Percent
Feed Case
50/50
80/20
Feed Rate, BPSD
17000
17000
Feed Rate, Std M3/H
112.6
112.6
Std Process(SG)
50/50
80/20
H2O
0
0.27
H2S
0.53
0.19
H2
82
84.65
0.857
0.853
C1
5.3
3.32
50.8
57.7
C2
5.12
3.85
Sulphur, WT%
1.2
1.05
C3
4.4
3.99
Nitrogen, WT PPM
28
30
IC4
0.64
0.61
NC4
1.35
1.73
Cetane Index (from Assay)
Aromatics, Liq Vol% Mono-Aromatics
Note (1)
16.5
13.5
IC5
0.32
0.39
Di-Aromatics
Note (1)
6.5
5.5
NC5
0.34
0.51
Tri-Aromatics
Note (1)
4.5
3.5
C6+
0
0.49
27.5
22.5
100
100
2.5
2.5
1
182
184
5
234
235
10
247
247
30
266
262
50
277
279
70
309
304
TOTAL VISC. CST @ 50C ASTM D-86 C
Vol %
TOTAL
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Operating Manual LGO Hydrotreating unit (Unit 15)
Note (1)
90
330
335
95
343
344
EP
350
349
The aromatics analysis has been estimated by Haldor-Topsoe from typical laboratory data. It has not been derived by Parsons from the Assay. TABLE 2 GAS OIL HYDROTREATER
GAS OIL PRODUCT FEED CASE
50/50
80/20
SOR
EOR
SOR
EOR
0.844
0.845
0.83
0.83
Sulphur wppm
500
500
500
500
Nitrogen wppm
6
6
9
9
50.8
49.5
60.9
59.7
69
64
79
76
IBP
147
133
170
168
10%
239
232
242
236
30%
260
254
257
252
50%
274
269
274
268
70%
304
300
299
293
90%
330
325
329
324
FBP
347
340
349
344
Specific gravity @ 15.6C
Cetane index, ASTM D-976-80 Flash point Distillation deg. C
Note:
1. 50/50 case properties calculated from Pro2 simulation, except sulphur and nitrogen data from Haldor Topsoe. 80/20 case properties from Haldor Topsoe except flash point estimated.
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TABLE 3 LIGHT GAS OIL HYDROTREATER OPERATING PARAMETERS Feed Case Run Phase
50/50 Star-of-Run
50/50 End-of-Run
17,000 112.6
17,000 112.6
1.3 1.89 4.18
1.3 1.89 4.18
316 347 339 347 338 38
362 388 381 388 380 32
1551D Inlet
49.8
51.5
1551D Outlet
49.1
49.5
1501D Inlet
49.0
49.4
1501D Outlet
48.0
48.0
Treat Gas to Reactor Inlet
23,500
24,880
Inter-Reactor Quench
5,070
3,660
Recycle Gas H2 Purity, mol %3
79.2
74.0
Treat Gas H2 Purity, mol %
79.9
76.0
Wash Water Rate, kg/hr4
3,857
3,857
Capacity, BPSD Std m3/hr Space Velocity, v/v-hr Overall 1551D 1501D Reactor Temperature, C 1551D Inlet 1551D Outlet1 1501D Inlet 1501D Outlet1 Reactor Average Bed2 Total Temperature Rise, C Reactor Pressure, bar abs
Treat Gas Rates (Recycle + Makeup), Nm3/hr
Note:
1. The reactors are operated with equal bed outlet temperatures by adjustment of the quench temperature setpoint. 2. Average bed temperature is weighted by catalyst volume and temperature profile in the catalyst bed. 3. The recycle gas hydrogen content has been calculated by simulation based on the yields and makeup hydrogen composition and with the following assumptions. (a) high pressure separator temperature of 57C, (b) high pressure separator pressure of 45.5 bara, (c) recycle gas amine scrubber removes all H2S and ammonia, (d) the purge gas is 4 volume percent of the scrubbed gas. 4. Wash water is continuous. The rate is equivalent to 3.4 volume percent of feed. Water rate has to be sufficient to maintain at least 20 percent liquid water at injection point.
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Operating Manual LGO Hydrotreating unit (Unit 15) TABLE 4 GAS OIL HYDROTREATER, UNIT 15 BATTERY LIMIT CONDITIONS
Feeds
Press., barg
Temp., C
From
Gas Oil Feed (Cold)
3.0
25
Unit 21
Gas Oil Feed (Hot)
2.2
149
Unit 11
Makeup Hydrogen
30.1
41
Unit 12
Press., barg
Temp., C
To
Product Gas Oil
5.5
57
Unit 21
Wild Naphtha
6.3
57
Unit11 or Unit61
Sour Water
2.5
57
Unit 11
Fuel Gas
3.75
65
Unit 16
Sour Fuel Gas
4.3
49
Unit 16
Light Slop
5.5
57
Unit 21
Products
Utilities & Others LP Steam Steam Condensate Cooling Water Supply Cooling Water Return Process Water (Cold Condensate) Fuel Gas Fuel Oil Instrument Air Plant Air Nitrogen Potable Water Service Water Raw Water DMDS Caustic
Press., barg
Temp., C
From/To
6.9 2.5 3.8 2.3 4.5 3.7 8.0 7.0 7.0 7.0 3.1 - 4.5 7.0 - 12.0 3.1 - 4.5 4.2 12
173.0 139 35 43.5 60.0 43.0 50.0 40.0 40.0 40.0 30.0 - 43.0 30.0 - 43.0 30 - 43 48 45
From Unit 51 To Unit 51 From Unit 22 To Unit 22 From Unit 51 From Unit 10 From Unit 10 From Unit 52 From Unit 52 From Unit 52 From Unit 51 From Unit 54 From Unit 21 From Unit 46 From Unit 43
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Note: For the detail of the battery limit conditions, refer to the attached sheet No.1. 2.7 UTILITY REQUIREMENT Utility Requirement figures are shown in Table 7. 2.8 CHEMICAL & CATALYST REQUIREMENT Chemical & Catalyst Requirement figures are shown in Table 5 1) Catalyst and Inerts Specifications The principal desulfurization catalyst for this unit is 1.3 mm three-lobed TK-554. This catalyst will be sock loaded in both reactors. In addition,a graded bed system is utilized at the top of the new reactor’s first bed to provide protection against fouling. The graded bed system incorporates a 150 mm topping layer of high void inert 16 x 11 mm tableted TK-10, a 300 mm layer of 5 mm ring shaped TK-550 catalyst and a 300 mm layer of 3 mm ring shaped TK-550. The high void inert 16 x 11 mm tableted TK-10 is also used for a 150 mm topping layer on the catalyst bed in the existing reactor. These catalysts have the following loaded densities: Density, kg/m3 TK-10 800 TK-550 3-mm ring and 5-mm ring 500 TK-554 1.3-mm three-lobed 810
Method Sock Sock Sock
The following presents the overall catalyst requirements for this unit: Catalyst Designation Catalyst Type Size Catalyst Volume, m3 Catalyst Weight, Kg
TK-554 CoMo 1.3 mm (1/20-inch) three-lobe 82.4 57,700
Catalyst Designation Catalyst Type Size Catalyst Volume, m3 Catalyst Weight, Kg
TK-550 CoMo 5 mm (3/16-inch) ring 2.12 1,060
Catalyst Designation Catalyst Type Size
TK-550 CoMo 3 mm (1/8-inch) ring
Operating Manual LGO Hydrotreating unit (Unit 15) Catalyst Volume, m3 Catalyst Weight, Kg
2.12 1,060
Catalyst Designation Catalyst Type Size Catalyst Volume, m3 Catalyst Weight, Kg
TK-10 Inert 16x11-mm tablet 1.80 1,440
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Each of the catalyst beds of The TK-554 is supported by a system of inert designed to provide a stable support with minimum pressure drop. Most of the bottom head of each reactor is filled with 19 mm inerts. That is topped with a 75 mm layer of 6 mm inerts and a 3 mm inerts. The minimum distance from the top of the outlet cover at the bottom of the reactor to the bottom of the 6 mm inert layer is 150 mm. The catalyst can be loaded into the head as long as the cross sectional area of the catalyst is not less than 80 percent of the shell cross sectional area. Inert Type Size Inert Depth, per bed, mm Total Volume (both reactors), m3
Ceramic 3-mm spheres or pellets 75 1
Inert Type Size Inert Depth, per bed, mm Total Volume (both reactors), m3
Ceramic 6-mm spheres or pellets 75 1
Inert Type Size Inert Depth, per bed, mm Total Volume (both reactors), m3 2) Chemicals
Ceramic 19-mm spheres or pellets Fill head 8
Sulfiding Agent – Catalyst Sulfiding Provide 11,600 kilograms of Dimethyl Disulfide for use as a catalyst sulfiding agent during start-up. The quantity of sulfiding agent specified represents an amount sufficient for the initial start-up sulfiding operation. An equivalent amount should be ordered prior to the process unit shutdown for catalyst regeneration or catalyst change out. Caustics
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Provide 266,000 kilograms of 15 oBe caustic to neutralize reactor effluent gases for the regeneration of the catalyst. An equivalent amount of caustic should be provided for each subsequent catalyst regeneration. Soda Ash & Sodium Nitrate Provide 3,500 kilograms of soda ash (Na2CO3) with 500 ppm by weight maximum chloride content, and 350 kilograms of sodium nitrate (NaNO3). An aqueous soda ash neutralizing solution of 70 cubic meters is required for neutralizing of the austenitic stainless steel lining in the reactor section. The solution shall contain 5 weight percent soda ash, 0.5 weight percent sodium nitrate and the chloride content must be less than 50 ppm by weight. Corrosion Inhibitor Provide 230 kg of Nalco EC1021A or equivalent corrosion inhibitor (filming) for corrosion protection in the gas oil product stripper overhead system. The above quantity represents approximately 12 months supply at normal injection rates. 2.9 UNIT PERFORMANCE GUARANTEE Unit performance guarantee figures are shown in Table 6.
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Operating Manual LGO Hydrotreating unit (Unit 15) TABLE 5 CHEMICAL & CATALYST SUMMARY Catalysts
Consumption Service
Catalyst (1501D & 1551D)
Type
TK-10 Inert 16x11mm tablet
Initial Filling
Life Time
[m3]
Cont. /Batc h
per year
3 months
[years]
[m3]
[m3]
1.8
1)
-
-
Batch Sock loading
Remarks
Catalyst (1551D)
TK-550 3/16”&1/8” rings, CoMo
4.24
1)
-
-
Batch Sock loading
Catalyst (1501D & 1551D)
TK-554 1.3mm(1/20inch) three lobe
82.4
1)
-
-
Batch Sock loading
Inert Ball (1501D & 1551D)
3 mm spheres or pellets
1
-
-
-
Batch
Inert Ball (1501D & 1551D)
6 mm spheres or pellets
1
-
-
-
Batch
Inert Ball (1501D & 1551D)
19 mm spheres or pellets
8
-
-
-
Batch
1) Minimum 2 years for the 1st cycle life and 4 years for the ultimate life.
Chemicals
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Operating Manual LGO Hydrotreating unit (Unit 15) Consumption Service
Catalyst Sulfiding Agent Corrosion inhibitor (Filming)
Type
DMDS Nalco EC1021A
Initial Filling
Life Time
[m3]
[years]
Cont. /Batc h
per year
3 months
[kg]
[kg]
1)
1)
1)
Batch
1.0 2)
230
57
Cont.
Caustic(15 oBe)
15 oBe Caustic
-
3)
3)
Batch
Neutralizing Agent
Soda Ash (Na2CO3)
-
4)
4)
Batch
Neutralizing Agent
Sodium Nitrate (NaNO3)
-
4)
4)
Batch
Remarks
1) 11,600 kg of DMDS for catalyst sulfiding during start-up and after catalyst regeneration. 2) 1.8kg/day of corrosion inhibitor diluted with LGO. It is injected to 1501E on 1 to 40ppm. Chemical type and cons umption is preliminary and to be finalized according to the vendor’s information. 3) 266,000 kg of pure caustic to neutralize reactor effluent gases for the regeneration of the catalyst. 4) 3,500 kilograms of soda ash (Na2CO3) and 350 kilograms of sodium nitrate (NaNO3) for neutralizing of the auste nitic stainless steel lining in the reactor section.
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Operating Manual LGO Hydrotreating unit (Unit 15) TABLE 6 UNIT PERFORMANCE GUARANTEE
Unit 15
Remarks Revamp of Unit 15
Description
Gas Oil Hydrotreater
Designer
Haldor Topsoe / RM Parsons
Subject to conditions 1. The Gas oil feed shall be substantially as follows:
Feedstock maximum specified by Haldor-Topsoe
Composition ASTM D-86 deg c
50/50
80/20
Vol% 1 182
184
5 234
235
10 247
247
30 266
262
50 277
279
70 309
304
90 330
335
95 343
344
344 max.
EP 350
349
350 max.
2. The make-upgas shall be substantially as follows: Composition Vol%
Case 50/50
Case 80/20
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Operating Manual LGO Hydrotreating unit (Unit 15) Water
0
0.27
Hydrogen Sulphide
0.53
0.19
Hydrogen
82.00
84.65
Methane
5.3
3.32
Ethane
5.12
3.85
Propane
4.4
3.99
Iso Butane
0.64
0.61
Normal Butane
1.35
1.73
Iso Pentane
0.32
0.39
Normal Pentane
0.34
0.51
Haxane
0
0.49
3. Feed properties :
Feedstock maximum specified by Haldor-Topsoe
Specific gravity @ 15.6 deg c
0.857
0.853
0.857 max.
Sulphur content wt%
1.2
1.05
1.2 max.
13.5
16.5 max.
di-aromatics 6.5
5.5
6.5 max.
tri-aromatics 4.5
3.5
4.5 max.
Aromatic content vol% mono aromatics 16.5
Water content
no suspended water or free water
Cetane index
50.8
57.7
Nitrogen wt ppm
28
30
4. Guaranteed Feed capacity : Gas oil throughput bpsd
17,000
from assay
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Operating Manual LGO Hydrotreating unit (Unit 15) 5. Product Specification Guarantees : Sulphur content wppm
500 max.
500 max.
ASTM D-86 90% point
338 oC max.
338 oC max.
Cetane index ASTM D-976-80
Shall not be less than the Cetane index of the feed
Yield wt%
93.9
94.3
Start of Run Pressure Drop for new reator (bar)
1.1 (max.)
Start of Run Pressure Drop for old reator (bar)
1.7(max.)
Flash point oC
60 (min.)
Copper corrosion
Of the similar TBP fraction in the feed
Max. No. 1
5. Catalyst Guarantees : Catalyst Life First Cycle
24 calandar months
( Table 6. continued)
Unit 15
Remarks
Ultimate catalyst life Hydrogen consumption Nm3/m3 Oil
48 calandar months 47
40
The above table lists the unit capacities, composition and properties guaranteed by open art unit process designer.
TABLE 7-1
UTILITY SUMMARY (NORMAL)
2500-15-00-80-001
Operating Manual LGO Hydrotreating unit (Unit 15)
Equip. Duty Item No.
1502C 1504C 1504C1 1505C 1503J 1503JA 1504J 1504JA 1505J 1505JA 1506J
Moto r pow er
Service
mmkcal/ hr
1501C1 1503C1 1506C 1507C
Rated powe r
Exchangers Reactor Stripper Stripper Off Reactor Air Coolers Reactor Gas Oil Trim Gas Oil Trim Stripper Pumps Gas Oil Feed Spare for Wash Water Spare for Stripper Spare for Gas Oil
(kW)
(kW)
13.7 9.53 0.295 1.21 10.76 1.435 1.435 0.844
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Steam (ton/hr)
HP
MP
40 bar g
13. 9 bar g
LP
6.9 bar g
LLP
3.5 bar g
LLL P 0.7 bar g
BF W
Treate d water
Con d
Los s
Coolin g
Plant
Inst.
Water
Air
Air
m3/hr
Nm3/ hr
Nm3/ hr
-29.7
-11x2 -6x2
15x4 15x2 5.5x2 7.5x2
-308 (-15.4 (-8.5 (-8.5) -102
345 (345) 30 (30) 11 (11) 132
-2.7
N2
Nm3/ hr
Fuel
kcal/ hr
2500-15-00-80-001
Operating Manual LGO Hydrotreating unit (Unit 15) 1506JA 1507J 1502LJ 1501B 1502B 1501J1/ J2 1501JA1 / JA2 1502J 1502JA 1501L
Spare for Caustic Corrosion Fired Reactor Stripper Compressor Recycle/Ma ke-up Spare Gas for 1501J1/J2 Sour Gas Spare for ETC Ejector
(-7.69 -0.27
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(132) 13.1 0.37
-2.7
2.92 3.8
-2.92 -3.77 -469
590
-8
-8
-2
(469) -155 (-
(590)
(-8)
(-8)
(-2)
180 (180)
-7 (-7)
-8 (-8)
-2 (-2)
Miscellaneo
-
2.2
Total NOTES: +Indicates quantity produced. – Indicates quantity consumed
2.2
( ) Indicates spare service, not included in totals.
-25
-50.1
-41
-4
-6.69
Operating Manual LGO Hydrotreating unit (Unit 15) TABLE 7-2 UTILITY SUMMARY (MAX)
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2500-15-00-80-001
Operating Manual LGO Hydrotreating unit (Unit 15)
Equip. Duty Item No.
