lpg merox operating manual merox

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JOB No. JGC DOC. No. REV. 0-3100-25 S-260-1283-001 R2 DAT 31 Mar. 2004 SHEET 1 OF 94 PREP T.Akama CHKD H.Shiraishi APPD T. Watanabe

OPERATING MANUAL

UNIT 2600

RFCC LPG MEROX UNIT

SOHAR REFINERY COMPANY L. L. C.

SOHAR REFINERY PROJECT

SOHAR, SULTANATE OF OMAN

Reference ITT Doc. No. Rev

- -

REV. DATE PAGE DESCRIPTION PREPD CHKD APPD

0 31 Mar 2004 All For Approval T.A H.S T.W R 28 Apr 2005 All For Construction (As per OS-JY-E-21028, 20986,

20371, JY-OS-E-20888, 20870 and JY-OY-X-23353)

T.A H.S T.W

R1 28 Sep 2005 36,65,94 For Construction (as per correction of attachment list) T.A H.S T.W R2 8-Nov-2005 94 For Construction H.S T.W T.W

PROJECT SPECIFICATION

Sohar Refinery Company SOHAR Refinery Project

FOR CONSTRUCTION

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JOB CODE: 0-3100-25Sohar Refinery Company SOHAR Refinery Project

DOC NO: S-260-1283-001 Rev.R2 Operating Manual for Unit 2600 SHEET : 2 of 94

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CONTENS 1. General Description ....................................................................................................................... 5 1.1. Plant duty.................................................................................................................................... 5 1.2. Principles of process................................................................................................................... 5 1.3. Design basis ............................................................................................................................... 8

1.3.1. Feeds 8 1.3.2. Products 9 1.3.3. Design Considerations 9 1.3.4. Material balance 9

1.4. B.L. Conditions ......................................................................................................................... 10 1.5. Utility and Chemicals Requirements ......................................................................................... 10

1.5.1. Utility Requirements 10 1.5.2. Chemical Requirements 10

2. OPERATING CONDITIONS AND CONTROLS............................................................................... 11 2.1. Process Flow and Control......................................................................................................... 11

2.1.1. Process Description 11 2.1.1.1. Pretreatment Section....................................................................................................... 11 2.1.1.2. Extraction Section ........................................................................................................... 11 2.1.1.3. COS removal section ................................................................................................. 11 2.1.1.4. Caustic Regeneration Section......................................................................................... 12

2.1.2. Summary for Main Equipment 12 2.1.2.1. Tower Summary ......................................................................................................... 13 2.1.2.2. Drum summary........................................................................................................... 16 2.1.2.2. Drum summary........................................................................................................... 17 2.1.2.3. Reactor summary ....................................................................................................... 25 2.1.2.4. Fired heater summary ................................................................................................ 25 2.1.2.5. Exchanger summary .................................................................................................. 25 2.1.2.6. Pump summary .......................................................................................................... 25 2.1.2.7. Compressor summary ................................................................................................ 26 2.1.2.8. Special equipment summary ...................................................................................... 26

2.1.3. Process Flow Control 26 2.2. Process Variables and Their Effects ......................................................................................... 29

2.2.1. Catalyst Concentration 29 2.2.2. Oxygen Injection 29 2.2.3. Alkalinity 31 2.2.4. Contact 31 2.2.5. Heat (Temperature) 34

3. EMERGENCY EQUIPMENT ........................................................................................................... 35 3.1. Safety Valves and Their Set Pressure ...................................................................................... 35

3.1.1. Summary of Safety Relief Valves 35 3.1.2. Summary of Flare Loads 35

3.2. Car Sealed Valves .................................................................................................................... 35 3.3. Remote Operating Valves......................................................................................................... 36 3.4. Instrument Alarms..................................................................................................................... 36 3.5. Instrument Trip Settings............................................................................................................ 36

4. PREPARING UNIT FOR PRE-COMMISSIONING........................................................................... 38 4.1. General Preparation for Pre-commissioning............................................................................. 38 4.2. Vessel Inspection...................................................................................................................... 38 4.3. Line Cleaning............................................................................................................................ 39 4.4. Service and Calibrate Instruments............................................................................................ 39 4.5. Run-in of Rotary Machineries ................................................................................................... 39 4.6. Chemical Cleaning.................................................................................................................... 39 4.7. Refractory Drying of Fired Heater ............................................................................................. 40

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4.8. System Drying .......................................................................................................................... 40 4.9. Loading of Chemical, Catalyst and other Materials................................................................... 40 4.10. Operational Tightness Test.................................................................................................... 40 4.11. Air Freeing ............................................................................................................................ 40

5. COMMISSIONING (INITIAL START UP) ........................................................................................ 41 5.1. General Overall Commissioning Plan....................................................................................... 41 5.2. Step-by-step Start-up Procedure and Process Priority.............................................................. 41 5.3. Special Precautions .................................................................................................................. 43

6. NORMAL START-UP & SHUTDOWN............................................................................................. 44 6.1. Normal Start-up after Prolonged Shutdown .............................................................................. 44 6.2. Normal Start-up after Short Shutdown ...................................................................................... 44 6.3. Normal Operations ................................................................................................................... 44

6.3.1. Monitoring and Control 45 6.3.1.1. Amine Treatment ........................................................................................................ 45 6.3.1.2. Water Wash................................................................................................................ 45 6.3.1.3. Caustic Prewash ........................................................................................................ 45 6.3.1.4. Circulating Caustic ..................................................................................................... 46 6.3.1.5. Regenerated Caustic from Disulfide Separator .......................................................... 48 6.3.1.6. COS Removal ............................................................................................................ 49 6.3.1.7. Sand Filter .................................................................................................................. 49 6.3.1.8. Optimization ............................................................................................................... 49

6.3.2. Summary of recommended Operating ranges for Variables 51 6.4. Routine Operation .................................................................................................................... 54

6.4.1. Miscellaneous Procedures (Trouble Shooting) 54 6.4.1.1. Extraction ................................................................................................................... 54 6.4.1.2. Regeneration.............................................................................................................. 54 6.4.1.3. Tools for Narrowing Origin of Problem........................................................................ 55

6.4.2. Special Procedures 56 6.4.2.1. Merox WS Catalyst Addition ....................................................................................... 56 6.4.2.2. Sand Filter Backwashing ............................................................................................ 57

6.5. General Overall Shutdown Plan................................................................................................ 57 6.6. Blind.......................................................................................................................................... 59 6.7. Opening Equipment .................................................................................................................. 59 6.8. Special Precautions .................................................................................................................. 60

7. EMERGENCY SHUTDOWN & LOGICS ......................................................................................... 61 7.1. General Instructions.................................................................................................................. 61 7.2. Fire ........................................................................................................................................... 61 7.3. Power Failure ........................................................................................................................... 62 7.4. Instrument Air Failure................................................................................................................ 62 7.5. Steam Failure ........................................................................................................................... 62 7.6. Cooling Water Failure ............................................................................................................... 62 7.7. Fuel Gas Failure ....................................................................................................................... 62 7.8. Natural Gas Failure................................................................................................................... 62 7.9. Major Equipment Failure........................................................................................................... 63 7.10. Hydrogen Failure .................................................................................................................. 63 7.11. Amine Failure........................................................................................................................ 63 7.12. Nitrogen Failure .................................................................................................................... 63 7.13. Flare Problem ....................................................................................................................... 63 7.14. Feed Failure.......................................................................................................................... 63 7.15. DCS Failure by Inst ............................................................................................................... 63 7.16. PLC Failure by Inst................................................................................................................ 63 7.17. Boiler Feed Water Failure ..................................................................................................... 64 7.18. Air Blower Failure.................................................................................................................. 64 7.19. Slide Valve Failure ................................................................................................................ 64

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7.20. Wet Gas Compressor Failure................................................................................................ 64 8. EQUIPMENT & INSTRUMENT LIST............................................................................................... 65

8.1. Equipment List.......................................................................................................................... 65 8.2. List of Instruments .................................................................................................................... 65

9. FLOW PLANS AND PLOT PLAN ................................................................................................... 66 9.1. PFDs, MSDs and P&IDs......................................................................................................... 66 9.2. Design engineering and safety flow plans ................................................................................ 66 9.3. Plot Plan ................................................................................................................................... 66 9.4. Cause and effect charts............................................................................................................ 66

10. SAFETY....................................................................................................................................... 67 10.1. Emergency Fire Plan............................................................................................................. 67 10.2. Fire Fighting and Protective Equipment ................................................................................ 68 10.3. Toxic Gas Leak Detection System......................................................................................... 68 10.4. Maintenance of Equipment and Housekeeping..................................................................... 68 10.5. Repair Work .......................................................................................................................... 69 10.6. Thermal Expansion in Exchangers........................................................................................ 69 10.7. Withdrawal of Samples ......................................................................................................... 70 10.8. Safe Handling of Volatile and Toxic Materials including Catalyst........................................... 70

10.8.1. Respiratory Protection 70 10.8.2. Breathing Apparatus (B. A.) 71 10.8.3. Poisonous Material 71

10.8.3.1. Sodium Hydroxide (NaOH Caustic Soda) ..................................................................... 71 10.8.3.2. Catalyst/Reagents ......................................................................................................... 72 10.8.3.3. Hydrogen Sulfide (H2S) ................................................................................................. 72 10.8.3.4. Disulfide ........................................................................................................................ 72 10.8.3.5. MEA-NaOH ................................................................................................................... 72

10.9. Preparing Process Equipment............................................................................................... 73 10.10. Opening Equipment .............................................................................................................. 74 10.11. Working on Tanks.................................................................................................................. 74 10.12. Entering Tanks, Drums or Other Vessels .............................................................................. 75 10.13. Procedure for Removing Safety Valves................................................................................. 75 10.14. Work permit Procedure and Work permit Formats ................................................................ 75 10.15. Operation Notes relating to HAZOP Review ......................................................................... 76 10.16. Material Safety Data Sheet (MSDS)...................................................................................... 79

11. MISCELLANEOUS ...................................................................................................................... 90 11.1. Catalyst and Chemical Loading / Unloading ......................................................................... 90 11.2. Catalyst and Chemicals Requirements ................................................................................. 90 11.3. Analytical Plan ...................................................................................................................... 90

12. ATTACHMENT LIST OF OPERATING MANUAL FOR RFCC LPG MEROX UNIT..................... 94

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1. General Description

This Operation Manual covers the operational procedures for the RFCC LPG MEROX UNIT, Unit 2600, in the Sohar Refinery Project constructed in Sohar, Sultanate of Oman. This Manual refers to the following documents:

(1) Process Flow Diagrams (2) Piping & Instrument Diagrams (3) Utility Flow Diagram (4) Equipment List (5) Relief Load Summary (6) Cause & Effect Diagrams

This specification is for design purposes only. This is useful as a guide in operation and does not necessary represent exact operating conditions or guarantees.

1.1. Plant duty

The duty of the RFCC LPG MEROX Unit is to remove organic sulfur by caustic extraction as well as inorganic sulfur by amine treating from RFCC LPG and send the treated LPG to the Propylene Recovery Unit (U-2700). The RFCC LPG Merox Process Unit consists of four sections: the Pretreatment Section for H2S removal, the Extraction Section for mercaptan removal, the COS removal section and the Caustic Regeneration Section that is used common with CDU LPG MEROX unit.