1502C 1504C 1504C1 1505C 1503J 1503JA 1504J 1504JA 1505J 1505JA 1506J
Mot or pow er
Service
mmkcal/ hr
1501C1 1503C1 1506C 1507C
Rate d powe r
Exchangers Reactor Stripper Stripper Off Reactor Air Coolers Reactor Gas Oil Trim Gas Oil Trim Stripper Pumps Gas Oil Feed Spare for Wash Water Spare for Stripper Spare for Gas Oil
(kW)
(kW)
13.7 9.53 0.325 1.21 10.76 1.435 1.435 0.844
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Steam (ton/hr)
HP
MP
40 bar g
13. 9 bar g
LP
6.9 barg
LLP
3.5 bar g
LLL P 0.7 bar g
BF W
Treate d water
Con d
Los s
Cooli ng
Plant
Inst.
Water
Air
Air
m3/hr
Nm3/ hr
Nm3/ hr
-32.7
-11x2 -6x2
15x4 15x2 5.5x 7.5x
-308 (-15.4 (-8.5 (-8.5) -102
345 (345) 30 (30) 11 (11) 132
-2.7
N2
Nm3/ hr
Fuel
kcal/ hr
2500-15-00-80-001
Operating Manual LGO Hydrotreating unit (Unit 15) 1506JA 1507J 1502LJ 1501B 1502B 1501J1/ J2 1501JA1 / JA2 1502J 1502JA 1501L
Spare for Caustic Corrosion Fired Reactor Stripper Compressor Recycle/Ma ke-up Spare Gas for 1501J1/J2 Sour Gas Spare for ETC Ejector
(-7.69 -0.27
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(132) 13.1 0.37
2.92 3.8
-2.7
(-12)* (-
(-
-469
590
-8
(469) -155 (-
(590)
(-8)
180 (180)
-7 (-7)
Miscellaneo
-8(100)* (-8(100)* -8((-8(-
-2(316)* (-2(316)* -2 (-2)
(-2.21
Total (-12)* NOTES: +Indicates quantity produced. – Indicates quantity consumed ( ) Indicates spare service, not included in totals.
(780)* ((780)*
-6.35 -5.39
2.2
2.2 ( )* Indicates intermittent service
-25
-53.1
(-
(*1) : The sum of possible simultaneous consumption
(-
(-
-
Operating Manual LGO Hydrotreating unit (Unit 15)
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CHAPTER 3: THEORETICAL DESCRIPTION OF THE PROCESS 2.4 CHEMISTRY OF THE PROCESS 3.2.1
Introduction
The main hydrodesulphurisation purpose is to eliminate the major amount of sulfur components contained in the charge, and to improve the product qualities by taking into account pollution, corrosion and odour specifications. The nitrogen compounds are hydrogenated, and the catalyst retains the metallic components. The existing olefins are saturated improving the product stability. The reactions are exothermic, and aid in release of hydrogen sulphide and ammonia. A hydrogen gas recycle limits the coke deposits on the catalyst. 3.2.2
Reactions
In this complex feed, many chemical reactions can take place. The most important ones are: Hydrogenation of olefins and aromatics. Hydrodesulphurization. Hydrodenitrification. Decomposition of oxygenated components. Hydro-demetallization . 3.2.2.1
Hydrogenation reactions
1) Olefins: Under operating conditions needed by the hydrodesulphurization, olefins are quickly hydrogenated. If hydrogen partial pressure is too low, and temperature too high, they can give a cracking parasite reaction with an important coke deposit and alteration of the catalyst. The reaction of olefin saturation is highly exothermic. 2) Aromatics: Aromatic hydrocarbons are more difficult to saturate owing to the presence of sulphur. The reaction depends on the hydrogen partial pressure, and takes place preferentially on polynuclear aromatics that have an olefinic character. This reaction is highly exothermic, and improves the product quality.
Examples of these reactions are presented below: HDA:
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Operating Manual LGO Hydrotreating unit (Unit 15) TOLUENE
METHYL R
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Heat of reaction at 25C (kcal/mol) :
R
+
-22.2 x 103
3H2
R-NAPHTALENE R
+
2H2 Not available
R-TETRALIN R
+
3H2 Not available
The reaction of hydrogen with the aromatic compounds present in the feed is reversible. At higher temperatures or at lower hydrogen partial pressure, the rate of the reverse (dehydrogenation) reaction increases relative to the hydrogenation reaction. The amount of conversion of aromatics decreases as the reactor temperature is increased above approximately 675F. At the end of run, the amount of di and tri-aromatics in the product will be greater than at the start of run. 3.2.2.2 Desulphurization Reaction The types of reactions that occur in the reactor that involve sulphur compounds include reactions of mercaptans, sluphides, disulphides, thiophenes, benzo-thiophenes and dibenzothiophenes. Hydrogen sulphide is formed in the reactor as a result of these reactions. An example of these reactions is shown below: HDS : THIOPHENE
N-BUTANE +
4H2
Heat of reaction at 25C (kcal/mol) : -62.5 x 103
C4H10 + H2S
S C4H4S
DI-BENZOTHIOPHENE BENZOTHIOPHENE + S C8H8S
DI-PHENYL ETHYLBENZENE +
3H2 + 2H2 C8H10
S C12H8S
C12H10
H 2S + H2S
-37.5 x 103 -21.9 x 103
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All of these reactions consume hydrogen and are highly exothermic. The amount of hydrogen consumed per weight percent of sulphur in the feed is dependent on the types of sulphur species that are present. Only the most difficult to remove sulphur compounds remain thiophenes that have an alkyl group attached to the carbon atom or atoms adjacent to the sulphur atom. Two of these compounds are 4-methyl di-benzo-thiophene and 4,6 di-methyl-di-benzo-thiophene. 3.2.2.3 Hydrodenitrification Reaction Nitrogen is contained essentially in heterocyclic compounds. Hydrodenitrification is a more difficult reaction than hydrodesulphurization. As for sulphur, nitrogen in heavy compounds may be decomposed in intermediate products, and with high severity the ultimate product will be ammonia. Part of the nitrogen and oxygen containing organic compounds that are present in the feed to the unit is converted in the reactor, producing ammonia and water as a by-product. The content of nitrogen and oxygen compound is very small for the design feed. Very little hydrogen is consumed by these reactions. The importance of the denitrogenation reactions to form ammonia is that the ammonia formed can react with hydrogen sulphide or any chlorides present in the makeup gas or feed to from solid deposits in the colder equipment in the unit. These deposits are controlled by the addition of wash water. Examples of the types of denitrogenation reactions occurring in the reactor are shown belows: HDS : INDOLE
Heat of reaction at 25C (kcal/mol) :
ETHYLBENZENE
+
6H2
+
NH3
-82.2 x 103
+
NH3
-44.1 x 103
H H
C8H7H
C8H10
CARBAZOLE
DI-PHENYL
+
5H2
H H
C12H8H
3.2.2.4
C12H10
Hydrocracking Reactions and other reactions
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Although hydrocracking reactions occur in the reactor, the amount of hydrogen consumed by these reactions is small. These hydrocracking reactions are also exothermic and result in a temperature increase across the reactor. At the start of the run, when the reactor average temperature is low, very little hydrocracking takes place. As the reactor temperature is increased, the rate of hydrocracking also increases. The net result is an increase in light gas (methane, ethane, propane, butane) and naphtha formation as the catalyst ages. The average boiling point of the desulphurised distillate also decreases from the start to the end of the catalyst cycle. Other reactions such as demetallization, hydrogenation of phenolic compounds, improvement of Conradson Carbon etc., take place at the same time as desulphurization and Hydrogenation reactions, but with different velocities depending on the severity of the operation. 3.4
PROCESS VARIABLE
The principal operating variables of the hydrogenation reactions are the following
Temperature,
Pressure,
Space
Mole
Charge quality.
3.3.1
velocity, ratio
of
hydrogen/hydrocarbon,
Temperature Every increase in temperature increases the hydrogenation reaction speed. However, the coke deposit also increases on the catalyst. So, it is necessary to find a balance between a catalyst life and complete hydrogenation. In fact, the minimum temperature permitting a suitable desulphurisation rate is set.
3.3.2
Pressure The pressure is normally maintained at a maximum compatible with the equipment. This pressure has a favourable effect limiting the coke deposit on the catalyst (increase of the hydrogen partial pressure), and promotes the hydrogenation of nitrogen compounds. The secondary reactions (saturation and hydrocracking) increase with the pressure, and increase the hydrogen consumption.
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Space Velocity (VVH) The space velocity is the residence time of the feed on the catalyst. It indicates the hourly flow rate of liquid fresh feed in a ratio to the volume of catalyst, and provides indications on the severity of the operation.
VVH
Hourlyflow rate of theliquidfreshfeed (㎥/hr) Volumeof catalyst(㎥)
The lower this number is, the greater the severity. In general, a low space velocity will improve the reactions. As the volume of catalyst is fixed, only changing the feed rate may vary the space velocity. A decrease of the feed flow rate (a decrease of the space velocity will promote the reactions and permit reduction in the temperature to the reactor. In the inverse case, an increase of the feed flow rate requires an increase of temperature. 3.3.4
Molar Ratio of Hydrogen to Hydrocarbons This ratio is defined by the number of hydrogen moles divided by the number of hydrocarbon moles in the reaction section. The greater this ratio is the smaller the coke deposit on the catalyst, thereby improving the hydrogenation reactions. This is why the quantity of hydrogen introduced in the reaction section includes the quantity needed for the hydrogenation reactions and a quantity going through the reactor without reacting, which increases the partial pressure of hydrogen. The recycled volume is greater than the one reacting.
3.3.5
Quality of the Feed The operating conditions vary according to the quality of the feeds. They will have a greater severity for feeds with a high end point of distillation and/or which have a greater content of impurities.
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CHAPTER 4: PROCESS DESCRIPTION 2.4 FEED, FEED PREHEAT, REACTIORS Cold feed at 25C from storage enters under flow control to the coalescer 1503L for water removal and then enters the feed surge drum 1501F. Hot feed to the LGO hydrotreater flows directly from the crude unit 11 light gas oil stripper and arrives hot (149C) at the battery limit under flow control in unit 11 and enters the feed surge drum 1501F. The design is based on 90% hot feed, 10% cold feed. Pressure on the surge drum is maintained with a fuel gas blanket. Feed from the surge drum is charged to the unit under level control using the gas oil feed pump suction line close to the vessel to allow vessel isolation during a pump seal failure and/or plant fire. Feed is preheated in the gas oil feed/reactor effluent exchanger 1501C1~4 and splits into two equal streams, the split controlled by a proportioning circuit on the feed level control loop. Each stream is mixed with treat gas which has been preheated in reactor feed gas/effluent exchanger 1507C and which also has been divided into two equal streams upstream on the mixing tee under proportioning flow control. The combined feed and treat gas is heated to reactor inlet temperature in the reactor charge furnace 1501B. Each half of the combined feed uses one heater pass. The hot charge from each heater pass enters desulphurisation reactor 1551D, then passes through 1501D. 3.4 REACTOR EFFLUENT COOLING AND PRODUCT SEPARATION Reacotr effluent is cooled in the gas oil feed / reactor effluent exchanger 1501C1~4 and the reactor feed gas/effluent exchanger 1507C. Effluent exchanger 1507C is mixed with washwater and the temperature is reduced in airCooled, reactor effluent cooler 1502C. The washwater consists of stripped sour water from unit 11 sour water stripper. A line and condensate drum 1509F has been added to dilute the stripped sour water from unit11with cold condensate from unit 51. Cooled effluent is separated into hydrocarbon liquid, sour water, and vapour phases in the HP flash drum 1502F. Hydrocarbon liquid is dropped in pressure under level control and enters the LP flash drum 1503F. Sour water is sent by level controller 15-LV-036 to the sour water-stripping unit for removal of hydrogen sulphide and ammonia. Disposition of the HP flash drum vapour is described in paragraph 4.3. A pressure control on the HP flash drum maintains the hydrotreater unit pressrue by adjusting the exiting purge gas (paragraph 4.3). Hydrocarbons entering the LP flash drum are separated into hydrocarbon liquid, sour gas, and a small amount of sour water. The sour gas is directed to the amine treating Unit16. Pressure control on the LP flash drum is maintained by adjusting sour gas flow. Sour water is sent to the sour water stripping unit. Flash drum liquids are charged to the light gas-oil product stripper 1501E as described in paragraph 4.4 4.4 AMINE TREATING, PURGE, MAKEUP AND RECYCLE GAS COMPRESSION, AND TREAT GAS HP flash drum vapour phase from 1502F is washed with monoethanol amine (MEA) in the recycle gas H2S scrubber 1502E to remove hydrogen sulphide. MEA is supplied to the battery limits at adequate pressure to enter 1502E without further pumping. A portion of the washed gas is purged to control the build-up of light hydrocarbons, the remainder of the gas enters the recycle gas compressor 1501J2 or 1501JA2 via the recycle gas K.O. drum 1507F.
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The emergency depressuring station is provided on the knockout drum overhead line. The depressuring orifice is sized for an initial depressuring rate of 6.9 bar per minute. The depressuring station is provided with an 15-Hs-030A which can be opened from the control room. Recycle gas from 1501J2/JA2 is mixed with makeup hydrogen discharging from the makeup gas compressor 1501J1/JA1. The makeup gas compressor takes suction from the hydrogen header which normally draws gas from the naphtha hydrotreater unit 12. Mixed recycle and makeup gas (treat gas) is preheated, and enters the reactor inlet as previously described in paragraph 4.1. 5.4 PRODUCT STRIPPING LP flash drum 1503F liquid (stripper feed) is dropped in pressure through a flow Controlled valve reset by 1503F level control. Stripper feed is heated to stripper inlet temperature in the stripper feed/effluent (stripper bottoms) exchanger 1503C. Feed enters the product stripper 1501E. Supplemental energy for stripping is provided by stripper reboiler 1502B. Stripper overhead is condensed in the stripper overhead condenser 1505C, combined with a small stream of condensate from the compressed gas K.O. drum 1506F (described below), and enters the stripper reflux drum 1504F. The hydrocarbon liquid from this drum is pumped with stripper reflux pump 1505J/JA back to 1501E as reflux with a small portion of the pump discharge drawn off to the crude distillation unit 11 as wild naphtha. Alternatively to condensate distillation unit 61. Sour water from drum 1504F is directed to the sour water stripper in unit 11. via new drum 1516F and new pump 1510J. PCR(15-10-001).
Sour gas from 1504F passes through stripper off-gas K.O. drum 1505F, is compressed with sour gas compressor 1502J/JA to sour fuel gas pressure, cooled in the stripper off-gas cooler 1506C, and passes through compressed gas K.O. drum 1506F. A small amount of condensate is removed from 1506F as wild naphtha to unit 11 or 61. The compressed sour gas combines with the sour off-gas from the LP flash drum (paragrpah 4.2), and is directed to the amine-treating unit 16. Stripper pressure is controlled by adjusting the recycle gas on the sour-gas compressor. Stripper bottoms are product light gas oil. The product is pumped with the gas oil product pump 1506J/JA under stripper level control and cooled by heat exchange with the stripper feed in stripper feed/effluent (stripper bottoms) exchanger 1503C1~6, and gas oil trim cooler 1504C/C1. A line is provided from the discharge of pump 1506J/JA for recirculation of product back to the feed drum. This is useful for start-up and also when battery limit feed is tempeorarily unavailable. Corrosion inhibitor is added via corrosion inhibitor tank 1502LF and pump 1502LJ into the stripper overhead line. This reduces the potential for corrosion in this sour service. 6.4 REGENERATION During regeneration, the unit is charged with nitrogen and circulation maintain with make-up and
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the recycle gas compressors. The make-up and recycle gas compressors 1501J1/J2 or 1501J2/JA2 may be used to maximse regeneration gas flow. The H2S scrubber 1502E is bypassed during the procedure. During the burning phase, air is introduced into the compressor suction with a portable compressor and closely monitored so that the oxygen concentration in the gas to the reactors is about 1~2%. Compressor discharge flows through the reactor feed gas/effluent exchangers 1507C and the reactor furnace 1501B and is heated to the reactor inlet temperature required for sustaining the catalyst burn. Flue gases from the reactor pass through the reactor effluent heat excahgners 1501C1~4 and 1507C. Sodium hydroxide (caustic soda) solution is injected into the flue gas stream and the mixture cooled in the effluent cooler 1502C. The caustic neutralises sulphur dioxide and a portion of the carbon dioxide formed in the reactor to prevent corrosion of the air cooler and downstream piping. Caustic is separated from the flue gases in the HP flash drum 1502F. Caustic is normally recirculated by caustic circulation pump, 1507J and blowdown stream of spent caustic removed. A portion of the flue gas is purged from the system to prevent build-up of carbon dioxide in the recirculating nitrogen. Fresh nitrogen is added to maintain the system pressure.