1.2. Principles of process (1) Outline of process scheme

Low molecular weight mercaptans are soluble in caustic soda solution. Therefore, when treating LPG, the Merox process can be used to extract mercaptans, thus reducing the sulfur content of the treated product. In the extraction unit, sulfur reduction is directly related to the extractable mercaptan content of the fresh charge. The LPG Merox process utilizes liquid-liquid contacting to extract the mercaptans from the hydrocarbon with a strong aqueous alkali solvent. The mercaptan-rich solvent, which also contains the dispersed Merox catalyst, is sent to a regeneration section where air is injected and the mercaptans are oxidized to disulfides. The disulfides are subsequently separated from the solvent by coalescing, gravity settling, and decanting; the regenerated lean solvent is recycled back to the extractor. Thus, the process consists of two steps; mercaptan extraction and solvent regeneration. The name Merox originates from the function of the process itself; namely the conversion of mercaptans by oxidation. MERcaptan OXidation The word mercaptan is a descriptive name applied over 140 years ago to organic

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compounds with a sulfhydryl function (-SH) and derived from the Latin mercurium captans, due to their mercury seizing properties. Todays literature, however, assigns the word thiol for this functional group. In the common system used by the petroleum industry, mercaptans are named after their analogous alcohol counterparts. Thus, CH3SH, by the common system, is methyl mercaptan just as one would name an alcohol having the formula CH3OH methyl alcohol; the strict formal name is methanethiol. Likewise, n-butyl mercaptan becomes 1-butanethiol, t-butyl mercaptan becomes 2-methyl-2-propanethiol. The aryl mercaptans are commonly called thiophenols, while in the formal systems used by Chemical Abstracts, these compounds are benzenethiol, toluenethiol, etc. This discussion uses the common mercaptan terminology as practiced in the petroleum industry. (2) Overall Merox Reaction Mercaptans are undesirable for many reasons. The lower boiling mercaptans are moderately acidic and characterized by an extremely offensive odor. These properties diminish as the mercaptan molecular weight increases. Thio-phenol, which is an aryl mercaptan and more acidic than alkyl mercaptan, is found principally in cracked hydrocarbons. Thiophenol is undesirable in finished LPG because it produces an unstable LPG by promoting the hydroperoxidation of olefins to gum. In summary, mercaptans are undesirable in finished petroleum products to whatever extent. Their presence is considered to adversely affect the products odor, stability, total sulfur content, etc. The Merox process in all its applications is based on the ability of an organometallic catalyst to accelerate the oxidation of mercaptans to disulfides at near ambient temperatures and pressures. Oxygen is supplied from the atmosphere. The overall reaction can be written: RSH + O2 RSSR + H2O R is a hydrocarbon chain which may be straight, branched, or cyclic. These chains may be saturated or unsaturated. In most petroleum fractions, there will be a mixture of mercaptans to the extent that the R chain might have 1,2,310 or more carbon atoms in the chain. When this reaction occurs, two different mercaptans might enter the reaction. This is indicated by showing R and R in the reaction. The reaction is then written: 2RSH + 2RSH + O2 2RSSR + 2H2O This reaction occurs spontaneously, but at a very slow rate, whenever any sour mercaptan bearing distillate is exposed to atmospheric oxygen. (3) Mercaptan Extraction Extraction is applied to both gaseous and liquid hydrocarbon streams. The degree of completeness of mercaptan extraction depends upon the solubility of a mercaptan in the alkaline solution. That, in turn, depends primarily upon the following: molecular weight of mercaptan degree of branching of mercaptan molecule caustic soda concentration

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temperature of the system As the molecular weight of the mercaptan increases, solubility in the alkaline solution decreases, and as chain branching increases, solubility decreases. The following equation illustrates the mechanism of mercaptan extraction: RSH + NaOH NaSR + H2O This is a reversible reaction. The equilibrium degree of completion is affected by the law of mass action and the variables outlined above. Of course, nothing can be done to control either the amount or the molecular weight of the mercaptan present, as this is a function of the crude source and distillation cut of the feed. However, for a mercaptan of the same molecular weight, primary mercaptan will be most completely extracted, secondary mercaptan will be less completely extracted, and tertiary mercaptan will be the least completely extracted. This, too, is a function of the feedstock. Because of these factors, mercaptan extraction is used mainly for low boiling range petroleum fraction such as the C3/C4 fractions and light gasolines, which only contain low molecular weight mercaptans, and where a reduction in sulfur content is needed or desired. (4) Merox Caustic Regeneration Once the mercaptan is in the caustic solution, it is readily oxidized to disulfide when Merox catalyst is present.

NaSR + O2 + H2O NaOH + RSSR

The disulfide thus formed is insoluble in the caustic solution and can be separated from it so that the caustic can be reused for extracting mercaptan from additional hydrocarbon feed stock. This oxidation reaction is not reversible. The theoretical amount of oxygen needed is independent of the mercaptans molecular weight or structure. The reaction rate is speeded up by: Raising the temperature Increasing the amount of air Increasing the mixing rate or intimacy of contact Increasing the catalyst concentration. Note that Merox catalyst does not affect amount of extracted mercaptan; that is, the concentration of Merox catalyst does not improve on solubility of mercaptan in caustic. It is usually observed that mercaptan extraction is better with the Merox process because of the lower mercaptan content of the regenerated caustic when using Merox catalyst and air, as compared to the method of regeneration using steam stripping. The catalyst used for the Merox unit is a type soluble or dispersible in water (UOP Merox

Secondary mercaptan Primary mercaptan

H

C R SH

H

Tertiary mercaptan

H

C R SH

R

R

C R SH

R

Catalyst

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WS Reagent). It is shipped as a dark-blue aqueous slurry packaged in 1 gallon plastic bottles. Under proper conditions the catalyst can be made to disperse in water and thereby transferred into the unit. Although the disulfide formed is insoluble in the caustic solution, it is soluble in the hydrocarbon. Therefore, by injecting wash oil (Diesel), the disulfide can be separated from the caustic solution so that the caustic can be reused for extracting mercaptan.

(5) COS Removal System

The need to remove carbonyl sulfide (COS) from liquid propane, propylene, and liquefied petroleum gas (LPG) streams has become more prevalent in recent years. Carbonyl sulfide is present in LPG products derived from natural gas and from cracking units in which feedstocks with high sulfur content are processed. Carbonyl sulfide is formed under certain conditions when both hydrogen sulfide (H2S) and carbon dioxide (C02) are present. The reaction illustrating this formation is as follows:

H2S + CO2 COS + H2O The reverse of this reaction, called hydrolysis, often occurs under ambient temperature conditions and can be catalyzed by molecular sieves and other desiccants during product dehydration. The H2S formed often causes the product to fail the copper-strip corrosion test. Hence, COS should be removed if a product is to be dried over molecular sieves and other desiccants. In other cases, COS must be removed if end product is to meet a total sulfur specification. In recent years, the total sulfur specification of propylene (COS typically concentrates in the propylene fraction) has been reduced to lower and lower values thereby necessitating COS removal. To remove the trace quantity (parts per million) of COS that remains, UOP offers a simple and economical process that uses an aqueous monoethanolamine (MEA) and sodium hydroxide (NaOH) solution. The simplified reactions are assumed to be as follows:

COS + 2 MEA Diethanol Urea + H2S (1) H2S + 2 NaOH Na2S + 2 H2O (2) COS + 2 MEA + 2 NaOH 1 Diethanol Urea + Na2S + 2 H2O (3)

The COS-containing feed is contacted with the circulating MEA-NaOH solution. This solution is made up to an initial concentration of approximately 20 wt-% MEA and 8 to 10 wt-% NaOH. Steam condensate (or the equivalent) is used for dilution.

1.3. Design basis

1.3.1. Feeds

The feed to the RFCC LPG MEROX Unit is the C3/C4 net overhead liquid from the Debutanizer Receiver at the Gas Concentration Process Unit of RFCC unit (Unit 2200). The RFCC LPG MEROX Unit shall be designed to treat 29,371 BPSD of untreated LPG.

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1.3.2. Products

The design specification for treated LPG from RFCC LPG MEROX Unit is as follows:

PROPERTY VALUE Use of product Propylene & LPG Will product go to fractionation? Yes RSH-S, wppm max. 5 Reentry-S + RSH-S, wppm max. 10 COS-S, wppm max. 1 Sodium (Na+), wppm max. 1

1.3.3. Design Considerations

Not shown 1.3.4. Material balance (1) Feed Rate and Compositions

The feedstock rates and compositions used for the design purpose are shown below:

PROPERTY VALUE Design Case Maximum Olefin Case Normal Rate, BPSD 29,371 Turndown Rate, BPSD 14,685 Composition, kgmol/hr H2S 2.93 Methane 0.00 Ethane 0.18 Ethylene Trace Propane 195.12 Propylene 998.46 n-Butane 81.14 i-Butane 208.87 Butenes 695.23 n-Pentane 0.21 i-pentane 8.51 Pentene 8.88 C6+ PROD 0.00 Total, kg/hr 107,946 Sp. Gr. @ 15C 0.555 Total Sulfur, wt % 0.14 RSH-S, wppm max. 474 COS-S, wppm max. 30

(2) Product Rates and Compositions

The product rates and compositions used for design purpose are referred to Attachment 9.1 (PFD of the RFCC LPG MEROX Unit) for details.

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1.4. B.L. Conditions When the unit is operating at design throughput, the temperature and pressure of the feed and products shall be as follows: Temperature, oC Pressure, barg (at Grade) Feed Untreated LPG 38 17.5 (*1) Wash Oil (Diesel from DHDS Unit) 38 6.0 (*1) Lean DIPA 38 28.6 (*1) Plant Air 38 7.0 Product Treated LPG at Battery Limit to U-2700 38 13.4 Treated LPG at Off Spec LPG Header 38 12.5 Rich DIPA 38 16.0 (*1) Disulfide Oil 38 3.8 (*1) (*1) These values are estimated by the hydraulic calculation and not guaranteed.

1.5. Utility and Chemicals Requirements

1.5.1. Utility Requirements

Refer to Attachment 1.1 (Utility Summary of the RFCC LPG MEROX Unit, Doc. No. S-260-1223-501) for details.

1.5.2. Chemical Requirements Refer to Attachment 1.1 (Catalyst and Chemical Summary of the RFCC LPG MEROX Unit, Doc. No. S-260-1223-502) for details.

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2. OPERATING CONDITIONS AND CONTROLS 2.1. Process Flow and Control

2.1.1. Process Description

The RFCC LPG Merox Process Unit consists of four sections: the Pretreatment Section for H2S removal, the Extraction Section for mercaptan removal, the COS removal section and the Caustic Regeneration Section.

2.1.1.1. Pretreatment Section

LPG from the Gas Concentration Unit of RFCC Unit (U-2200) is fed to the bottom side of the Amine Absorber (C-2651) for counter-current, liquid-liquid contacting with a 35 wt% Di-isopropanolamine (DIPA) solution from the Amine Regeneration Unit (U-3500). Lean amine enters the top of the absorber and flows downward while contacting the upward flowing LPG. The rich amine is removed from the bottom of the absorber and is returned to the Amine Regeneration Unit. The LPG is advanced to the Caustic Prewash vessel (V-2601) where it is batch contacted with 10o Baume caustic for the removal of residual H2S. LPG from the Caustic Prewash then enters the Extraction Section. The H2S concentrations at the outlet of Amine absorber and caustic Pre wash vessels during normal operation are as follows: - H2S concentration at the outlet of Amine absorber: Maximum 20 wtppm as sulfur - H2S concentration at the outlet of caustic Pre wash vessels: Negligible

Spent caustic is sent to the Waste Water Treatment Unit (U-6500) via the Spent Caustic Degassing Drum (V-2609) which vents to the relief header.