CHAPTER 5: MATERIAL AND HEAT BALANCE WITH PHYSICAL AND THERMAL PROPERTIES OF THE STREAMS 5.1
HEAT & MATERIAL BALANCE
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Operating Manual LGO Hydrotreating unit (Unit 15) 5.1
DETAILED MASS BALANCE – REACTOR SECTION
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CHAPTER 6: MAJOR EQUIPMENT ITEMS AND THEIR PURPOSE OR FUNCTION 6.1 REACTORS Contact of oil with hydrogen gas takes place in the presence of a catalyst in the reactors. Under the appropriate operating conditions of temperature, pressure, and time over the catalyst; the desulphurisation reaction takes place. Sulphur in the feed combines with hydrogen and enters the gas phase as hydrogen sulphide(H2S) which can readily be separated downstream of the reactor from the product oil. The gas oil is cleaned of sulphur to levels below 0.05% weight. Two reactors are required for holding sufficient catalyst to provide a liquid hourly space velocity of 2.5 needed to achieve gas oil desulphurisation to 0.05% weight maximum in the product gas oil. The existing reactor 1501D is designed to contain 27m3. With addition of the new reator 1551D, the total catalyst volume will be nominally 60m3. The new reactor will be added upstream in series with the existing reactor. Placing the reactor in this position provides greater flexibility for adding reactor internals which may be required for installation of the distributor, distirbutor tray, and other equipment which may be necessary for provision of the graded catalyst bed. 6.2
COMPRESSORS
The make-up compressor supplies the hydrotreater with hydrogen from the naphtha hydrotreater hydrogen product header. The recycle gas compressor circulartes the gas which has been separated from the treated oil back to the reactor. The recycle gas is separated from oil in the HP flash drum and passes through the amine contactor in which the generated H2S is removed. The gas passes through the recycle gas compressor, mixes with the fresh hydrogen, is heated to reactor inlet temperature and contacted with oil in the reactor, is then cooled and finally separated from the oil to complete the loop. Both the make-up and recycle gas compressors are new for handling the operating conditions required for the revamped hydrotreater. The recycle compressor will be required to circulate nitrogen during startup, presulphiding, and regeneration and appropriate notes have been added to the compressor data sheets. Installation of flange with valve for chemical cleaning /steaming facilities for de-plugging Cooling system for both compressor of unit 15 during normal operation and shutdown to avoid higher temperature. PCR No (15-11-005). In case of higher gas temperature of compressor, these facilities can be used for de-plugging the cooling water line via high pressure water / steam during normal operation.
The sour gas compressor increases the pressure of the off-gas from the product stripper to sour fuel gas header pressure upstream of the amine treating unit 16. Because of increased gas rates, two new compressors are required.
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REACTOR EFFLUENT EXCHANGERS, AIR COOLER, AND REACTOR HEATER
The reactor effluent exchangers conserve energy by warming the treat gas (incoming hydrogen plus recycle gas) and fresh gas oil with hot reactor effluent. As much heat as possible is removed from the reactor effluent stream to conserve fired heat required in the heater. Four new shells are required for the gas oil feed/reactor effluent service 1501C1~4 replacing the existing three shells. This permits a greater temperature cross and reduces the heat duty of reactor charge furnace 1501B. The existing shells in the reactor feed gas/effluent exchanger 1507C are too small to handle the increased reactor effluent flow and were replaced by one new shell. The reactor charge furnace 1501B heats reactor feed to the requird reactor inlet temperature. The existing heater was checked and found to be adequate for the new service. NODCO inspection reports (1993 and 1995) indicate that the airCooled reactor effluent cooler 1502C is severely fouled and may required major repairs or replacement. Until this is confirmed, it is assumed that a new air cooler is required. 6.4
DRUMS
All drums in the unit are adequate for the new service. Surge times in the predominantly liquid holding drums are as follows:
Feed surge drum HP Flash drum LP Flash drum Stripper reflux drum
Minutes 18 7 7 12
Other drums are adequate to handle the required gas flows and to separate entraind liquids. A gas-blanketed wash water drum has been added. The feed surge drum, stripper reflux drum, and stripper off-gas drum require increased nozzle sizes. New knockout drum (1515F) installed during 2013 to improve consistent refinery wide fuel gas heating value, remove impurities, and stabilize supply pressure and improving burner reliability. 6.5
PRODUCT STRIPPER
The product stripper removes H2S and light hydrocarbons from the hydrotreated gas oil. Removal of the light hydrocarbons ensures that the flash point is within specification. The product stripper is adequately sized for the new service and calculations indicate that the trays will be satisfactory. However, tray loads will be forwarded to the tray vendors for their check, as the vendors will provide a guarantee and may wish to perform tray modifications. The Gas Oil Product Stripper (1501E) is designed as follows :
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Operating Manual LGO Hydrotreating unit (Unit 15) Tray Location
:
#1-6
#7-22
No. of tray
:
6
16
Type of tray
:
Valve
Valve
No. of passes
:
1
2
Design Pressure Drop (bar)
6.6
0.3 (Total)
Diameter (mm)
:
1220
2750
Height (mm)
:
21,300 (Total)
Material
:
410S
AMINE TREATING
In the H2S scrubber 1502E, sour gas from the HP flash drum is washed with monoethanol amine (MEA) to remove hydrogen sulphide and ammonia. The column is adequately sized to handle the gas and increased liquid flow in the revamped unit, but the packing will require change to a type with lower pressure drop such as pall rings. 6.7
REBOILER (1502B)
The existing reboiler heater convection &radiation tube replacement of the existing coil of heater 1502b material changed during 2009 from carbon steel A106grb to 9Cr-1Mo to overcome high skin temperature& restricts increasing unit feed capacity.
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CHAPTER 7: DESCRIPTION OF PROCESS INSTRUMENT INTERLOCKS 7.1 PHILOSOPHY The objective of ESD/PSD system is to prevent undesirable event and minimize their consequences. It is activated in a critical situation in the unit to prevent the unit to go out of control and in case of leakage, fire and accidents. The system is designed to limit damages on environment and to minimize the risks on personnel. The levels of shutdown depend on the severity of the event and are configured to ensure safe and effective shutdown of the equipment/plant in a controlled manner. The shutdown levels comprise of 3 levels, which are according to the increasing levels of hazard. They are: a) Level 1 – Local equipment shutdown b) Level 2 – General facilities shutdown (no Blowdown) c) Level 3 – Post General facilities shutdown (Blowdown)
Note: Level 3 shutdown is the most severe and is activated only if Level 2 shutdown is active. Level 3 shutdown is activated manually only. 7.7.1
Level 1 – Local Equipment Shutdown The objective is to protect individual equipment.
7.7.2
Level 2 – General Facilities Shutdown The objective is to protect facilities and personnel in the event of serious process malfunction. The operator is responsible for taking the decision to activate this level of shutdown. In order to enable a quick restart in case of rectification of the problem within a reasonable length of time, no blowdown facilities are included.
7.7.3
Level 3 – Post General Facilities Shutdown (Blowdown) The objective is to minimize risk and to protect environment and personnel under upset conditions/emergencies.
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The operator is responsible for taking the decision to activate this level of shutdown. Level 3 shall only be activated if the facility has reached a Level 2 status. This is activated manually by a blowdown push button located on the CCR DCS console.
7.2
DESCRIPTION
No.2 GO Hydrotreater (Unit 15) is provided with three levels of shutdown, Level 1, Level2 and Level3. 7.7.1
Level 1 for Unit 15 This is detailed in the Cause & Effect Table in P&ID (Chapter 24) Drawing No. 7J48N-15-0030-005
7.7.2
Level 2 for Unit 15 This is activated by 15-HS-001A and 001B. 15-HS-001A is located in the CCR while 15-HS001B is in the field.
7.7.3
Level 3 for Unit 15
This is activated by 15-HS-030A. 15-HS-030A is located in the CCR while 15-HS-030B is in the field. Generally comments
Separate SIL study done for unit (15) as details report available.
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CHAPTER 8: PREPARATION FOR INITIAL START-UP 8.1 START-UP SEQUENCE The start-up is represented on the following preliminary precommissioning and start-up schedule. This schedule shows approximately when the successive operations should be carried out and the duration of these operations, from the checking of the unit until the performance test. This schedule may be modified following the local conditions and particularly buyer's requirements. 8.2 8.8.1
GENERAL PRECOMMISSIONING Hydrostatic Pressure Test should be given to exchanger supports, piping on fractionators where differential expansion can be a problem, and reactor circuit piping. The installation and orientation of vessel internals must be checked carefully. For the first start-up, it is necessary that several items be taken care of before the unit can be considered ready for oil. Most of these items might be considered as construction details, in as much as subsequent plant start-ups will not require the repetition of all of them. Such items may be summarized in action as follows 1) Clean and service utility systems. 2) Final inspection of vessels. 3) Washout lines and equipment and break-in pumps. Hydrostatic pressure tests are carried out in order to ensure that the lines and equipment will be able to withstand the normal operating pressures and temperatures. One exception to this rule is the reactor, which can be excluded since it has already been shop tested and special metallurgical considerations must be taken into account whenever such a vessel is pressured at low temperatures. The lines and equipment should be divided into convenient sections for hydrotesting. In any given section the pressure test applied should be equal to the allowable test pressure of the lowest rated equipment in the circuit. In hydrotesting sections which include heat exchangers, special care must be exercised to avoid exceeding the design differential pressure across the tube bundles, especially for exchangers in the reactor system. A temporary connection may have to be installed to ensure that both sides of the exchangers are pressured to the same level. Before the pressure test is concluded, exchangers must be tested at the design differential pressure to ensure that no
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leakage exists. The test pressure must be held until it is certain that the section being tested is tight, and all leaks have been eliminated. In addition to process lines, utility lines (steam, air, etc.,) should also be tested. The contractor and refinery personnel responsible for such tests must witness all pressure tests. In general operating staff is not involved in hydrostatic pressure tests that are carried out at the end of the construction period. 4) Plant Inspection The equipment must be checked to see that it conforms to the detailed P&I drawings and the Project Specifications. Attention should be given to the location of vents, drains, gauge glasses, pressure gauges, sample points, etc., to ensure that they are accessible. 5) There should be sufficient room for expansion when the unit is heated. Particular attention Break-in compressors 6) Service and calibrate instruments. 7) Pressure test equipment. The above outline may be expanded somewhat as follows 8.8.2
Clean and Service Utility Systems Following construction, the various utilities such as steam, cooling water, air, etc., must be put in service. The various lines must be tested for leakage and should be washed free of debris and construction trash. This latter may be done by water flushing and air blowing to atmosphere. Fuel gas lines must be steamed out or N2 purged to remove air before admitting gas. Steam lines should be warmed up slowly to prevent damage by water hammer. All steam traps and control valves in the system should be placed in service and tested. Likewise, control systems in the air, water, and fuel systems should be tested for operability. a)
Steam networks Networks shall be blown through completely from battery limit with a strong steam flow in order to clean the lines. The following steps are recommended.
check network, all equipments disconnected,
open slightly battery limit valve and let the temperature rise in the header, slowly and steadily,
when the line is hot, blow it through completely with a strong steam flow,
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close the battery limit valve and prepare another network.
When the blowing is satisfactory, reconnect all the equipment and remount the stream traps. Note: During the blowing operations, do not forget:
To drain the low points of lines during the heating period of the collectors in order to avoid water accumulation which causes water hammer, this also checks that the lines to steam traps are not plugged.
To open the vents during all the cooling periods to prevent creating a vacuum.
b) Condensate, treated and raw water Networks shall be cleaned with water from battery limit with strong water flow. c)
Cooling water Networks shall be cleaned from battery limit with a strong water flow. All the equipments will be disconnected at the inlet and reconnected when lines are cleaned. When the systems have been washed out, pressurize the lines to the operating pressure. Note : During the filling, do not forget:
To open the vents at high points in order to evacuate the air contained in the equipment and the piping.
To open the battery limit valves, slowly and steadily.
d) Instrument and service air Networks shall be blown through completely from battery limit with a strong air flow in order to clean and dry the lines. The instrument air system shall be tested pneumatically with dry air. All joints and connections shall be checked for tightness with soapy water solution. Heater and branch lines shall be blown through with a high flow rate of air. During all these tests, the instruments, supplied with air, shall be carefully isolated from the system.
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Fuel-gas and fuel-oil networks Networks shall be blown through from battery limit with a strong steam flow for fuel-oil and a strong air flow for fuel gas in order to clean the lines. During this operation, the orifice plates and control valves shall be removed. Note: Take care to prevent water entering the furnace.
f)
Sewers Sewer system is the first system to be prepared and placed in service, ready to receive the various discharges. It will be worked-up as follows: check peep holes and all drains, fill with water to ensure a steady fluid flow, check the oily water treatment.
8.8.3
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 and also cleaned. It is very important that the internals of the hydrotreating reactor be inspected very carefully. The hydrotreating 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 insure correct fit in the nozzles. The product separator should be checked carefully to be sure the cement lining is installed well, and that the mesh blankets is securely fastened to the support ring. There should be no gaps in the mesh blanket, which can occur at seams between sections or between the blanket and the vessel shel1. 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 tendency for brittleness increases. Temperatures above 17℃ (60℉) are considered satisfactory for testing to eliminate the possibility of cold fracturing of equipment. Such temperatures can be attained by warming the testing medium. If the unit contains any austenitic stainless steel, the chloride content of the test water must be less than 50 ppm. If this is not possible, then the test water should have 0.5% wt. sodium nitrate added to it.
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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, Test them first, 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 thermowall 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. 8.8.4
Wash Out Equipment and Break-in Pumps After the hydrostatic 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. A1l possible lines and pumps should be used during the washing procedure for complete clean-up of the system. Of course, no water circulation should be carried out in the gas sections of the Unit. 1) Vessels and lines flushing All towers and drums should be manually cleaned before flushing. The fire water system should be flushed first and can be used to supply water for flushing the rest of the plant. Before flushing, open overhead vents on vessels (to avoid vacuum), disconnect pump suctions and discharges, cover pump nozzles, and "drop out" or "roll" control valves and orifice plates. Open compressor headers and blank off compressors. Fill vessels with water and flush lines away from vessels or drums, especially if equipped with internals that could be fouled. All lines not flushed by vessel drainage must be flushed independently. Lines connected to exchangers should not be flushed into exchangers but the joint should be disconnected and the exchanger flange covered with a piece of sheet metal. After sufficient flushing, the line can be reconnected and water flushed through the
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exchanger to the next section of the line. Reconnect pump suction lines after initial flushing and insert 20 mesh or 30 mesh screen linings in pump strainer and continue flushing, changing to spare pump and cleaning strainers when plugged. This operation should continue until no debris is collected on the strainers. Any equipment flushed into should be opened and cleaned manually. Block valves or other valves not "rolled" or “dropped out" should be checked for closure and rolled out for cleaning as required. All equipment blinds not necessary during start-up should be removed during or after the flushing operation. All control valves and orifices should be installed when line flushing is completed. A mechanical flow diagram should be used as a cleaning "check-off" list. Check that lines to and from tankage are also flushed. 2) Inspection and running in of 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. 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. a)
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 all piping is installed, and that this piping is not mistakenly connected to the water system.
b)
Check arrangements to vent the pump for priming if the pump is not self-venting. See that special connections such as bleeds and drains are properly installed.
c)
Check strainers in pump suction lines. Strainers must be installed before aligning pumps. A three to six mesh strainer is provided for each pump suction line during startup. To avoid pump damage during flushing with water, the strainers should temporarily be lined with 20 mesh or 30 mesh screen. 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. d) Check that power or steam is available for running-in the pump. Check that: pressure gauges and any special instrumentation are in working order.
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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. e) Before lubricating oil-lubricated bearings, check bearing chamber in pumps to see that no slush compounds or shipping grease is left in the chamber. f) Mechanical type seals should be flushed with water prior to pump operation so no dirt gets into the seal and scores the seal faces. g) It is extremely important that the proper type and viscosity all and proper grade of grease is used to lubricate the equipment. Refer to manufacturer's instructions and refinery lubricating schedule for this information. h) 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. i) 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. j) 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. k) Start the pump. As the pump is motor driven, the pump will come up to speed. Immediately check discharge pressure gauge. If no pressure is shown, stop the pump and find the cause. If the discharge pressure is satisfactory, slowly open the discharge valve to 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 operating condition. l) Check bearings of pumps and drivers for signs of heating. Recheck all oil levels. m) 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. n) Start the pump and run it for at least four hours. o) 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 completed. On a new unit, the screens are sometimes left in service for the first run on all locations where spare pumps have been provided. Water circulation with motordriven hydrocarbon pumps can result in motor overloading, if the full pumping capacity is used on water. In this type of equipment, the capacity must be reduced by throttling the discharge during such periods. When water is used for pressure testing and washing, it is sometimes better to have packing in the pumps for a seal to
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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 1ines, 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 must be introduced to the vessels to prevent rusting of' the internals from oxygen in the air. 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. 8.8.5
Compressors Run-in As with the pumps the compressors should be run-in as soon as construction permits to find and correct problems early. The initial run-in of all compressors should be carried out under the supervision of the manufacturer's representatives. Before running any of the machines, the operators should familiarize themselves with the pertinent operating instructions including 1ubricating, cooling and safety requirements. The compressors will be run-in on air according to maker's instructions. Before operation of the compressors, the following items should be completed: 1) All lines and vessels should be pressure tested. 2) If portion of make-up and recycle system were acidized they should be under a nitrogen blanket since the completion of the acid cleaning. 3) Suction strainers should be installed in each suction line. 4) All safety valves should be installed and unblocked. 5) It is extremely important that all instrumentation on the compressor and its associated equipment be thoroughly checked to ensure proper installation and function. All alarms must be tested. All shut down alarms must be tested. Before running any of the reciprocating compressors, the cooling and lubrication system must be placed into service. Before loading any compressor, be certain that all liquid has been drained from the lines, snubbers, etc.