2.1.1.2. Extraction Section

The LPG from the Caustic Prewash is fed to the bottom of the Extractor (C-2602) for counter-current, liquid-liquid contacting with 20o Baume caustic from the Regeneration Section. Lean caustic enters the top of the Extractor and flows downward while contacting the upward flowing LPG. The rich caustic is removed from the bottom of the Extractor and returned to the Caustic Regeneration Section. The treated LPG leaves the top of the Extractor and enters COS removal section

2.1.1.3. COS removal section

The COS-containing LPG from the top of the Extractor is contacted with the circulating MEA-NaOH solution. This solution is made up to an initial concentration of approximately 20 wt-% MEA and 8 to 10 wt-% NaOH. Steam condensate (or the equivalent) is used for dilution. The COS-containing LPG-solution mixture is passed through an adjustable mixing valve; Pressure drop across the mixing valve provides the contact needed to complete the chemical reactions. The mixture is allowed to separate by gravity in a horizontal settler, the COS Solvent Settler (V-2602). The settler also acts as the holding vessel for the MEA-NaOH solution inventory. The MEA-NaOH solution is withdrawn from the bottom of the settler and is recirculated back to the hydrocarbon feed to complete the circuit. Unit pressure is regulated by a back-pressure controller set high enough to keep the LPG in the liquid state. Operating temperature is not critical, and a typical product rundown temperature of 90-110F (32-43C) is generally used. Treated hydrocarbon exits from the top of the settler and is routed to a sand

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filter (V-2603) for coalescing and removal of the last traces of entrained MEA-NaOH solution. The treated LPG is sent to the Propylene Recovery Unit (U-2700). (see Figure 2.1).

2.1.1.4. Caustic Regeneration Section

The mercaptan rich caustic leaves the bottom of the Extractor and flows to a low-pressure steam exchanger where it is heated to initiate the mercaptide oxidation reaction. Air is injected into the caustic stream downstream from the Caustic Heater (E-2601) to provide oxygen for the oxidation reaction. The air and caustic enter the bottom of the Oxidizer (V-2604). Merox WS catalyst is intermittently injected into the rich caustic stream to maintain the required catalyst activity level. From the Oxidizer, the mixture enters the stack of the Disulfide Separator (V-2606) where the spent air is separated from the caustic/disulfide oil mixture. The spent air leaves the top of the stack where it mixes with a fixed amount of fuel gas, and the spent air/fuel gas mixture is sent to the RFCC Steam Heater (F-2002). The disulfide oil and caustic are separated in the horizontal portion of the Disulfide Separator. The regenerated caustic leaves the bottom of the Disulfide Separator and is pumped to the Extractor by the Caustic Circulation Pumps (P-2602 A/B). The disulfide oil is discharged from the top of the horizontal section of the Disulfide Separator and enters the Disulfide Sand Filter (V-2607), which coalesces and removes any entrained caustic. Then the disulfide oil is normally pumped by the Disulfide Oil Pumps (P-2607 A/B) to the Distillate Unifining Unit (U-3200). 2.1.2. Summary for Main Equipment

Figure 2.1 UOP COS REMOVAL SYSTEM

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Note that the dimensions, design conditions and material of equipment are indicated in the Equipment list S-260-1224-001. The operating conditions of equipment are indicated in PFD D-260-1223-101. Consequently, both Equipment list and PFD should be referred to understand the abstract of main equipment deeply. 2.1.2.1. Tower Summary

(1) RFCC LPG Amine Absorber (C-2651)

The RFCC LPG Amine Absorber is provided on the LPG feedstock containing relatively high concentrations of acid gases (H2S and CO2). An aqueous solution of an amine, Di-isopropanolamine (DIPA), is utilized in a counter-current contact to extract the acid gases (Figure 2.2). The absorber is provided with three beds of liquid - liquid contacting packing. The Amine Absorber will remove acid gases to an equilibrium level dependent on amine regeneration; however, this level is not low enough to send amine treated feed directly to a Merox unit. Further pretreatment in the form of a caustic prewash is required to remove the last traces of acid gases present.

Figure 2.2 Amine Absorber, C-2651

Rich Amine to U-3500

LPG to Caustic Prewash

V-2601

LPG from U-2200

Lean Amine from U-3500

FC

C-2651

LC

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(2) Extractor (C-2602)

The Extractor is a vertical vessel consisting of eight numbers of specially designed perforated trays (Figure 2.3). Each tray (Figure 2.4) consists of a caustic inlet reservoir with the inlet weir separating this reservoir from the central mixing region. The center section is the mixing region of each tray and contains perforations to allow the up-flowing hydrocarbon to contact the cross-flowing caustic. The caustic mixes with the hydrocarbon, disengages as it is carried upward and overflows the outlet weir, collecting in the caustic outlet reservoir. A downcomer pipe transfers the caustic to the next tray inlet reservoir by gravity flow. Since the caustic flow rate is often an extremely low rate relative to the hydrocarbon flow, it is very important that both inlet and outlet weirs are level. Also, no caustic leakage can be tolerated at any point in the tray. The trays should be entirely sealed except for manways; these are sealed with neoprene rubber gaskets. The initial checkout should include a water leak test. For this test the downcomer pipes are plugged and filled with water to the top of the outlet weir. If the inlet weirs have holes accessing the mixing region for drainage purposes, these should be plugged and the inlet reservoirs leak tested as well. Both reservoirs should contain no leaks. Even the tiniest leak will serve to reduce extraction efficiency and capacity by upsetting the carefully designed hydraulics. When the caustic flow rate is less than 0.70 m3/hr, the inlet weir drainage hole should be omitted or welded shut. The hydrocarbon inlet or feed tray contains no holes in the mixing section but instead contains an inlet distributor designed with holes oriented downward to distribute hydrocarbon over the bottom of the feed tray (Figure 2.5). The size and number of holes should be verified. The end must be capped. The bottom of the Extractor column serves as a caustic surge reservoir for the entire system. It is fitted with a level glass and level indicator with a low level alarm.