8.8.6
The Furnace Dry-Out The charge heater dry-out can be performed by itself or it can be coupled with the run-in of the recycle compressors and the dry-out of the reactor system. Although it is probably preferable to combine all three operations, the charge heater may be ready for dry-out before the reactor and compressor system. It that case it may be desirable to do the heater dry-out by itself. The heater manufacturer's procedure for refractory dry-out should be consulted and
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incorporated into either method used. See Chapter 14 for the dry-out procedure. The recycle compressor will be run in on air at maximum flow through the reaction section, if possible, according to the manufacturer's instructions. All possible low points will be open to remove the water still remaining in the system after the flushing of the equipment. During this operation the make up compressor may be run at 0% capacity by unloading the valves. Caution : Recycle cylinder should not be operated at 0 % capacity for more than 20 minutes. Make-up cylinder can run permanently at 0% capacity. When running unloaded, the cylinders do not compress and the same gas is always recycled in the suction valves. Excessive overheating can occur causing damages of the wearing parts. See manufacturer's instructions. When this operation has been completed and vessels inspected for cleanliness, catalyst can be loaded into the reactor and packing into the gas absorber. Demister pads, orifice plates and restriction orifices can be installed and a check made on all instrumentation for correct installation and operation. Refer to Chapter 14 for packing loading and for catalyst loading. As the recycle gas scrubber 1502 E needs degreasing before start-up it will be included in the unit 16 washing operation for the circulation of the cleaning solution. Refer Unit16 Operation Manual Chapter 14, chemical cleaning of the unit. 8.8.7
Air Coolers Precommissioning Prior to starting the air coolers, the motor-driven fans are run-in for at least four hours. The auto variable blade will be adjusted, so that the amperage on the driver is near the maximum. Before start, the following checking must be done:
Connection of the earth wire.
Operability of the louvers.
Good alignment of the motor and the fan.
Coupling.
Lubrication of the bearings.
Free rotation of fan and motor.
Sense of rotation of motor.
Correct belt tension of fan drive pulleys.
Operation of the auto-variable blades (if any).
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8.8.8
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Operational Pressure Test 1) Check the entire plant to ensure that all vents and drains are closed, and that the unit process lines are blinded off at battery limits. Pressure tests are now carried out on the unit using plant air tied in at suitable points, to ensure that no major leaks exist due to omissions of vessel test plugs, gaskets, etc. All flanges and manholes should be checked for leaks using tape and soap solution. The reactor and the stripper sections will be tested at different pressures. 2) The reactor section a) Block off the make-up and recycle gas compressor ; b) Block off the start-up ejector including vacuum gauge ; c) Test the equipment at 7 barg. Finally vent the system. Use the low points to drain any remaining water left in the system. 3) The Stripper Section Block off all pumps and test the system at 1.75 barg. Finally, vent the system down to atmospheric pressure.
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APPENDIX I
PUMP OPERATION
The following procedures are presented to outline the most important steps involved in pump operation. Any modification of these procedures due to particular installation peculiarities should conform to good engineering practice. Suction Conditions
Sometimes the suction conditions imposed on a centrifugal pump are extremely unfavorable and lead to a complete breakdown of the operation of the pump. The suction head or pressure should be kept within the limitation for which the pump was sold. If the original operating conditions must be change for any reason, consult your nearest Worthington specialist. Care should be exercised to keep the suction piping air tight and sealed against leakage.
Starting and Operating Pumps :
Preliminary instructions Test the driver for rotation with the coupling bolts removed. An arrow shows rotation on the pump casing Replace the coupling bolts.
Starting Pumps
Refer to the lubricator section and be sure that the bearings have been properly lubricated. Before starting the pump initially, turn the rotor over several times by hand to lubricate the bearings. If cooling water is required by the operating conditions, open the valves in the cooling liquid line. Once the pump is in operation regulate the cooling liquid to prevent condensation inside the bearing housing. Eliminating visible condensation on the outside of the housing can do this.
The valves on the liquid line to the stuffing box should now be opened. This step is imperative whether the pump has a packed box with a seal cage, or a mechanical seal requiring flushing. The amount of fluid
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circulated to the stuffing box must be controlled at all times during operation. Operating experience will indicate the proper procedure to be followed. Open the suction valve and any vents or gauge connections in the system which will allow the air in the casing to escape. Turn the rotor over by hand ; if it is bound, do not operate the pump until the cause of the trouble is found. Start the driver according to driver manufacturer's instructions. Open the discharge valve slowly as soon as the pump attains full speed. If the discharge pressure gauge does not immediately register when the rotor is revolving at or near ratedspeed, immediately shut down and make a careful check of the suction line for obstructions in the line which could interfere with the liquid flow to the pump. During the routine operation of the pump, the bearings should be occasionally checked for proper lubrication and oil level. Check stuffing box operation.
Stopping Pumps Normally, there should be a check valve and a gate valve in the discharge line. In such cases, stopping the driver according to the driver manufacturer’s instructions can shut down the pump. The remaining valves are then normally closed in the following order : discharge, suction, cooling liquid supply, and sealing liquid supply. (In some services, the sealing liquid is left on continually to protect seals against the formation of solid or crystals etc.). In some installations the use of a check valve is not feasible due to the creation of pressure surges or water hammer as a result of the sudden closing of the valve under high discharge pressure. In such cases the discharge valve should be closed slowly prior to stopping the driver to eliminate the possibility of water hammer. A pump will partly drain through the glands if left standing for long periods of time. For this reason it is recommended that the pump always be primed before start-up. LUBRICATION
Oil used for lubricating ball or roller bearings should be a high quality, well-refined mineral oil which will not readily oxidize or gum. Vegetable or animal oils should not be used. The oil should be certified to be free from deleterious substances which would harm the bearings at any operating temperature.
New Installation or Oil Change 1 - Drain the bearing bracket and flush it with a light oil, install the constant level oiler. 2 - Make sure the oiler is level.
3 - Fill the bottle through the stem, replace and allow all to flow into reservoir. It may be necessary to fill the bottle several times before the oil ceases to run into the reservoir, indicating that the oil is up to the proper level.
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4 - Refill the bottle to maintain this level. Caution
Never fill reservoir through the air vent opening. The constant level oil control maintains a constant level of oil in the reservoir. The control feeds only enough oil to maintain the required level. It operates on the liquid seal principal, feeding only when the level in the reservoir is low enough to break the liquid seal at the end of the shank, thus permitting air to enter the bottle. It will cease to feed when there is sufficient all in the reservoir to cover the hole in the end of the shank. Bearing Oil Temperatures The oil fingers maintain circulation of the oil in the reservoir. It is recommended that the lubricating oil be kept between 40℃ and 70℃, preferably above 50℃. Bearing cooling water may be eliminated, when desired, for suction pressures up to 20 bar g when the pumping temperature is below 50℃ In specific cases higher pumping temperatures are possible without cooling up to 100℃ maximum with considerably lowered suction pressure. The bearing oil temperature without cooling may rise to 70 - 85℃. Oil Change Operating conditions and severity of service will determine the intervals between oil changes. In general higher oil temperatures will require more frequent oil change. If the bearings maintain their normal temperature and there has been no contamination of the oil, the interval between changes may be prolonged. Generally the oil should be changed every six months. If the bearing temperature increases, check immediately for improper lubrication or a faulty bearing. LOCATING TROUBLES
The troubles which may occur with your pump and their causes are listed below. The operator can often avoid unnecessary expense by careful consideration of the points outlined. Failure to Deliver Liquid a)
Insufficient speed.
b)
Discharge head too high (greater than that for which the pump is rated).
c)
Impeller passages partially clogged.
d)
Wrong direction of rotation.
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Insufficient Capacity a)
Air leaks in suction piping.
b)
Speed too low.
c)
Total head higher than that for which pump is rated.
d)
Impeller passages partially clogged.
e)
Insufficient NPSH.
f)
Mechanical defects - Impeller damaged. - Wearing rings worn.
Insufficient Discharge Pressure a)
Speed too low.
b) Air in liquid. c)
Mechanical defects : - impeller damaged. Wearing rings worn
Pump loses Prime After Starting a)
Leaky suction line.
b) Suction lift too high. c)
Air or gases in the liquid.
d) Stuffing box not effectively sealed.
Pump Overloads Driver a)
Speed too high.
b) Liquid pumped of different specific gravity and viscosity than that for which pump is rated. c)
Mechanical defects.
Operating Manual LGO Hydrotreating unit (Unit 15) Pump Vibrates a)
Misalignment.
b) Foundation not rigid c)
Impeller partially clogged, causing unbalance.
d) Mechanical defects : - Bent shaft. - Rotating element binds. - Worn bearings. e)
Insufficient NPSH.
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CHAPTER 9: UNIT START-UP PROCEDURE 9.1
START-UP WITH FRESH OR REGENERATED CATALYST
The start-up procedure contained in this manual describes in general terms the steps to be followed for placing the unit on stream. The following steps must be completed before charging oil to the reactors. 9.1.1
Prestart-up Checklist
9.1.2
All unnecessary blinds removed All relief valves tested and installed Flare header purged and in service Sewers in service Heaters steamed out Fuel gas and fuel oil lines in service Pilots lit in heaters 1501B and 1502B All instruments ready for service All utilities in service All drains and vents closed in reactor section Control valves and bypasses blocked in All compressors blocked in Flanges taped in reactor circuit Nitrogen supply available and connected Steam jet ejector connected. Purging the Equipment
The reactor and stripper section are treated separately. The reactor section is first placed under vacuum and then filled with pure nitrogen whereas the stripper section is purged with steam that is subsequently replaced by fuel gas. Appropriate blinds should be removed before the purging operation. 9.1.2.1
Reactor section
After venting to atmosphere, the vents are closed and the section is placed under vacuum by means of the steam jet ejector 1501L which is connected to the recycle compressor section line so that the vacuum will be pulled in the normal direction of flow. It is emphasized that whenever flow is established through the reactor, be it for vacuum or pressuring, it must always be in the normal direction that is downward through the catalyst bed. Make sure that instrument connections are isolated to prevent damage when a vacuum
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of 600 mm Hg approximately has been reached, the ejector is first blocked off and then shut down. The pressure rise over a period of one hour is recorded and if it is greater than 25 mmHg/hr the system is not sufficiently tight and should be retested under positive air pressure to find the leaks. Note:
Open the 1 1/2 inch H2 pressurizing line between the make-up compressor section and discharge in order to include the make-up gas K.O. drum 1508F in the reaction section. When the system is sufficiently tight, the vacuum is broken using nitrogen which is introduced downstream of the recycle gas compressor and allow pressure to build up to 0.3 barg. Then the ejector is restarted to remove the nitrogen.
Repeat this process two or more times until the oxygen content of the system, sampled at the ejector, is less than 0.5% by volume. Once purging is complete the reactor section is held at a nitrogen pressure of about 0.3 barg. At the same time that the reactor circuit is evacuated, the compressors must be thoroughly purged with nitrogen before admitting hydrogen into the unit. Do not pull a vacuum on the compressors but leave them blocked in during the reaction section purging phase. With the suction and discharge block valves closed and the by-pass open, introduce nitrogen via the nitrogen connection provided at each head. When the system is at the nitrogen supply pressure or at least 3.5 bar g, shut off the nitrogen supply, bar over the compressor and then vent off the nitrogen. Repeat the above operation two or more times or until the oxygen content is less than 0.5% by volume. This procedure applies for the recycle and make-up gas compressors 1501J1/J2, 1501 JA1/JA2 as well as the product stripper overhead sour gas compressors 1502J/JA. 9.1.2.2
The stripper section The product stripper section, the feed coalescer 1503L, the feed surge drum 1501F, and the LP flash drum 1503F are first purged by steam to displace air in the system, then the steam is replaced by fuel gas. d) Open high point vents and low point drains. e) Block off pumps 1503J/JA, 1505J/JA, 1506J/JA and compressors.
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Block off all instrument connections to prevent damage.
g) Start steam purging, introducing steam through steam hoses and into steam-out connections. When a steady continuous flow of steam has been issuing from the high point vents for a minimum of one hour, fuel gas may be brought into the unit. h) Close vents and steam purging connections. Close drains. i)
Slowly introduce fuel gas along the start-up connection. (2" line connected on the product stripper 1501E).
j)
Slowly bring the product stripper, the stripper overhead drum 1504F and the overhead compressor K.O. drum 1505F to a pressure of 0.3 bar g. bring the rest of the system up to gas pressure. Commission the 15-PIC-005 on the overhead drum.
k) Slowly bring fuel gas into the feed surge drum 1501F and commission the 15-PIC-001. l)
Frequently check and drain off any condensate.
m) Establish a liquid seal of lean amine solution in the base of the H2S scrubber 1502E. 9.1.3
Circulation on start-up bypass - The stripper section - Cold oil circulation The start-up bypass lines installed in the unit should be used to run-in the charge pumps, to remove scale from the lines, and to inventory the stripper with oil. In order to avoid rapid expansion of the pumps and lines due to the high temperature of the raw gas oil from the crude distillation unit should this plant be running, the feed surge drum wi11 be fed using the 6" recycle line located downstream of the stripper bottom air cooler 1504C/C1. a)
Open the oil feed block valves on the 6” recycle line. Establish a normal working level in the feed surge drum and leave the drum floating under controlled pressure from the fuel gas system (15-PIC-001). During cold-circulation, the feed coalescer, 1503L should be blocked
b) Block-in the valve leading to the reaction section. c)
Line up the feed charge pump 1503J/JA via the 6" start-up line to the stripper 1501E and establish the following circulation route: from the stripper 1501E through the bottom pump 1506J/JA, product stripper feed/bottoms exchangers 1503C1/C2/C3/C4/ C5/C6, gas oil trim coolers 1504C/C1 and the recycle line back to the surge drum 1501F, or to storage if the crude unit is shut down. 15-FIC-016 at the liquid outlet of LP flash drum 1503F will have to be opened from the control room using 15-FIC-016, as there is no product in the LP flash drum 1503F.
d) Start the feed pump 1503J/JA at a flow of 55m3/h (minimum flow allowed by the manufacturer) using 15-HCV-001 on the 6” start up line. Establish a level in the product stripper 1501E. Prime and start the stripper bottom pump 1506J/JA. It would be to establish the flow to the stripper reboiler furnace 1502B first as close to design as
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possible. Control valves, 15-FV-025/026 at the inlet to the two passes are used to split the flow equally. e)
Commission the stripper level controller 15-LV-010.
f)
During these operations and until the complete loop has been established it is advisable that an operator keep watching the feed surge drum level and keep it normal by throttling on the 6" recycle line feeding this drum.
g) During the cold oil circulation step it is assumed that the crude distillation unit will be running only at 50% of design as both recycled stripper bottoms and raw light gas oil from crude unit will be flowing through the gas oil trim cooler 1504C/C1, the split between the two streams being made downstream the latter. 9.1.4
Reaction section – Heat-up(drying out) Drying of the fresh or regenerated catalyst prior to activation is preferably carried out using treat gas, nitrogen or air. If hydrogen or gases containing large amounts of hydrogen (e.g. recycle gas) are used, the reactor temperature must be kept below 200C (400F). Contact of hydrogen with fresh or regenerated catalyst in the absence of sulfur particularly at higher temperature will reduce the efficiency of the sulfiding treatment and the catalyst performance. This is due to the risk of reducing the catalyst oxides to free metals that would be extremely harmful to the catalyst activity. Therefore the heating up of the catalyst is carried out with nitrogen at reduced flowrate. Please note that ex-situ presulphided catalyst should not be dried out before activation. a)
IF hydrogen containing the reactor must be purged with nitrogen so that the oxygen content of the reactor is less than 0.5 volume percent before introducing the hydrogen containing gas.
b) Line up the nitrogen circulation as follows From make-up and recycle gas compressors 1501J1/J2 or 1501JA1/JA2 to exchangers 1507C, reactor charge furnace 1501B, reactors 1551D & 1501D, exchanger l50lC1/C2/C3/C4, 1507C, air cooler 1502C, HP Flash drum 1502F, recycle gas scrubber 1502E, make-up gas K.O. drum 1508F, recycle gas K.O. drum 1507F, and suction of make-up and recycle gas compressor 1501J1/J2 and 1501JA1/JA2. c)
Be sure that the nitrogen circulation loop is isolated from cold circulation in stripping section, block valve in 6''-P-15-105-0-GA02 closed. Check that block valves are closed in:
tripped water line to reaction effluent (2"-P-15-217-0-GA03L) Around 15-LV-003 (bottom of 1502F) Stripped water line to the scrubber 1502E (3/4"-P-15-217-1-GA02) Around 15-PV-003 (Sweet gas out of 1502 E) Line to ejector 1501L
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Drain of recycle gas to K.O. drum 1507F (2"-P-15-221-0-GA02L) Drain of recycle gas to K.O. drum 1508F (2"-P-15-222-0-GA12L) d) Pressure the reactor to the highest pressure allowed by the refinery when the reactor temperature is the ductile-brittle transition temperature (as a rule-of-thumb the maximum
allowable pressure at temperatures below 135℃ (275F) is 1/4 of the design pressure). At the same time, start the make-up and recycle compressor with maximum rate according vendor’s instruction. The air or nitrogen used for the drying out may be recycled, if desired e)
Light the reactor charge furnace 1501B according manufacturer's instruction. Start to raise the reactor temperature to 150℃ (300F) over a 4 to 5 hour period. The recommended maximum rate for heating up of the catalyst is 30℃/hr (50F/hr) to minimize chances for leaks due to thermal expansion.
f)
Maximize cooling of the effluent by 1502C. Check and drain water from the highpressure separator 1502F. When no more water is accumulated in the high-pressure separator 1502F, the drying out of the catalyst is complete.
g) Stop the burner of the reactor charge furnace 1501B. Stop the make-up and the recycle compressor 1501J1/J2or 1501JA1/JA2. Depressurize the loop. h) If air is used for the above procedure, nitrogen purge must now be used in order to reduce oxygen level in the reactor to less than 0.5 volume percent prior to the activation step. 9.1.5
Presulphiding and Reactor Section Start-up
Hydroprocessing catalysts as manufactured consist basically of an alumina (aluminum oxide) carrier impregnated with the oxides of cobalt-molybdenum, The cobalt-molybdenum types are grayish blue. Hydroprocessing catalyst can be delivered ex-situ presulphided. The ex-situ presulphiding is done by impregnating the catalyst pore system with a sulphur-containing component dissolved in an organic solvent or with elemental sulphur followed by a soaking of the catalyst in a paraffinic hydrocarbon. When the catalyst is heated under hydrogen pressure, this sulphur-containing component will decompose and release the sulphur in the form of H2S for the sulphiding of the catalyst. Irrespective of type, ex-situ presulphided catalysts are dark gray with a slight small of the organic solvent. Hydroprocessing catalysts are very porous, having surface areas of 150-250 square meters/gram. This is an important feature of the catalyst. Such porous catalyst is hygroscopic, i.e. water or moisture is readily absorbed. As delivered, the catalyst will contain some water, normally about 12 percent of the catalyst weight. Furthermore, the catalyst may absorb some moisture during the loading. Therefore, the catalyst must be dried before the activation is carried out. Please note that ex-situ presulphided catalyst does not require drying before activation because this has already been done at the company doing the ex-situ presulphiding. Hydroprocessing catalysts including ex-situ presulphided catalyst must be activated before use.
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During the activation and the cobalt/molybdenum are converted to sulphides, which is the active form of the catalyst. The activation is very important for the subsequent performance of the catalyst charge and therefore requires careful monitoring. During the activation, the catalyst will pick up 6-13 weight percent sulphur depending on the level of active metal present in the catalyst. There are several methods available for sulphiding the catalyst. The method recommended by HALDOR TOPSOE is the doped feed method using an easily decomposable sulphur compound mixed with the oil. If other methods are considered, such as native sulphur or ex-situ presulphided, HALDOR TOPSOE should be consulted in each case for advice. 9.1.5.1
Doped Feed Method and Reactor Section Start-up
In this procedure, a start-up feed is used with additional sulphur being provided by doping the feedstock to about 1-2 weight percent sulphur with a sulphiding chemical. The startup feed is a light straight-run petroleum fraction (e.g. kerosene or diesel) that is not higher boiling than the normal feedstock. The start-up feed should have a maximum ASTM end point of 370℃ (700F). A number of options are available for sulphiding chemical. The procedure as written is based on using dimethyl-disulphide, DMDS. DMDS is the most commonly used sulphiding chemical currently being used in the refining industry. If other sulphiding chemicals are applied, adjustments to the procedure below may be needed and HALDOR TOPSOE should be consulted. It is advisable to do a sulphur balance as a check on the level of sulphiding by measuring DMDS added the organic sulphur in the feed and duct streams and the H2S content in the gas product streams. Normally we recommend having an excess of 25 percent available of the sulphiding chemical. DMDS will be supplied from 4603LJ1 at Unit46. n)
The reactor must be dried out and purged with nitrogen, so that the oxygen level is less than 0.5 volume percent. The temperature at the start of the procedure is maintained at approximately 150℃ (300F) to minimize catalyst reduction.
o)
Set the high-pressure flash drum pressure controller 15-PIC-003 to 4.2 barg.
p)
Crack open the 6'' make-up hydrogen line to unit15 & 17 in unit12 and allow the reaction section pressure to rise to 4.2 barg using the 1 1/2 inch pressurizing line. Check the system for leaks. If the system is tight at this pressure, raise the pressure in 7 barg steps using the HP flash drum pressure, controller 15-PIC-003, each time checking for leaks until the make-up gas mains pressure is reached. NOTE: During start-up of unit 15, natural gas will be used for the pressure control of 1701F
Operating Manual LGO Hydrotreating unit (Unit 15)
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q)
Open fully the make-up gas valve in unit12.
r)
Pressurize the reactor to normal operating pressure (unless limited by the ductile-brittle transition temperatures of the reactor and equipment)
s)
Prepare to start the make-up and recycle compressors, 1501J1/J2 or 1501JA1/JA2. Commission 15-FIC-006 on recycle gas flow to charge heater 1501B. Commission 15PIC-003 pressure controller on the high pressure separator 1502F. Start the reactor effluent condenser 1502C in reactor effluent line.
t)
While pressurizing the unit, start the make-up and recycle gas compressor and establish recirculation of process gas at normal flow rate. In order to conserve H2S the recycle gas scrubber should be by-passed or the amine recirculation stopped during the sulphiding.
u)
Line up the recycle and make-up compressors to discharge through 1507C to the charge heater 1501B, reactors 1551D & 1501D, through feed/effluent exchangers 1501 C1/C2/C3/C4 and 1507C, through air cooler 1502C to the high pressure flash drum 1502F, through the 6" start up line by passing the recycle gas scrubber 1502E, to the recycle gas to drum 1507F & 1508F and back to the make-up and recycle gas compressor. The two valves on the 6” start up line are locked open during bypassing the recycle gas scrubber 1502E.
v)
Open the block valve in feed line 6"-P-15-105-0-GA02 and start to feed the reaction section through the furnace by increasing the set point of 15-FRC-001, closing progressively 15-HCV-001 in reaction section by-pass line. Make this change gently. Do not allow reactor temperature to drop significant1y during the change.
w)
Start flow of start-oil at normal feed flow rate. Adjust both 15-FRC-006 (H2) and 15FRC-001 (oil feed) for design flow-rate. This must be done gently to prevent thermal shock
x)
After stabilizing of flows, temperatures and pressures in the unit, the start-up oil can be recirculated from the stripper, 1501E, if desired. This reduces the quantity of start-up oil needed and may reduce off-specification material produced. Start-up oil recycle should not be done through storage tanks because the unstripped start-up oil may contain H2S that may accumulate in the storage tank.
y)
Increase the reactor 1551D inlet temperature to 180℃ (360F) at a rate of (45F/hr).
z)
If pressure was limited by ductile-brittle transition temperature, increase the pressure to design level when all reactor wall temperatures exceed the transition temperature. Minimize the recycle gas bleed to conserve H2S.
aa)
When the reactor inlet temperature is 180C (360F), start the sulphiding chemical injection and adjust the rate to give 1-2 weight percent total sulphur in feed.
bb)
Water is formed from the sulphiding reactions. Check the high-pressure separator, 1502F at regular intervals for water accumulation and drain if necessary.
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cc)
The reactor inlet temperature is increased to 225C (440F) at a rate of 25C/hr (45F/hr). The catalyst is sulphided at this reactor of 1551D inlet temperature until breakthrough of H2S. The reactor of 1501D outlet temperature during this period should not exceed 250C (480F).
dd)
In order to ascertain breakthrough of H2S, the high-pressure separator of 1502F off-gas should be checked for H2S concentration at regular intervals. Breakthrough can be defined as the point when consecutive stable measurement of H2S are above 5000 vppm H2S. Breakthrough indicates completion of the first stage of the sulphiding.
ee)
Raise the reactor inlet temperature to 350C (660F) at a rate of 15C/hr (30F/hr). Check H2S levels at 1/2-hour intervals. Stop the heat-up rate if the H2S level drops below 3000 vppm. During this period, adjust the injection rate of the sulphiding chemical to keep the recycle gas H2S content of 1-2 volume percent.
ff)
Hold the reactor inlet temperature at 350C (660F). When all catalyst temperatures have been at or above 330C (625F) for a minimum of 4 hours, the sulphiding phase is considered completed.
gg)
Lower the reactor inlet temperature at a rate of 30C/hr (50F/hr) to the temperature specified as the start-of-run temperature(316C).
hh)
Start normal straight-run feed (90wt% hot feed from unit 11 and 10wt% cold feed from stroage) to the unit at design rate. 10wt% cold feed is fed after removing water by feed coalescer 1503L and the cold-feed flow-rate is controlled by 15-FV-076. Start amine circulation and put the recycle gas scrubber into service. If the startup oil is recirculated, stop the circulation and begin flow to tankage. Typically this will be to off-spec storage until laboratory analyses indicate the product meets design specifications
ii)
Check operating conditions to ensure the design pressure, gas rates, recycle gas purity and H2S removal specifications are being met. Adjust the operating temperature to meet product specifications. After on specification, LGO product will be routed to HT gas oil storage tanks(2106FA/FB).
9.1.5.2
Sulphiding of Replacement Catalyst after Skimming and Reaction Section Start-up
In some cases, refiners have had to interrupt a run to skim off the top catalyst bed to alleviate pressure drop problems or to replace contaminated catalyst. In these cases, new replacement catalyst (or a layered graded bed) could be installed after the skimming. The bulk of the catalyst is still in the sulphided state, so sulphiding is only required for the new top layers. In this situation, an abbreviated presulphiding procedure is typically used. If a large percentage of the catalyst in a reactor is replaced, use one of the recommended methods previously described for new or regenerated catalyst. The following procedure is for activating a small percentage (less than 10%) of new catalyst on top of catalysts that have
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previously been in operation. jj) The reactor must be dried out and purged with nitrogen, so that the oxygen level is less than 0.5 volume percent. The temperature at the start of the procedure is maintained at approximately 150℃ (300F) to minimize catalyst reduction. kk) Set the high-pressure flash drum pressure controller 15-PIC-003 to 4.2 barg. ll) Crack open the 6'' make-up hydrogen line to unit15 & 17 in unit12 and allow the reaction section pressure to rise to 4.2 barg using the 1 1/2 inch pressurizing line. Check the system for leaks. If the system is tight at this pressure, raise the pressure in 7 barg steps using the HP flash drum pressure, controller 15-PIC-003, each time checking for leaks until the make-up gas mains pressure is reached. NOTE: During start-up of unit 15, natural gas will be used for the pressure control of 1701F mm)
Open fully the make-up gas valve in unit12.
nn) Pressurize the reactor to normal operating pressure (unless limited by the ductile-brittle transition temperatures of the reactor and equipment) oo) Prepare to start the make-up and recycle compressors, 1501J1/J2 or 1501JA1/JA2. Commission 15-FIC-006 on recycle gas flow to charge heater 1501B. Commission 15PIC-003 pressure controller on the high pressure separator 1502F. Start the reactor effluent condenser 1502C in reactor effluent line. pp) While pressurizing the unit, start the make-up and recycle gas compressor and establish recirculation of process gas at normal flow rate. In order to conserve H2S the recycle gas scrubber should be by-passed or the amine recirculation stopped during the sulphiding. qq) Line up the recycle and make-up compressors to discharge through 1507C to the charge heater 1501B, reactors 1551D & 1501D, through feed/effluent exchangers 1501 C1/C2/C3/C4 and 1507C, through air cooler 1502C to the high pressure flash drum 1502F, through the 6" start up line by passing the recycle gas scrubber 1502E, to the recycle gas to drum 1507F & 1508F and back to the recycle gas compressor. The two valves on the 6” start up line are locked open during bypassing the recycle gas scrubber 1502E. rr) Open the block valve in feed line 6"-P-15-105-0-GA02 and start to feed the reaction section through the furnace by increasing the set point of 15-FRC-001, closing progressively 15-HCV-001 in reaction section by-pass line. Make this change gently. Do not allow reactor temperature to drop significant1y during the change ss) Introduce the feed at design rate. If the feed normally is a cracked stock or has cracked components, use a straight-run feed in the same boiling range as the normal feed or the straight-run components of the blend. The start-up feed must contain enough sulphur, above 0.5 weight percent, to make this procedure effective
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tt) After stabilizing of flows, temperatures and pressures in the unit, the start-up oil can be recirculated from the stripper if desired. This reduces the quantity of startup oil needed and may reduce off-specification material produced. Startup oil recycle should not be done through storage tanks because the unstripped startup oil may contain H2S which may accumulate in the storage tank. uu) If the new catalyst has been ex-situ presulphided, increase the inlet temperature gradually, 10C/hr (15F/hr), until the exothermal begins. It is expected that at a reactor inlet temperature of 150-180C (300-350 F) the conversion of the sulfur on the ex-situ presulphided catalyst will start and a reactor exothermal will develop. When the exothermal starts, pause the heat-up until the exothermal has stabilized vv) If pressure was limited by ductile-brittle transition temperature, increase the pressure to design level when all reactor wall temperatures exceed the transition temperature. Minimize the recycle gas bleed to conserve H2S. ww) Water is formed from the sulphiding reactions. Check the high-pressure separator, 1502F at regular intervals for water accumulation and drain if necessary xx) Increase the reactor, 1551D inlet temperature at 30C/hr (50F/hr) until the desulphurization reactions begin and an exothermal develops. Hold the inlet temperature as needed to maintain the exothermal for a minimum of 2 hours. yy) After the 2-hour hold, increase the inlet temperature to 350C (660F) at 30C/hr (50F/hr). zz) Hold the inlet temperature at 350C (660F) for 4 hours. The sulphiding of the replaced catalyst is then considered completed. aaa) Lower the reactor inlet temperature at a rate of 30C/hr (50F/hr) to the temperature specified as the start-of-run temperature. bbb) Start normal straight-run feed (90wt% hot feed from unit 11 and 10wt% cold feed from stroage) to the unit at design rate. 10wt% cold feed is fed after removing water by feed coalescer 1503L and the cold-feed flow-rate is controlled by 15-FV-076. Start amine circulation and put the recycle gas scrubber into service. Also commission the amine regenerator. If the startup oil is recirculated, stop the circulation and begin flow to tankage. Typically this will be to off-spec storage until laboratory analyses indicate the product meets design specifications. ccc) Check operating conditions to ensure the design pressure, gas rates, recycle gas purity and H2S adsorption specifications are being met. Adjust the operating temperature to meet the product specifications. 1 After on specification, LGO product will be routed to HT gas oil storage tanks(2106FA/FB). 9.1.5
Start-Up Stripping Section ddd)
At this step oil is flowing through the stripping section supplied from 1503F of LP
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flash drum and sent to light slop tank 2121F. eee) Start the reboiler 1502B according manufacturer's instructions and bring the temperatures to operating conditions. Note: The drying out of the furnace can be performed at this moment if not already done. fff) When a normal working liquid level is established in the stripper overhead drum 1504F, start the product stripper reflux pump 1505J/JA and commission the reflux flow controller 15-FIC-021, the level controller 15-LIC-011 and the pressure controller 15PIC-005. The product stripper off-gas compressor 1502J/JA is to be started and the start-up fuel gas supply can be shut-off. ggg) Commission the compressed gas K.O. drum 1506F level controller 15-LIC-016 and establish a normal working level in the drum, transferring excess liquid hydrocarbon to the Unit11. If Unit11 is shutdown, excess liquid is transferred to the Unit61. hhh) Sample the desulphurised product for quality and route product to desulphurised storage 2106FA/FB when on specification. 9.2 9.2.1
START-UP FOLLOWING NORMAL SHUT-DOWN OR REGENERATION Start-Up with Unregenerate Catalyst This section is a start-up following a normal shutdown, were no changes have been made to the state of the catalyst. 4) The high-pressure section is purged with nitrogen, so that the oxygen level is less than 0.5 volume percent. Keep the reactor inlet temperatures below 150C (300F) to minimize catalyst reduction. 5) Set the high pressure separator 1502F pressure controller 15-PIC-003 to 4.2 barg. Crack open the 6'' make-up hydrogen line to unit15 & 17 in unit12 and allow the reaction section pressure to rise to 4.2 barg using the 1 1/2 inch pressurizing line. Check the system for leaks. If the system is tight at this pressure, raise the pressure in 7 barg steps using the HP flash drum pressure, controller 15-PIC-003, each time checking for leaks until the make-up gas mains pressure is reached. Open fully the make-up gas valve in unit12. NOTE: During start-up of unit 15, natural gas will be used for the pressure control of 1701F. 6) Pressurize the reactor to normal operating pressure (unless limited by the ductile-brittle transition temperatures of the reactor and equipment). 7) Prepare to start the make-up gas compressor 1501J1/J2 and recycle gas compressor 1501JA1/JA2. Commission 15-FIC-006 on recycle gas flow to charge heater 1501B. Commission 15-PIC-003 pressure controller on the high pressure separator 1502F.
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8) While pressurizing the unit, start the make-up gas and recycle gas compressor according to manufacturer’s instruction and establish recirculation of process gas at normal flow rate. If the recycle gas is scrubbed to remove H2S, start amine circulation and put the recycle gas amine scrubber into service. 9) Start increasing the heater outlet temperature at 30C/hr to 150C, when the right hydrogen flow has been established. 10) When the heater outlet temperature has reached 150C, introduce the feed at 50% design rate and raise it gradually to full design rate. 11) If pressure was limited by ductile-brittle transition temperature, increase the pressure to design level when all reactor wall temperatures exceed the transition temperature. 12) After stabilizing of flows, temperatures and pressures in the unit, the start-up oil can be recirculated from product fractionator if desired. This reduces the quantity of startup oil needed and may reduce off-specification material produced. It shall however be assured that some sulfur remain in the liquid feed to maintain the exotherm in the reactor and prevent sulfur reduction of the catalyst. The preferred method of for checking this status is to check that the high-pressure separator gas going to the scrubber remains above 0.05 mol% H2S. This can be checked with Drager tubes. Startup oil recycle should not be done through storage tanks if the stripped startup oil may contain H2S, which may accumulate in the storage tank. 13) The heater outlet temperature is raised at 30C/hr towards the desired operating temperature. At no point in time must the heater outlet temperature be more than 100C higher than any reactor temperature. 14) As the reactor temperatures approach the desired operating temperatures, stop any product recirculation and start performing laboratory analysis for the desired specifications. 15) Check operating conditions to ensure the design pressure, gas rates, recycle gas purity and H2S removal specifications are being met. Adjust the operating temperature to meet product specifications. After on specification, LGO product will be routed to HT gas oil storage tanks(2106FA/FB). 9.2.2
Start-Up after Catalyst Regeneration To start the unit after catalyst regeneration, follow in its entirety the procedure outlined previously for fresh catalyst.