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Hydrocarbon and RSH

Rich Caustic

Regenerated Caustic

Treated Hydrocarbon

Figure 2.3

Extractor, C-2602

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Figure 2.4 Extractor Tray

Figure 2.5 Feed Tray

Downcomer

Distributor

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2.1.2.2. Drum summary

(1) Spent Caustic Degassing Drum (V-2609) The Spent Caustic Degassing Drum is a small, vertical vessel designed to remove entrained gases/vapors from the withdrawn spent caustic from the Caustic Prewash (V-2601, V-1201), the COS Solvent Settler (V-2602) and the sand Filter (V-2603, V-1202). Withdrawal of spent caustic from the Caustic Prewash is intermittently done based on the concentration (% Spent) of the caustic. See Figure 2.6 (Caustic Prewash). The feed stream enters the vessel via an inlet weir located on the no. 2 tray; then flows through no. 1 tray to the bottom of the vessel. The off gas from the Degassing Drum is sent to the Relief Header and the degassed spent caustic collected at the bottom of the vessel is pumped to the Waste Water Treating System on level control. (2) Caustic Prewash (V-2601) A single batch-type caustic prewash is used when removing moderate levels of hydrogen sulfide, H2S, (up to ca. 100 wt-ppm). The simple batch-type caustic prewash is used in the unit which consists of a single vertical vessel. Hydrocarbon enters the bottom of the vessel and jets through a distributor with holes oriented downward. The distributor hole area and orientation is designed to provide adequate mixing and should be checked for conformance to specification. The number and size of the distributor holes will vary with the application. The vessel is normally operated half full of dilute caustic and caustic is replaced batch-wise. A full diameter stainless steel wire mesh blanket is provided in the upper section of the vessel below the hydrocarbon outlet to coalesce and remove most of the entrained caustic. The mesh blanket should be adequately secured to its support with tiedown wires. Periodic inspections should be conducted to evaluate mesh blanket integrity. The batch prewash is normally supplied with two inlet distributors, one near the bottom and the second several feet up. Normal operation utilizes the bottom distributor. The top distributor, with holes oriented upward, is used only when it is necessary to change-out caustic. This upward hole orientation allows a calm caustic phase essentially free of undissolved hydrocarbon to be withdrawn from the bottom of the vessel.

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(3) COS Solvent Settler (V-2602) In order to remove the trace quantity of COS that remains in the extracted LPG, an aqueous monoethanolamine (MEA) - sodium hydroxide (NaOH) solution is mixed. The COS Solvent Settler (V-2602) is a horizontal vessel designed to permit gravity separation of MEA-NaOH solution from the hydrocarbon product. The settler also acts as the holding vessel for the MEA-NaOH solution inventory. The MEA-NaOH solution is withdrawn from the bottom of the settler and is recirculated back to the hydrocarbon feed to complete the circuit. An inlet distributor is provided to avoid excess inlet turbulence and promote an even flow distribution through the vessel. It usually consists of a single pipe arranged vertically through nearly the full width of the vessel diameter with one full length slot facing the nearest head of the vessel. The spent solution is sometimes replaced batch-wise and pressured out of the settler via a degassing drum (V-2609) to release any entrained gases. The gases are vented to the refiner's flare system. See Figure 2.7

Figure 2.6 Caustic Prewash

V-2601 Amine Treated

LPG Feed

Pre-washed LPG to the Extraction Section

Lean Caustic

12

V-2609

To Relief Header

M To Effluent Treatment System

LIC

Start/Stop

P-2603

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(4) Sand Filter (V-2603) The sand filter is provided to coalesce any entrained caustic solution. Hydrocarbon product from a properly maintained sand filter will usually be visibly clear and contain less than 1 wt ppm sodium. The sand bed consists of 2 m depth of 8-16 mesh silica sand. The sand bed is supported on a special Johnson Screen proprietary design steel grid with 0.025 inch (0.6 mm) openings. Hydrocarbon enters at the top of the vessel, through a slotted distributor, passes downward through the sand bed, through the support grid, and makes a 135o turn before exiting from the side of the vessel, below the sand support grid. The hydrocarbon outlet is protected by a special chordal baffle permitting the coalesced aqueous phase to run down the walls and collect at the bottom of the vessel. Care should be taken that the sand is of the same size and grading as specified so that excessive pressure drop does not develop. Make sure that the sand support is correctly installed. Check the levelness and for sealing strips over the section joints. Make certain that the nylon rope packing around the perimeter of the support grid is properly installed. The first two inches (50 mm) of sand should be loaded by hand via the side manway, leveled, and allowed to sit for about one hour. This will confirm proper support grid installation and absence of any unobserved leaks. Temporarily cover the inlet distributor with plastic film or cloth to prevent the sand from seeping into the distributor slot. The sand is preferably loaded with a sock to prevent any cone effect and classification from developing. The sock loading method also reduces the amount of dust generated if the sand is dry.

Figure 2.7 COS Solvent Settler

LPG Product Extracted LPG

Spent Caustic to Degassing Drum

V-2602

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(5) Oxidizer (V-2604) The Oxidizer is a vertical vessel designed as a mixer to contact rich caustic from the bottom of the Extractor, containing Merox catalyst and sodium mercaptides, with air for regeneration. Since this vessel will contain mixed vapor/liquid phase, packing is provided in the form of 1-1/2 inch (38 mm) diameter carbon Raschig rings. Carbon composition is used because it is inert to the strong caustic and severe oxidizing environment encountered. Because these rings are subject to breakage, the loading should be done with the vessel filled with water. A caution is added that the vessel should be completely filled of rings, flush with the top manway. Otherwise ring attrition will occur as a result of abrasive contact caused by subtle shifting action. An inlet distributor is provided consisting of a perforated pipe enclosed by a slotted sleeve. The slot in the sleeve points downward while the holes in the pipe are oriented upward. This arrangement is designed to provide maximum mixing. Should the inner pipe ever plug or require modification, it can be removed without having to unload the Raschig rings. Any outlet connection should be protected by a bar grating, which usually consists of a inch (6 mm) bar welded across the nozzle to prevent any Raschig ring migration. The vessel drain is protected by a broken ring trap consisting of a slotted pipe to exclude ring fragments.

Figure 2.8 Sand Filter

To Flare

Product Bypass

Backwash

Backwash Connection

To Caustic Regeneration

V-2603

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(6) Wash Settler (V-2605)

The Wash Settler is a horizontal vessel designed to permit gravity separation of the wash oil from the regenerated Caustic solution. The Caustic solution is withdrawn from the bottom of the settler and is recirculated back to the Extractor. The wash oil is send to the Oxidizer to extract Disulfide Oil from the rich caustic solution. An inlet distributor is provided to avoid excess inlet turbulence and promote an even flow distribution through the vessel. See Figure 2.10

Figure 2.9 Oxidizer

Oxidized Caustic

Air

Rich Caustic

Pump-out

V-2604

Figure 2.10 Wash Settler

Wash Oil to V-2604Regenerated Caustic +

Wash Oil

Rege. Caustic to the Extractor

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(7) Disulfide Separator (V-2606) The Disulfide Separator is a horizontal settler vessel with a small air disengaging stack at the inlet end. The inlet distributor enters at the midpoint of this stack. It is slotted top and bottom to aid both disengaging and distribution. The excess air flows upward into a packed area. This packing consists of 1 inch (25 mm) diameter carbon steel Raschig rings. These rings are susceptible to corrosion, especially during periods of sustained operation at high oxygen contents in the vent gas. These rings should be inspected regularly, since they provide a secondary safety function (flame arresting) as well as acting as a demister. The liquid passes downward into the main vessel or horizontal section of the separator. It encounters a second packed zone, 1200 mm in length. This zone is packed with 4 x 8 mesh anthracite coal which acts as a coalescer to aid in the separation of disulfide oil from the regenerated caustic. The coal retaining screens are 9 x 9 mesh with 0.063 inch (1.6 mm) diameter wire supported by standard deck-type grating. It is important that the annular space between these screens and the vessel wall, along with any space between screen sections, be carefully sealed with nylon rope. Otherwise coal leakage may result. Both packed zones should be loaded with the vessel full of water. The water aids in achieving a random orientation of particles and thus results in a tighter packing arrangement. This is particularly important for the coal loading to avoid later attrition resulting from abrasion if the packing is not tightly loaded, as discussed earlier with the carbon rings in the Oxidizer. Again, both packed zones should be filled as completely as possible with no void spaces.

Figure 2.11 Disulfide Separator

Spent Air to F-2002 or V-2608

Disulfide Oil to V-2607

Regenerated Caustic

to V-2605

To 26-LV-008

V-2606

P-2602 A/B

LC

Rich Caustic From Merox

Oxidizer

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(7) Disulfide Sand Filter (V-2607) The Disulfide Sand Filter is usually provided to coalesce any entrained caustic solution from the disulfide oil before being pumped to Fuel Oil Blending System. The sand bed consists of a specified depth of 8-16 mesh silica sand. The sand bed is supported by a design steel grid with two layers of 13 nylon rope. Disulfide oil enters at the top of the vessel, through a slotted distributor, passes downward through the sand bed, through the support grid, and makes a 135o turn before exiting from the side of the vessel, below the sand support grid. The disulfide oil outlet is protected by a special chordal baffle permitting the coalesced aqueous phase to run down the walls and collect at the bottom of the vessel. Care should be taken that the sand is of the same size and grading as specified so that excessive pressure drop does not develop.

(8) Catalyst Addition Pot (V-2610) The Catalyst Addition Pot is a vertical vessel normally operated batchwise to maintain the required catalyst activity level in the rich caustic stream going to the Oxidizer (V-2604). Merox WS catalyst and cold condensate enter the top of the vessel on two different nozzles. Air is injected to provide adequate mixing of the catalyst and the condensate and to introduce the condensate/catalyst mixture to the rich caustic stream by pressurizing the vessel above the operating pressure of the stream.

Figure 2.12 Disulfide Sand Filter

To Flare

To Disulfide Oil Pumps (P-2606 A/B )

OWS

LG

To / From V-2606

Disulfide Oil from V-2606 V-2607

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(9) Vent Tank (V-2608) A small vertical atmospheric vent tank is provided to separate any liquid carryover from the vent gas exiting the Disulfide Separator during start-up or period of unsteady operation. Liquid carryover is not normally expected to occur. Because of odor, the preferred disposal of vent gas is to incineration rather than to atmosphere. A packed zone is provided to coalesce any liquid and provide a safety function as a flame arrestor. The packing consists of 1 inch (25 mm) diameter carbon steel rings which are subject to the same loading and maintenance as detailed for the Disulfide Separator stack. The bottom drain is open to the sewer but sealed by means of a hydraulic overflow seal. Thus for start-up, the vent pot must initially be filled with water in order to provide a seal.

Figure 2.13 Catalyst Addition Pot

Merox WS Reagent

Air

Mixture to E-2601

Cold Condensate

V-2610

Figure 2.14 Vent Tank

Atmosphere

Vent Gas from V-2606

Sweet Fuel Gas

Flame Arrestor

F-2002 Sewer

V-2608

Trip Signal

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2.1.2.3. Reactor summary

Not applicable to this unit.

2.1.2.4. Fired heater summary


2.1.2.5. Exchanger summary

(1) Caustic Heater (E-2601) The Caustic Heater is a hair pin type heat exchanger provided to supply heat to the rich caustic solution before entering the Oxidizer (V-2604). Heat is supplied to the Caustic Heater by low pressure steam on the tube side to initiate the mercaptide oxidation reaction. This heat exchanger shall be all carbon steel. All carbon steel components in contact with caustic solution shall be stress relieved after fabrication.

2.1.2.6. Pump summary

(1) COS Solvent Circulation Pumps (P-2601 A/B) The COS Solvent Circulation Pumps are the centrifugal pumps provided for continuously circulation of MEA-NaOH solution from the COS Solvent Settler (V-2602). These pumps are constructed with carbon steel. (2) Caustic Circulation Pumps (P-2602 A/B) The Caustic Circulation Pumps are the high speed integral gear pumps provided for continuous circulation of 20o Be caustic solution from the Wash Settler (V-2605) to the Extractor (C-2602 and C-1202). These pumps are constructed with stainless steel. (3) Spent Caustic Pump (P-2603) The Spent Caustic Pump is a centrifugal type pump provided to pump-out periodically the degassed spent caustic from the Spent Caustic Degassing Drum (V-2609) to the Effluent Treatment System (U-6500) on level control. This pump is constructed with carbon steel. (4) COS Solvent Makeup Pump (P-2604) The COS Solvent Makeup Pump is a centrifugal pump provided to make up periodically MEA-NaOH solution from the COS Solvent Storage Tank (T-2601) to the COS Solvent Settler (V-2602). This pump is constructed with carbon steel.