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Operating Manual LGO Hydrotreating unit (Unit 15) CHAPTER 10: UNIT NORMAL OPERATION 10.1 OPERATING VARIABLES
The proper operation of the unit will depend on the judicious selection and control of the processing conditions. As they are of utmost importance to the performance of the unit the following discussion includes some of the steps that can be taken to maintain them within acceptable limits. 10.1.2
Reactor Temperatures
Each reactor inlet temperature is most easily and commonly controlled by the operator to adjust the sulfur removed from the feed. The reactor 1501D-outlet temperature is a function of the feed quality and cannot be easily varied except by changing the reactor inlet temperature. The reactor 1551D-inlet temperature must always be controlled at the minimum required to achieve the desired sulfur and/or nitrogen removal. Temperatures above this minimum will only lead to higher rates of coke formation and reduced processing periods. During the course of an operating cycle, the temperature required to obtain the desired product quality will increase as a result of catalyst deactivation. The gradual loss in catalyst activity can be compensated for by increasing reactor temperatures up to a limit of about (428℃) maximum bed temperature, above which coke formation becomes very rapid and little improvement in performance is obtained. Note that this temperature is the highest temperature in the catalyst bed and is not necessarily the outlet temperature. The design temperatures of the reactor and charge heater will also determine the maximum allowable operating values. The temperature rise across the reactors must be monitored continuously in order to ensure that the design limitation of the unit is not exceeded. This can be especially important when changing feed stocks since olefin saturation results in considerably higher heats of reaction. The first reactor inlet temperature is controlled by 15-TIC-010 acting on the rate of fuel to the reactor charge heater 1501B through 15-HS-005 which selects either fuel gas or fuel oil as leading fuel, the remaining fuel being manually adjusted by 15-HIC-005. The second reactor inlet temperature is controlled by 15-TV-016. Special care should be taken when operating these devices as misoperation could lead to temperature upsets thus leading to coke formation or improper desulphurization. Reactor Section Operation Conditions The
design
of
the
reactor
is
based
on
the
following
Feed Case
50/50
Run Phase
Start-of-Run
operating
conditions:
50/50 End-of-Run
Operating Manual LGO Hydrotreating unit (Unit 15) Capacity, bpsd
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17,000
17,000
112.6
112.6
Overall
1.3
1.3
1551D
1.89
1.89
1501D
4.18
4.18
1551D inlet
316
362
1551D outleta
347
388
1501D inlet
339
381
1501D outleta
347
388
Reactor Average BEDb
338
380
Total Temperature Rise, oC
38
32
1551D inlet
49.8
51.5
1551D outlet
49.1
49.5
1501D inlet
49.0
49.4
1501D outlet
48.0
48.0
Treat Gas to Reactor inlet
23,500
24,880
Inter-Reactor Quench
5,070
3,660
Recycle Gas H2 Purity, c mol %
79.2
74.0
Treat Gas H2 Purity, mol %
79.9
76.0
Wash Water Rate, kg/hrd
3857
3857
M3/hr Space Velocity, v/v-hr
Reactor Temperature, oC
Reactor Pressure, bar abs
Treat Gas Rates (Recycle + Makeup), Nm3/hr
a
The reactors are operated with equal bed outlet temperatures by adjustment of the quench temperature setpoint b Average bed temperature is weighted by catalyst volume and temperature profile in the catalyst bed. c The recycle gas hydrogen content has been calculated by simulation based on the yields and
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makeup hydrogen composition and with the following assumptions: 3) High pressure separator temperature of 57 oC 4) High pressure separator pressure of 45.5bara 5) Recycle gas amine scrubber removes all H2S and ammonia 6) The purge gas is 4vol percent of the scrubbed gas. d Wash water is continuous. The rate is equibalent to 3.4 volume percent of feed. Water rate has to be sufficient to maintain at least 20percent liquid water at injection point. 10.1.2
Feed Quality and Rate
The amount of catalyst loaded into the reactors as well as other design parameters are based on the quantity and quality of feedstock the unit is designed to process. While minor changes in feed type and charge rate can be tolerated, wide variations should be avoided since they will tend to reduce the useful life of the catalyst. An increase in the charge rate will require higher reactor temperature to achieve a constant desulphurization, as well as higher recycle gas rate to maintain a constant ratio of H2 to hydrocarbon. The increased reactor temperatures will also lead to a fester rate of coke formation which will reduce the period between regenerations. The reduced feed rate may lead to bed flow distribution through the catalyst, such that higher temperatures will be required to obtain good product quality. In order to minimize the effect of variations in charge rate, it should be made common practice to reduce the reactor temperature before lowering the feed rate, and conversely, to increase the feed rate before raising the reactor temperature. The feed consists of 10wt% cold feed from Tank through 1503L and 90wt% hot feed from Unit11. The gas oil feed rate is controlled by 15-FIC-001 acting through a bias control on the flow control valves 15-FV-001A/B thus ensuring an equal split between the two passes of the heater l501B. Its distillation range and API gravity best indicate the type of feed being processed. An increase in the end point of the feed wil1 make sulfur and nitrogen removal more difficult, thus requiring higher reactor temperatures which, in turn, accelerate coke formation. Coke deposition is also accelerated by the fact that heavier feed contains more of the precursors that favor coke formation. In addition to the above, high boiling fractions also contain increased quantities of metals which lead not only to higher reactor pressure drop, but also to rapid catalyst deactivation as wel1. It must be remembered that regeneration will not restore the activity of a catalyst that has been poisoned by excessive quantities of metals. Thus, it is seen that processing higher than design end point feeds will, at best, reduce the length of the operating cycle, and under extreme conditions, may lead to an irrecoverable loss of catalyst activity. Therefore, every effort must be made to maintain the end point of the feed within the design limits by operating the crude and other units such that an acceptable feed stock is obtained. Storage tanks used for the accumulation of feed to the unit must be gas blanketed in order to minimize the formation of coke producing materials. 10.1.4
Pressure
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The reactor section operating pressure is 15-PIC-003 controlled by the pressure maintained at the high-pressure separator. This pressure, multiplied by the H2 purity of the recycle gas, determines the partial pressure of H2 in the reactor. The hydrogen partial pressure required for the operation of the unit is chosen based on the degree of sulfur (or nitrogen) removal that most be achieved and is an economic optimum that balances initial investment and operating costs against catalyst life. The operating pressure (i.e. the high pressure separator pressure) most be held constant at the design value for the following reasons : i)
While higher than design operating-pressure directionally favors catalyst life and may result in somewhat better catalyst activity, such operation would be detrimental since the equipment (heaters, reactors, compressors, exchangers, safety valves, etc.,) has been designed based on a fixed separator pressure. An increase in the separator pressure wil1 lead to accelerated wear on the equipment, and in extreme cases could result in costly and dangerous equipment failures.
j)
A reduction of the operating pressure below the design level will have a negative effect on the activity of the catalyst and will accelerate catalyst deactivation due to coke formation
10.1.5
Hydrogen Purity -Hydrogen Partial Pressure
These two terms are interchangeable since at a given system pressure the purity of the recycle gas will determine the partial pressure of hydrogen in the reactor. At reduced hydrogen purities (i.e. partial pressures) the reactions are not effectively completed and there is a greater tendency for coke to be formed in the hydrogen deficient atmosphere. This is especially more so as a result of the plant operator's reaction to raise the reactor temperatures to compensate for the lower catalyst activity caused by reduced H2 purity. Catalyst deactivation rate can be kept to a minimum by maintaining the recycle gas hydrogen purity as high as possible. The design H2 partial pressure at the reactor outlet is about 26.86barg. 10.1.6
Recycle Gas rate
The large quantity of gas recycled from the high-pressure separator to the reactor serves the following purposes : k) Provides the excess hydrogen needed to ensure that the reactions are carried to completion. l)
Absorbs some of the heat of reaction, thereby minimizing the catalyst bed temperatures.
m) Helps hold down charge heater and combined feed exchanger tube wall temperatures by increasing the flow through the equipment, and the excess H2 prevents the formation of coke as the charge is heated to reaction temperature.
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H2/HC Ratio
The charge heaters combined feed exchangers, compressors, etc., have been designed to allow for the circulation of a minimum ratio of hydrogen to hydrocarbon charge. This ratio, expressed as standard cubic meter of H2 per cubic meter of feed (Nm3/M3) is on the order of 209Nm3/M3. The H2/HC ratio is an economic optimum, balancing initial investment against catalyst life. If the unit is operated at less than the design H2/HC ratio, higher catalyst bed and charge heater tube wall temperatures will result, leading to accelerated coke formation and equipment wear. A complete loss of recycle gas can result in very serious damage to the catalyst and equipment, therefore, a safety device is incorporated in all units to shut down the charge heaters whenever the recycle gas flow drops to a predetermined minimum. Other steps to be taken during such as emergency are more completely described in the Emergency Procedures section of this manual. The H2/HC ratio is calculated as follows :
H2/HC
Totalgasat standardconditionsper unit timeto reactorsx H2purity Rawoil chargeper unit time
As the amount of gas that can be circulated is a function of the compression ratio, a gradual reduction in recycle gas rate will be observed during the course of an operating period as a result of higher reactor system pressure drop. Such a reduction in the recycle gas rate is acceptable as long as the calculated H2/HC ratio does not fall below the minimum value. When it is no longer possible to maintain the minimum H2/HC ratio, the catalyst must be regenerated and screened in order to reduce the reactor pressure drop. In all cases that result in less than design H2/HC ratio due to pressure drop or mechanical difficulties, the raw oil charge rate must be lowered in order to obtain the required H2/HC ratio. In the event of a complete loss of recycle gas, immediate remedial action must be taken to protect the catalyst: and equipment, as described in the Emergency Procedures section of this manual. 10.1.8
Recycle Gas Hydrogen Purity
The effective completion of the hydrogenation reactions occurring over the catalyst requires that a certain quantity of hydrogen be present at a minimum partial pressure. As noted previously, both the quantity (H2/HC) and partial pressure are dependent upon the hydrogen content, i.e. purity, of the recycle gas. Practical considerations, such as the cost of compression, catalyst life, etc., limit the purity of the recycle gas to a normal value usually in the range of 82 to 85 mol%. Lower hydrogen purities are detrimental to the performance of the unit since higher temperatures must be used to achieve the desired product quality. The purity of the recycle gas is determined by the following factors : n) The purity of the make-up gas. o) The amounts of 1ight hydrocarbons and H2S that are allowed to accumulate in the recycle gas.
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In most instances, the makeup gas H2 purity cannot be easily manipulated since it is fixed by the operation of the platformer. The light hydrocarbons present in the recycle gas enter the system with the make-up gas in addition to those being formed in the reactor, and must be vented from the high pressure separator to prevent their accumulation in the recycle gas This can be achieved by increasing the make-up gas rate thus venting more gas through 15-PIC003. The H2S formed in the reactors can reach equilibrium values as high as 5-mol% in the recycle gas. This concentration of H2S has a depressing effect on the activity of the catalyst, therefore, it is desirable to remove the H2S from the recycle gas. The removal of H2S is performed in a scrubber 1502E where the recycle gas in contacted with a monoethanolamine (MEA) solution. In this manner, the H2S content of the recycle gas can be reduced to the part per million range. The design flow of lean amine to 1502 E is 28543kg/hr or 28.6m2/hr at 15FIC-017. 10.1.9
Contaminants
The sulfur and nitrogen found in the feed can be considered contaminants to the extent that they produce hydrogen sulfide and ammonia which can react to form ammonium sulfide. The water injected into the reactor effluent dissolves the ammonium sulfide and prevents exchanger fouling. Organic nitrogen in the feed, if present in amounts higher than expected, will require higher reactor temperatures for processing, and will lead to a reduction in catalyst life. Alkaline metals are permanent catalyst poisons and must be completely excluded. Solid material, such as corrosion products, wi11 lead to rapid fouling of the catalyst bed if allowed to enter the reactor. CONTROL OF FURNACE OPERATION
10.2 10.2.1
Heating Control
During the ignition and the gradual firing rate increase of the burners, check the outlet temperature of the coils. If it does not rise, shut-off the heat, and look for the reason,
Increase progressively the heat, watching the flue gas temperature at the bridge wall. For information, the temperature rise rate can be about 50℃/hr at this control point.
The firing rate must be brought up gradually. As a matter of fact, during this period, the heat must be supplied both to the charge and to the furnace taken as a whole. A too fast increase of the firing rate can cause an over heating of the tubes, and of the fluid to be treated and crack the refractories.
In case of fluid circulation shut down, shut off immediately the burners. However, the furnaces are provided with safety devices which shut off the fuels automatically in case of loss of product through the coils. Up to the half of the normal burners heat liberation, it will be better to adjust manually
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the burners. Then, it will be possible to operate with the automatic control-valve taking care not to increase suddenly the fluid during the operation.
When the outlet temperature of the charge reaches its normal operating level, the swing to automatic may be attempted.
Adjust the draft and excess air accordingly by means of the stack damper and burners registers.
Combustion conditions: Draft
:
9.4 mm W.C. approximately at the bridge wall F 1501 B
Draft
:
6.6 mm W.C. approximately at the bridge wall F 1501 B
Excess air :
20% approximately with fuel gas 30% approximately with fuel oil
10.2.2
Combustion Control
Draft 7 The draft must be adjusted by means of the damper located in the flue gas outlet of the furnace. The draft should be periodically checked by means of draft gauges which are fitted on the furnace. A minimum draft should be obtained, without leaving the furnace under positive pressure. Excess Air A checking of the excess air must be carried out, The excess air adjustment depends on the burners air registers opening. Flames Aspect The various burners should have flames as uniform in length and size as possible. Under no circumstances should the flames be permitted to touch tubes or furnace walls. Tubular Coils The regular and periodical control of the combustion minimizes the external and internal coating of the tubular coils : coke, ash, etc 10.3
FURNACE OPERATING VARIABLES
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Pressure at the Top of the Furnace
The furnace is designed so that there is a negative pressure. Draft gauges must be installed to measure the draft. Their zero has to be set and frequently checked. 10.3.2
Flame Contact with Tubes
Flame impingement on tube surface decreases their service life duration and can cause serious damage. At regular intervals and particularly after any change in load, make sure that the flame impingement does not occur, and that no local hot spots are visible on the furnace walls. An incorrect flame aspect can be caused by a misalignment of burners, a lack of combustion air or erosion and corrosion of the burner ports and tips. Refer to interventions on burners. 10.3.3
After-burning
When the furnace is operating with insufficient combustion air, the flue gases are growing in carbon monoxide and an after-burning may occur at the bottom or at the top of the stack, according to the carbon monoxide content. An after-burning causes a rapid increase in flue gas temperature in the stack, and deterioration of the stack and of the structural steel may occur. If an after-burning is noticed, an action must be immediately taken :
Reduce the firing rate, Then, open slowly the burner registers in order to introduce As scan as the after-burning has ceased and the furnace is free of carbon monoxide, the firing rate may be increased
An after-burning is due to a bed combustion control, and to a lack of flue gas analysis. 10.3.4
Low Flow of the Charge Rate
A reduction or a shut down of the circulation in the tubular coils causes immediately an over heating of the tubes and requires an immediate reduction of the heating or the emergency shut down of the furnace. 10.3.5
Fuel Failure
Burners must be shut off when the fuel pressure reaches a value less than 10 % approximately of the minimum operating value.
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In case of a complete failure independent of the unit operation, close the burners manual valves, reduce the draft and close the combustion air registers, in order to avoid a quick cooling of the furnace. When it is possible to light burners again, proceed as indicated in the section describing furnace start-up. 10.3.6
Incidents with Fuel Gas Burners
p) Gas Burners Extinction The gas burners may be extinguished for the following main reasons : When the draft is too high, When the combustion air is not correctly adjusted. When the burners operate at too high or too low pressure, compared with those for which they are designed, When there are condensates in the gas feed pipe, particularly at high operating rate. Consequently, the gas circuit must be carefully preheated and purged When the firing rate is too rapidly reduced, without adjusting the draft and excess air accordingly q) Irregular Gas Burner Flames This can be due to:
10.3.7 r)
Insufficient combustion air. The flame smokes, is irregular and tends to be unstable. The combustion air registers must be properly adjusted, Excessive firing: at a high rate, the flame is long and irregular. Reduce the firing rate, Obstruction of the burner orifices : the gas manifold must be dismantled and the obstructed orifices cleaned, Draft excess: when the draft is too high, flames begin to lift-off, relight and cause smell explosions. Draft failure: when there is no draft, the furnace begins to smoke and flames tend to come out through the peepholes and registers. Reduce the firing rate and adjust properly the stack damper.
Incidents With Fuel Oil Burners The fuel jets from burners A faulty atomization can be caused by :
s)
insufficient fuel preheating, obstruction of atomizer tips, a heterogeneous mixture of the various fuel components, or a lack of atomization steam.
Burners extinction
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There are two main causes
t)
reduced flow of atomization steam, i.e. PDIC not working properly. too much combustion air : under low operating conditions the too large amount of combustion air makes the f1ame unstable, and it may go out : reduce the opening of burners air registers.
Coking of burners tips This event can be caused by a faulty atomization, by the quality of the fuel content in dirt or asphaltene. A fuel film forms on the burner tips and cokes under the effect of the heat radiated by refractories blocks. Burners should be dismantled and cleaned, and the fuel preheating temperature should be checked. The fuel oil temperature should be about 120℃ Check that the oil tips are correctly positioned and, if necessary, adjust the all gun higher.
10.3.8
Smoke Excess at Stack The most common reasons are the following : excess of liquid fuel, bad conditioning of liquid fuel, high asphaltene content, insufficient excess air, insufficient atomization steam, water carry-over in the atomization steam.
10.3.9
Recurring Burners Maintenance Remove periodically all burners and clean them, after complete dismantling. The frequency of this cleaning should depend on the fuel used.
Make sure that no coke deposits occur on refractories bricks, Make sure that the fuel does not accumulate in the burners,
During unit shut down, check the dimensions of the orifices of the oil tips and atomizers. In addition :
10.4
Check the refractories blocks. Replace worn or broken parts, Check the dimensions of drilling of the gas nozzles, Replace the worn parts, enlarged or ovalised holes, Check the pilot operation. Clean atomizer and mixer.
OFF SPEC & SLOP HANDLING
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The normal destinations and alternate destinations of off-spec products in case of start-up, shut down or maloperation of the unit are listed below: PRODUCT
NORMAL DESTINATION
OFF-SPEC DESTINATION
LGO
Storage
Light Slop
Wild Naphtha
Unit 11 /Crude pump suction
Light Slop
Slop Handling shall be in accordance to the requirement of QPR-R-PS-PR-011. CHAPTER 11: NORMAL SHUT-DOWN PROCEDURE This section covers normal shut downs of the gas all desulphuriser when there is no emergency, e.g. for catalyst regeneration. 11.1
REACTION SECTION
A normal shutdown a controlled cooling down and removal of the feed from the unit. The shutdown can be a short term occurrence midway through the catalyst’s life cycle due to maintenance requirements or due to shut-down of upstream or downstream units. In this case, it is expected that the reactor will be restarted after the shutdown. A long-term shutdown will come at the end of the catalyst life, cycle. In this case, the catalyst will either be replaced or regenerated. The following procedure addresses both cases described above. 1) Warn all units which may be affected, that shutdown of the unit is imminent (crude unit, platformer, amine regeneration and off-sites). 2) Reduce heat input to the unit to cool the reactor at a maximum of 30C/hr (50F/hr). 3) Switch product run-down to off-spec storage. Gradually decrease feed rate to nominally 50 percent of design. If processing a cracked stock. Remove the cracked portions of the blend first. Use suitable flushing oil to purge cracked material or high pour point gas oil from the system. If the unit is fed from the crude unit do not close the battery limit block valve. Close the valve at the inlet of the feed surge drum and reroute the raw gas oil from the crude unit to the inlet of the stripper bottoms cooler 1504C/C1. Caution: Do not forget to route the product stripper bottoms to slop or intermediate storage to avoid pollution of the treated storage before carrying out the above-mentioned operation. Valve 15-LV-010 will have to be manually open to allow raw product to be sent to storage. As the stripper reboiler 1502B is still in operation care will be taken not to lose the stripper bottoms pump suction by closing the block valve on the 6" bottoms product to storage at the outlet of the feed/bottoms exchanger 1503C1/C3. 4) If the shut-down will be temporary :
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u) Continue cooling with treat gas and flushing oil until the maximum reactor temperature reach 175C (350F). If not involved in the shutdown maintenance, the reactor does not need to be further cooled. The flushing oil can be put on recycle or stopped. Continue recycle gas circulation. v) Maintain the amine circulation and keep the amine regenerator hot unless the shutdown will be for an extended period. w) If the reactor or associated hot equipment is to be worked on, continue cooling as necessary with treat gas. Depressurize the unit before cooling below the ductile-brittle transition temperature. x) If the high-pressure loop is to be worked on, depressurize the loop and purge with nitrogen. Otherwise, maintain the hydrogen atmosphere. 5) If the purpose of the shutdown will be to remove the catalyst or to regenerate: y) Cool the reactor at 30C/hr (50F/hr) with treat gas and flushing oil until the temperatures reach 230C (450F). z) When the reactor inlet temperature reaches 230C (450F), remove flushing oil completely and shut down the amine system. aa) Circulate recycle gas at the maximum rate and increase the reactor inlet temperature to 400C (750F). Hold the reactor inlet temperature to 400C (750F) for 2 hours. bb) Begin cooling the reactor at 30C/hr (50F/hr) with recycle gas. Reduce the pressure appropriately in the unit before cooling below the ductile-brittle transition temperature. cc) After the reactor loop is cool, purge with nitrogen. dd) Drain the feed surge drum 1501F, and then shut down the charge pump 1503J/JA (in good time) just before it loses suction. ee) Stop the water injection to the reactor effluent line. ff) Drain the reactor effluent separator 1502F into the stripper feed flash drum 1503F. When no more liquid collects close the contro1 valve 15-FV-013. gg) The hydrogen make-up must be shut off at battery limit, the make-up compressor cylinder unloaded, and the cylinder by-pass opened. hh) Open the 6" recycle gas scrubber by pass line and block the scrubber inlet. Stop the MEA flow to the scrubber. Block the MEA inlet and outlet keeping a liquid seal at the bottom ii) Shut down the wash water pump 1504J/JA.
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jj) When the reactor temperature is about 218℃, shut down the charge heater 1501B, shut down the make-up and recycle compressor, and close suction and discharge valves. kk) Pressure any remaining liquid in the reactor effluent separator 1502F and the LP flash drum 1503F to the product stripper 1501E. Close block valve. ll) Depressurize the reactor to flare via the depressing valve, 15-XV-030. mm) If equipment is not to be opened, care must be taken to maintain a positive pressure of about 0.35 barg. nn) If equipment is to be opened, it should be drained, purged with nitrogen and blinded off during shut down. 11.2
STRIPPER SECTION
6) When the reactor feed is cut out, start reducing the firing of the stripper reboiler furnace. Once the reactor effluent separator is drained, pressure the liquid contents of the stripper feed flash 1503F drum into the product stripper 1501E 7) When the stripper feed stops, cut out the firing of the stripper reboiler furnace 1502B. The overheads will reduce rapidly in volume and the amount of off-gas leaving the product stripper overhead drum will also diminish until the product stripper off-gas compressor 1502J has to be shut down. 8) Stop the corrosion inhibitor injection. Shut down 1502LJ. However if units 12 and 14 are running, the HC release drum 1602F may produce low pressure gas and depending upon the amount, the stripper off-gas compressor 1502J/JA may have to be kept on line or acid gas may be evacuated to the acid gas flare through 15-PV-005A. 9) When no more liquid collects in the product stripper overhead drum, 1504F, empty the drum into the tower and then shut down the product stripper reflux pump 1505J/JA. 10) Shut off the gasoline to crude unit at battery limit then pressure out any liquid in the compressed gas K.O. drum 1506F to 1504F. 11) When the stripper bottoms temperature is down to about 200℃, empty the product stripper to slop or intermediate storage by manually opening the block valve on the 6" stripper bottom line. 12) Block off the reactor system purge gas at the 15-PIC-003 control valve and close the valve in the 6" gas scrubber by-pass line. Depressurize the compressed gas K.O. drum 1506 F and the stripper feed flash drum 1503F using the 1" vent to flare making sure that the battery limit valve is closed. 13) Depressurize the feed surge drum 1501F to flare via 15-PV-001B. 14) If towers or drums are not being opened, care must be taken to maintain a positive pressure of
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about 0.3 barg on the system using fuel gas via the start up connection. 15) If towers or drums are to be opened, they should be drained, steamed out, washed and blinded.
11.3
FURNACE SHUTDOWN
11.3.1
Normal Shut Down
Reduce the heating gradually to lower temperature of the treated fluid following the instructions of the operating manual and reduce the flue gas temperature which leaves the radiant zone or arch by about 50℃/hr. When the temperature of the feedstock reaches the required value :
Keep a small steam flow for a few minutes to avoid oxidation of the burners tips, Do not introduce too much purge steam too rapidly, otherwise burners go out too quickly and unburnt fuel is ejected into the furnace,
If another start up is forecast immediately, close the combustion air registers and stack damper, so that the furnace does not cool too rapidly, Stop the circulation in the tubular coils.
Otherwise, ventilate the furnace by leaving the burners, registers and the stack damper wide open. 11.4
PROTECTION OF FURNACE
11.4.1
Short Shut Down
Control and maintenance periods
11.4.2
Avoid any water admission into the furnace. Long Shut Down
Refer to unit shut down procedure. In addition
The tubular coils should be free of product and dry.
It is advisable, when the stoppage is foreseeable, to introduce a drying agent into the fire box. After this operation, see part AFTER ASSEMBLY, refractories will remain dry and no
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further dry-out is required.
At the furnace start up the temperature rise at the arch must exceed 27℃/hr with a leveling off at 150℃ during about 12 hours.
CHAPTER 12: EMERGENCY SHUT-DOWN PROCEDURE 12.1 LOSS OF NORMAL FEEDSTOCK Objective: Maintain hydrogen pressure to minimize cokes formation and cool the catalyst with recycles gas. The loss of normal feedstock may have different causes depending on the way the unit is fed. Possibilities include: 16) Shut-down of the crude unit, 17) Shut-down of the feed pump from intermediate storage if the crude unit is not on line, 18) Or failure of the unit charge pump 1503J itself. The following action is to be taken : Since the charge heater transfer temperatures will drop due to heater shutdown initiated through 15FALL-002, proceed as follows d) Shut down the charge pump 1503J/JA if the failure is from an outside source. e) Maintain water injection to the reactor effluent at the same rate as before the emergency. Take special care to prevent water from entering the stripper. f)
Maintain normal working levels in all vessels.
g) Cool the catalyst bed to at least 200℃ with recycle gas before charging oil again to the reaction section. 12.2
RECYCLE AND MAKE-UP COMPRESSOR FAILURE
1501J/JA recycle and make-up compressors are provided with safety devices : 19) 15-TAHH-049 (053), high discharge temperature make-up compressor 1501J1(JA1)
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20) 15-TAHH-051 (055), high discharge temperature recycle compressor 1501J2(JA2) 21) 15-LAHH-012, high level make-up drum K.O. drum 1508F(common) 22) 15-PALL-038, low pressure make-up compressor suction(common) 23) 15-LAHH-008, high level recycle gas K.O. drum 1507F(common) 24) 15-PALL-003X(023X), low pressure lube oil 1501J1/JA1/J2/JA2 In case of recycle and make-up compressor failure, the following action is to be taken: The charge heater 1501B will trip automatically through the safety device 15-FALL-007 low recycle gas flow, then : a) Immediately shut down and block in the charge pump 1503J b) Put the spare compressor on line as quickly as possible after the fault has been cleared, if it is a common fault, or immediately if it is a specific compressor fault. c) Shut down and block in the water injection pump. d) Once the compressor has been restarted, cool the catalyst bed to at least 200℃ before restarting the charge pump 1503J. 12.3
LOSS OF MAKE-UP HYDROGEN
In the event of a failure of the hydrogen-rich make-up gas, due to shut-down of gas platformer for example, and before the recycle and make-up compressor is tripped through low pressure make-up compressor suction safety mechanism, cut the feed rate down to the minimum in order to reduce hydrogen consumption and drop of reaction section pressure (to minimize coke formation). If the failure is prolonged, stop the liquid feed and shut down the unit in the normal manner. 12.4
TEMPERATURE RUNAWAY
This is a serious situation which requires immediate attention. It can be brought about by equipment or utility failures which result in a significant reduction in space velocity (this results in a reduction of gas capability to remove the heat of reaction from catalyst), thereby overheating during a startup, or it can even occur during normal operation. The period during startup before the catalyst has been thoroughly sulphurated is perhaps the most critical time when very special care should be taken to control the reactor temperatures, as outlined in the startup procedure. During a temperature runaway, highly exothermic demethylation reactions can take place. It is not necessary, however, to have demethylation occurring in order to have a temperature runaway. When there is a significant increase in residence time of feedstock on the catalyst, and especially when this is coupled with the loss or reduction of a large heat removal stream such as recycle gas, excessive cracking reactions can take place, resulting in severe overheating. Catalyst temperatures
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can rise rapidly to well above thc reactor design temperature in such a situation, even though the cracking has not progressed to the point of demethylation. In order to sustain a temperature runaway, both hydrocarbons and hydrogen must be available. Therefore, removing one or the other will cause the reactions to stop. The quickest way to achieve this, and still maintain hydrogen pressure to minimize coke formation, is to remove the liquid hydrocarbon feed from the reaction by stopping all feed, sweeping the catalyst with recycle gas circulation, and providing maximum cooling to the catalyst. If the temperature rise cannot he controlled, however, then the system should be rapidly depressurized to suppress the reactions and to minimize the danger of damage to the reactor and other equipment. Proceed as follows : e) Stop the liquid feed by shutting down and blocking in the feed pump, and shut down the reactor charge heater immediately. f)
Keep the recycle compressor running at maximum rate.
g) Maximize cooling on air-fin coolers in the recycle gas circuit to provide the maximum amount of cooling possible to the catalyst. h) Maintain water injection to the reactor effluent at the same rate as before the emergency. TAKE SPECIAL CARE TO PREVENT LIQUID WATER FROM ENTERING THE STRIPPER. Open the stack damper and all air registers to the full open position to establish the maximum flow of cooling air through the heater fire-box. i)
Hold the system pressure at the normal level if the temperature rise in the reactor can be brought under control. If the rate of temperature increase indicates the maximum allowable operating temperature will be exceeded (at normal operating pressure) at any point, either on the reactor itself or in the catalyst bed, then depressurize the reactor circuit to flare from the recycle gas knock-out drum at a rate at least 50percent of the vessel’s design gauge pressure within approximately 15minutes, utilizing 15-HS-030A/B. Continue depressurizing at this rate until the plant pressure is reduced to 60 % of the normal operating pressure. Closely monitor all catalyst and reactor outlet temperatures, and if any of these temperatures continue to rise unchecked, then increase the depressurizing rate to the maximum possible and continue depressurizing to as low a pressure as necessary to try to stop the temperature rise. If it appears that any temperature point, either on the reactor itself or in the catalyst bed, will exceed the reactor design temperature, do not stop depressurizing when the 60 % pressure level is reached, bolt continue depressurizing at the maximum rate possible to minimize any danger of damage to the reactor and other equipment. It should be noted that when depressurizing at accelerated rates, it will most likely be necessary to provide maximum cooling to the reactor products condenser to prevent overheating that exchanger. If temperatures remain high after the unit has been depressurized, then begin purging the reactor with nitrogen at the maximum rate possible.
j)
If recycle compressor operation can be maintained, continue maximum gas circulation and make-up rate and cool all catalyst temperature points and the reactor outlets to 200℃.
k) If recycle compressor operations cannot be maintained, immediately shut down and block in all
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make-up gas compressors to cut off any additional supply of hydrogen to the reactions and to allow for more rapid depressurizing of the system. l)
With all temperatures below 200℃, pressure the unit with make-up hydrogen.
m) If it was necessary to depressurize the unit to a very low level, necessitating shutting down the recycle compressor, then the water injection system should be shut down also. n) Put the recycle compressor on line and after it runs satisfactorily for one hour without difficulty and all catalyst temperatures remain below 200℃, load the make-up compressor and pressure to normal operating pressure with hydrogen. UTILITY FAILURE
12.5 11.4.2
Power Failure
On power failure, some equipment is automatically reaccelerated upon restoration of the power. Two cases have to be contemplated : oo) 415V half-board temporary failure. BUS BAR A or BUS BAR B and E. After a delay of about three seconds due to automatic transfer, power will be again available and the equipment fed from this helfboard and included in the reaccelerating group will be automatically restarted. There are four different reacceleration groups : 1, 2, 3, and 4 :
Group 1
:
equipment will restart after about 15 seconds.
Group 2
:
equipment will restart after about 20 seconds
Group 3
:
equipment will restart after about 25 seconds,
Group 4
:
equipment will restart after about 30 seconds,
These delays include the three seconds automatic transfer scheme. pp) 415V general failure : emergency board In case of complete loss of power, the emergency generator will start and after a delay of about 60 to 90 seconds the power will be restored to the emergency board. Motors connected to the emergency board will then be reaccelerated following their reaccelerating group. Motors with no reacceleration group will have to be restarted manually. The pattern is as follows : 415V Medium voltage.
Operating Manual LGO Hydrotreating unit (Unit 15)
Bus Bar
A
B
E
Step
DELAYS (SECONDS) TEMP. EM GEN
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ROLE
1502C
3
25
85/115
Reactor effluents cooler
1505C
1
15
75/105
Stripper overhead air cooler
1501 J1/J2 J2M
1
15
75/105
1505 J Oil pump
1501 JA1/JA2 J2M
1
15
1505J
2
20
80/110
Product stripper reflux pump
1505JA
2
20
80/110
1506J
1
15
Product stripper reflux pump Product stripper buttons pump
1506JA
1
15
1504C/C1A
1
15
1501 JA all pump
Product stripper buttons pump Bottoms product air cooler
In normal operation the emergency board is coupled with BUS BAR B. As the feed pumps 1503J/JA and the recycle and make-up compressors 1501J/JA are fed from the 3.3 kV board, these equipments will not shut down in case of 415V medium voltage board failure. The charge heater will keep running. On temporary failure, the effluent reactor cooler 1502C will automatically restart after about 25 seconds. It might be safer to cut the charge rate down to 50% to avoid overheating the HP flash drum 1502F. The stripper reboiler should not trip as the low flow safety 15-FALL-022 cut off is fitted with a temporization and the spare pump starts automatically through 15-FALL-023. The stripper overhead cooler 1505C will restart after 15 seconds and the reflux pump 1505J will restart after 20 seconds. The bottoms product air cooler 1504C will have to be restarted immediately and product routed to intermediate storage to avoid pol1ution of the treated product storage tank. In all cases when cutting back the charge rate to the reaction section, and if the crude unit is running, the excess raw gas oil from U11 must be routed to 1504C and the blend raw gas oil plus bottoms product sent to intermediate storage or slop. General power failure
qq)
In addition of the equipment above mentioned, the recycle and make-up gas compressor 1505J1/JA1/J2/JA2 and the charge pump 1503J/JA will trip. On a full electrical failure the fire in the furnaces should be cut immediately, the unit shut down as far as possible in the usual way, and the vessels left with liquid levels ready to he restarted when the power returns. 12.4.2
Steam Failure
The steam header pressure to Unit15 is indicated in the control room by 15-PI-117. A steam failure will lead to loss of atomizing steam and snuffing steam for the furnaces 1501B and
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1502B. 13.4.2
Cooling Water Failure
A cooling water failure will affect : rr) the stripper off-gas compressor after-cooler, 1506℃. ss) compressor jacket and lube oil cooling 1501J1/JA1/J2/JA2, 1502J/JA tt) pump cooling 1503J/JA, 1507J To avoid damage to the rotating machinery it should be shut down as soon as possible unless a temporary water supply can be made available (e.g. from hose connections). 14.4.2
Instrument Air Failure
The actions of the control valves are arranged so that a general instrument air failure will leave the unit in a sate condition. If possible, maintain the recycle gas circulation as long as possible while shutting down the plant in the normal manner. A close check should be kept on the recycle loop pressure, any excessive pressure being manually vented via the H.P. separator relief valve bypass. The unit may be left with pressures and levels maintained in the vessels until the fault is rectified. 15.4.2
Make-up Gas Failure
In the event of a failure of the hydrogen rich make-up gas the feed rate must be cut as necessary, probably by at least 50%. The firing must be adjusted accordingly. If the failure is prolonged, the start-up circulation procedure should be maintained for as long as possible and the unit then shut-down in the normal manner.
VALVES POSITION ON INSTRUMENT AIR FAILURE TAG NUMBER
LOCATION
ACTION
FLOW 15-FV-006 15-FV-001A/B 15-FV-013(reset UC04) 15-FV-017 15-FV-016(reset UC05) 15-FV-021 LEVEL
H2 recycle to 1501B charge heater GO to 1501 B charge heater Level control of HP flash drum 1502F Lean amine to recycle gas scrubber 1502E LP flash drum 1503F level control Reflux to product stripper 1501E
open closed closed closed closed open
Operating Manual LGO Hydrotreating unit (Unit 15) 15-LV-003 15-LV-006 15-LV-010 15-LV-011 15-LV-016 15-LV-036
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Interface level HP flash drum 1502F Recycle gas scrubber 1502E level control Product stripper 1501E level control Stripper reflux drum 1504F level control Compressed gas RO drum level control Interface level LP flash drum 1503F
closed closed closed closed closed closed
HIC/XV 15-HIC-001X
1501B Damper
open
15-HIC-002X
1502B Damper
open
15-XV-005
1501B Safety shut-off valve Fuel gas to main burners
15-XV-003
1501B Safety shut-off valve Pilot gas
closed
15-XV-006
1501B Safety shut-off valve Fuel oil to main burners
closed
15-XV-007
1502B Safety shut-off valve Fuel gas to main burners
closed
15-XV-004
1502B Safety shut-off valve Pilot gas
closed
15-XV-008
1502B Safety shut-off valve Fuel oil to main burners
closed
15-XV-030
Emergency depressing valve
closed
open
PRESSURE 15-PV-001A 15-PV-001B 15-PV-003 15-PV-004 L5 PV 05A 15-PV-005B 15-PV-006
Feed surge drum pressure control Fuel gas make-up Feed surge drum pressure control to flare HP flash drum 1502F Pressure control LP flash drum 1503F pressure control Stripper reflux drum 1504F pressure control to flare Sour gas compressor 1502J/JA kick-back Make-up gas knock-out drum 1508F pressure control during regeneration. 1501 B F6 to main burners 1501 B Pilot gas 1501 B Fuel oil to main burners 1501 B Atomizing steam 1502 B F6 to main burners 1502 B Pilot gas 1502 B Fuel oil to burners 1502 B Atomizing steam
15-PV-007 15-PCV-024 15-PV-009 15-PV-011 15-PV-012 15-PCV-025 15-PV-014 15-PV-016
closed closed closed closed closed open open closed control closed open closed control closed open
TEMPERATURE 15-TV-016
12.6
Desulphurization Reactor 1501D temperature control
open
CHARGE HEATER TUBE RUPTURE
Objective : Stop adding hydrogen and hydrocarbons to the fire in the heater box through the process lines, purge with steam/nitrogen to the rupture to prevent air from entering the process lines and equipment. Action as follows if possible :
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o) Shut down and block in all liquid feed pumps to the reactors. p) Shut off all fuel supply and return lines to the heaters and open snuffing steam to the box. q) Open the stack dampers wide. r) Shut down and block in the make-up and recycle gas compressors, and the water injection pump. s)
Depressurize the unit to flare with 15-HS-030A/B.if it has not already been depressurized into the heater box.
t)
After the system is depressurized, hook up steam hoses to both sides of the heater and purge through to the rupture to prevent air from back-flowing through the rupture and forming an explosive mixture with hydrocarbons in the system. If purging must pass through the reactor, then the purging material should be nitrogen instead of steam.
12.7
EXTERNAL FIRE
Objective : Rapidly shut down the unit and depressurize (if necessary) to prevent further damage. Be aware of the possibility that high temperatures could be generated rapidly in the catalyst bed, and be prepared to take appropriate action per instructions in paragraph 4. Action as follows if possible, and as applicable : u) Shut down and block in the liquid feed pump to the reactors, 1503J/JA. v) Shut off all fuel supply and return lines to heaters 1501B/1502B. w) Unload make-up gas compressor, but maintain recycle gas compressor operation as long as possible. x) Cool the catalyst to 200℃ with recycle gas circulation. y) Shut down and block in the water injection pump after the catalyst has been cooled to 200℃, but in any case before the recycle compressor is shut down. z) Depressurize to flare and purge with nitrogen, as applicable to the situation. In order to deal with other situations, same remote shutdown switches are provided : 16) 15-HS-007A /15-HS-008A Emergency shutdown switches located in the control room. These shut off all the fuels including the pilot gas to the heaters 1501B/1502B.
17) 15-HS-007B/15-HS-008B
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These switches are located outside and at least 15m from furnace at grade. This has the same action as 15-HS-007A/15-HS-008A above mentioned. 18) 15-HS-012A/15-HS-014A Located in the control room. They shutdown the compressors (one switch for each compressor) and close the associated motorized valves at the suction and discharge. 19) 15-HS-012B/15-HS-014B These switches are located outside and at least 15m from the compressors 1501J1/JA1/J2/JA2. They shutdown the compressors (one switch for each compressor) and close the associated motorized valves at the suction and discharge. 20) 15-HS-030A Located in the control room. This provides a quick means for depressurizing the reaction section if required. 21) 15-HS-030B Located outside. This has the same action as 15-HS-030A above mentioned. 12.8
EMERGENCY SHUT-DOWN FOR REACTOR
Emergency shutdowns may be caused by failures of various kinds. The action to be taken is primarily dictated by personnel and equipment safety considerations. However, in order to protect best the catalyst from damage, it should be kept in mind that the catalyst may be damaged by: aa) Hot hydrogen without hydrogen sulphide or oil: This will tend to strip sulphur from the sulphided catalyst and at prolonged exposure to these conditions, there is a risk of reducing the metals with to free metals with consequent permanent loss of activity. bb) Hot oil without hydrogen: Operating with a hot oil on the catalyst without any hydrogen will result in coke formation on the catalyst, leading to loss of catalyst activity and increased pressure drop. cc) Contact with water condensate: Exposing the catalyst to liquid water or high water vapor concentrations at elevated temperatures can result in loss of catalyst strength. Therefore, any slugs of water into the reactor inlet streams must be avoided. dd) Back-flow: Back-flow through the reactor should be avoided due to the risk of lifting of the catalyst bed and support. With the above in mind, the following emergency procedures should be observed.
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ee) If the charge pump shuts down, the treat gas will continue. However, the heater will not respond quickly to the sudden loss in flow. To prevent overheating, the heater should automatically cut back to minimum fires or shut off the fuel to the main burners. Pilots can be kept in service to facilitate return to normal service. If the pump cannot be started within 15 minutes, continue to cool the reactor at a rate of 30C/hr (50F/hr) to 230 (450F). Stop the amine circulation in the scrubber. The recycle gas compressor should be kept at maximum to maximize the cooling of the reactor. ff) If the recycle gas compressor shuts down, the oil will stagnate in the reactor. The feed pump should automatically shut down, the heater should cut back to minimum fires or shut off the fuel to the main burners. The make-up gas compressor should be kept at maximum to sweep oil from the heater tubes and catalyst. gg) If the make-up gas compressor shuts down, the pressure will decay as the hydrogen is consumed. If the make-up gas compressor cannot be restarted immediately, the feed should be removed and the unit cooled down as described for normal short-term shutdown. hh) If the amine supply is stopped, the H2S concentration in the recycle gas will increase and inhibit catalyst activity. The unit can continue to operate for a short time although the product may be off spec. Maximize recycle gas purge until limited by the make-up gas compressors’ ability to maintain loop pressure. Decrease feed rate to reduce the off spec. material and reduce sulphur input. If the amine system cannot be restarted reasonably quickly and the shut down the unit as described above for normal short-term shutdown. ii) If the wash water injection pump shuts down, operations can continue but be aware that ammonium salts may start to precipitate in the colder heat exchangers. Ammonia will be absorbed in the amine solution and that could potentially upset a downstream sulphur plant. The unit is equipped with an emergency depressurizing system and the unit is depressurized to meet as following:
To drop pressure at a rate equivalent to 7 bar/min (100 psi/min) tar the first minute.
The emergency depressurizing system is connected to the normal flare and used to rapidly drop the pressure in the unit in case of fire or other major emergency. 12.9
EMERGENCY UNIT SHUT-DOWN
In case of significant disastrous situation, initiate unit shutdown by pushing the emergency shutdown switch(15-HS-030A or 15-HS-030B), depend upon the desires of the supervisor. Otherwise, do the following if possible.
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Operating Manual LGO Hydrotreating unit (Unit 15)
CHAPTER 13: DETAILED DESCRIPTION OF ALL UNIT UTILITIES 13.1 UTILITY CONDITION 13.1.2
Steam
System Identification
Pressure (barg)
Temperature (C)
Min.
Norm.
Max.
Design
Min.
Norm.
Max.
Design
LLLP Exhaust Steam
-
0.7
-
5.0
-
115
-
203
LLP Steam
-
3.5
-
9.3
-
148
-
203
LP Steam
-
6.9
8.0
9.3
-
173
-
203
MP Steam
-
13.9
17.0
19.0
-
198
-
230
HP Steam
-
40.0
42.0
46.0
-
420
-
440
Notes: 1. In addition to the above, saturated high press. Steam is produced from sulfur unit. 2. LLP steam will be available only within 47/49 unit area. 13.1.3
Steam Condensate
System Identification
Process Area Battery Limit Pressure (barg)
Temperature (C)
Normal Design Normal Design At Condensate Tanks Inlet
1.0
9.3
65 to 100
To Users(for LP steam desuperheaters)
14.2
18.0
65 to 90 120
Pumped
To Users(for HP steam desuperheaters)
59.0
79.0
65 to 90 120
Pumped
To Users(for process water)
4.5
12.0
Notes: At condensate tank pump discharge: pH = 6.0 to 8.0 Total dissolved solids = 13 to 22 ppm
60
130
Two Phase (Unpumped) or All Liquid (Pumped)
100
Unpumped if possible.
Pumped
Operating Manual LGO Hydrotreating unit (Unit 15) Total iron 13.1.4
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= 1 to 1.3 ppm
Cooling Water
Description Source
Circulation and Cooling Water Cooling tower
Supply Pressure (barg) at Battery Limit
3.8 (MIN.)
Return Pressure (barg) at Battery Limit
2.3
Supply Temperature from Cooling Tower C
35
Return Temperature to Cooling Tower C
43.5C
Cooling Water System Mechanical Design Temperature C
75
Cooling Water System Mechanical Design Pressure bar g
6.0
Exchanger Fouling Resistance(min.) mª C hr/kcal
0.0004
Cooling Water Quality
Description
Circulation and Cooling Water
pH
8.5 to 8.7
Total Hardness, ppm
400 to 500
Total Alkalinity, ppm
310 to 370
Conductivity, micromhos/cm
1,200
Total Dissolved Solids, ppm
700 to 770
Chloride, ppm
250 to 320
Total Phosphorus, ppm
7 to 8.5
Dissolved Phosphorus, ppm
5.4 to 7.7
Total Iron, ppm
0.4 to 0.8
Chlorine, ppm
0.2 to 0.8
Total Zinc, ppm
1 to 1.5
Dissolved Zinc, ppm Turbidity, JTU Bacterial Count, m.col/cc
0.75 to 1.3 3 to 6 0.01 to 0.1
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Operating Manual LGO Hydrotreating unit (Unit 15) Process Water and Boiler Feed Water System
Deaerated Treated Boiler Feed Water LP Boilers Actual
MP Boilers Actual
HP Boilers Actual
(From 5102U)
(From 5102UA)
(From 5104U)
(Note 1)
(Note 1)
(Note 1)
Supply Pressure at B.L (barg)
13.8
20.5
59.0
Supply Temperature (C)
107
107
107
Design Pressure (barg)
20
25
88
Design Temperature (C)
150
150
150
8.5 to 9.2
8.5 to 9.2
9.3 to 9.5
0.2 to 1.0 (10)
0.1 to 0.5 (10)
0.1 to 0.6 (2.0)
Calcium (as CaCO3), ppm wt
0.1 to 1
0.1 to 0.4
0.1 to 0.5
Iron (as Fe), ppm wt
Nil (N.A)
1.0 to 1.3 (N.A)
0.8 to 1.0 (N.A)
0.01 to 0.05 (0.05)
0.01 (0.05)
Trace (0.02)
5
5
5
100 to 200
60 to 80
80 to 100
40 to 70
1 to 2
10 to 17
100 (700)
100 (700)
100 (500)
3000 (3000)
1400 (3000)
2000 max. (2000)
- (200)
- (200)
- (50)
N.A
N.A
N.A
800 to 1400 (N.A)
20 to 40 (N.A)
200 to 340 (N.A)
Description
Boiler Feed Water at Boiler Inlet PH Total Hardness (CaCO3), ppm wt
Oxygen, ppm Total Alkalinity (as CaCO3), ppm wt TDS, wt ppm Chloride (as CL), ppm wt Boiler Water in Steam Drum Total Alkalinity (as CaCO3), ppm wt TDS, wt ppm Suspended Solids, ppm wt Conductivity, micromhos/cm Chloride (as CL), ppm wt
Notes: 1. The figures in parenthesis are required maximums in accordance with BS 2486 : 1978. 2. N.A : Not Applicable. 3. Above figures are estimated considering expected make up ratio of Dealkalized water with Recovered Steam Condensate to produce Boiler Feed Water based on Steam Balance. For LP/MP/HP Boilers, estimated make up ratio of Dealkalized water are 100 / 0 / 22 % respectively and 5 % of blow down rate was applied. There are four types of Process Water being used: jj) Condensate (see 13.1.2). kk) Softened treated water (see 13.1.9). ll) Stripped sour water. mm) Phenolic stripped sour water
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Operating Manual LGO Hydrotreating unit (Unit 15) 13.1.6
Fuel System
Liquid Fuel Properties:
Existing
Revamp (1)
Net Heating Value kcal/kg
:
9,500
9,275 to 9,309
Sulphur wt%
:
3.62
3.25 ~ 3.33
Nitrogen ppm wt
:
-
N.A (2)
Vanadium ppm wt
:
11.0
150 Max.
Sodium ppm wt
:
2.0
N.A (2)
Existing
Revamp (1)
Nickel ppm wt
:
8.0
N.A (2)
Iron ppm wt
:
2.0
N.A (2)
Ash ppm
:
-
Copper ppm wt
:
2.0
:
17.5 to 20.5
11.25 ~ 11.29
: :
19 500
3.0 ~3.6 8.9 ~12.1 @50oC
Vapor Pressure (barA)
:
Negligible
Negligible
Flash point (C)
:
174C
74 ~ 77C
Pour point (C)
:
21C
14 ~ 16C
767 ~ 902 N.A (2)
Data: API Viscosity
cSt @ 99.0C cSt @ 37.8C
Supply Header Operating Pressure (barg) Maximum
:
10.0
10.0
Normal
:
8.0
8.0
Minimum
:
7.0
7.0
Design
:
14.0
14.0
: : : :
3.0 2.5 2.0 14.0
3.0 2.5 2.0 14.0
Return Header Operating Pressure (barg) Maximum Normal Minimum Design
Supply Header Operating Temperature (C)
@100oC
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Operating Manual LGO Hydrotreating unit (Unit 15) Maximum Normal Minimum Design
: : : :
Flow Rate (m3/hr)
120 150
50 150
As required
As required
Notes: 1. Expected Composition changes are due to blending and Refinery feed cases. 2. N.A : Not Available.
Gaseous Fuel Properties:
Case 3
Case 1
Case 2
Supplementary
Normal Revamped
Fuel Gas for
Normal Existing
Fuel Gas
Refinery Fuel Gas
Condensate Unit
Refinery Fuel Gas
H2 O
-
1.15
0.1
-
O2
-
-
-
-
N2
4.45
3.08
0.67
0.2~0.8
CO
-
-
-
-
CO2
2.19
-
0.33
0.1~0.4
H2 S
0.9
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