(5) MEA Addition Pump (P-2605) The MEA Addition Pump (P-2605) is a proportioning type for periodically filling MEA to the COS Solvent Storage Tank (T-2601). This pump is constructed with carbon steel. (6) Disulfide Oil Pumps (P-2606 A/B)

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The Disulfide Oil Pumps are the proportioning type pumps provided to pump-out periodically the accumulated disulfide oil from the Disulfide Separator (V-2606) to the DHDS Unit (U-3200) on level control via the Disulfide Sand Filter (V-2607). This pump is constructed with carbon steel. (7) Water Circulation Pumps (P-2651 A/B) The Water Circulation Pumps (P-2651 A/B) are the centrifugal type pumps provided for continuous circulation of water from the RFCC LPG Coalescer (A-2651). These pumps are constructed with carbon steel.

2.1.2.7. Compressor summary


2.1.2.8. Special equipment summary

(1) Special Check Valve (A-2602)

The purpose of this piece of equipment is to prevent a backflow of caustic to the source of air, the plant air system / compressor discharge. It is installed directly on the air line just upstream of the injection point into the sour hydrocarbon stream. The features of this check valve include its low cracking requirement (0.14-0.28 kg/cm2) and positive spring loaded closing action. Although no check valve is 100% fail safe, these valves have proven themselves quite reliable over the years. The valve must be installed in a vertical position, and it is recommended to use stainless steel tubing on its inlet side in order to prevent extended pipe threads either hindering the operation of or damaging the valve internals. (2) RFCC LPG Filter (S-2651) RFCC LPG Filter is a cartridge type filter for removal of trace amounts of solids from LPG stream. (3) RFCC LPG Coalescer (A-2651) RFCC LPG Coalescer is provided to remove extraneous amine from the hydrocarbon. The LPG is mixed with wash water and then the wash water is separated from LPG phase in the Coalescer. A level of water is maintained in the vessel and used for recontacting with the incoming hydrocarbon stream. The mixture of water and hydrocarbon is passed through a mixing manual valve just upstream of the vessel to allow for intimate contacting. The water is allowed to settle in the coalescer. Then a part of water is recycled back to the inlet for further contacting and the remainder is sent to the Amine Flash Drum (V-3252).

2.1.3. Process Flow Control

The arrangement of level controls is such that flow surges in the unit, which would upset the normal caustic hold-up in the plant, will be absorbed by fluctuation or caustic level in the extractor. It is advisable to hold such a level in the extractor during normal operation so that maximum caustic surge space is available, consistent with surges in hydrocarbon flow normally encountered. The extractor is the only part of the plant that can be seriously affected by surges

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in hydrocarbon flow. There is usually no problem with surging flow on units charged with a pump. In case fluctuations in fractionator instrumental control can cause surges in the Merox unit extractor, fractionator controls should be adjusted to give smooth control. The pressure of the hydrocarbon section on the unit is set by a back pressure controller on the outlet of the sand filter. The pressure is set to prevent vaporization or cavitation which will cause caustic entrainment and to allow caustic flow to the lower pressure regeneration section. In most flow schemes, the optimum caustic-hydrocarbon ratio which produces the minimum total sulfur in the product is determined and a control valve on the lean caustic to the extractor is used to maintain the desired flow of caustic. The COS-removal efficiency is determined by the mixing intensity and the condition of the treating solution. The mixing intensity is adjusted by varying the pressure-differential setting on the mixing valve or by varying the solvent-circulation rate or both. The control of the rich caustic flow from the extractor to the oxidizer is cascaded off of the level controller on the air-liquid interface of the disulfide separator stack. This is a safety feature to ensure that the liquid hydrocarbon is not vented along with the excess air. The bottom of the extractor acts as a reservoir for the contents of the recirculating caustic. The excess air is vented from the top of the disulfide separator stack with a back pressure controller. The instrumentation of the vent gas control system is arranged such that the vent gas is sent to Steam Superheater (F-2002) during normal operation (see Figure 2.15). Fuel gas is added to keep the oxygen content below 6 vol% in vent gas. In the event of an emergency heater shutdown, a diverting switch would automatically change the flow of vent gas from Steam Superheater in RFCC Unit to the vent tank as well as stop the addition of fuel gas.

(1) Pressure Control of LPG Stream

The pressure of the hydrocarbon section on the unit is set by a back pressure controller on the

Figure 2.15 Typical Vent Gas Control Scheme

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outlet of the sand filter. The pressure is set to prevent vaporization or cavitation which will cause caustic entrainment.

(a) Pressure Control of LPG product

The operating pressure of U-2600 is controlled with the help of 26-PC-006 in split range. Split range control action of 26-PC-006 is shown below:

In case of decreasing trend of pressure in LPG stream, the control valve, 27-FV-001 closes gradually. On the other hand, in case of increasing trend of pressure, the control valve, 26-PV-006 opens gradually.

Valve Opening

27-FV-001 26-PV-006

100%

0%

LPG stream pressure Increase

13.4 barg

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2.2. Process Variables and Their Effects

Followings are the process variables for the normal operation of the RFCC LPG MEROX Unit: The purpose of this section is to discuss the major Merox process variables and their effect on performance. Specific emphasis will be placed on identifying the optimum operating conditions. Feedstock quality is covered separately at the end of this section since Merox operators generally have little control over the feedstock. The following represent the five primary process variables. Each will be discussed as an independent variable with all others held constant. C atalyst O xygen A lkalinity C ontact H eat

2.2.1. Catalyst Concentration

The extractive Merox process requires the use of UOP Merox Reagent WS. It is supplied as a dark blue water solution packaged in 3.8 liter sealed polyethylene bottles. Each bottle contains one kilogram of water-soluble active ingredient. Catalyst concentration is a direct operating variable in the extraction process. For initial make-up, or whenever fresh caustic is added to replenish the system, a catalyst concentration of approximately 200 ppm in the caustic is recommended. This roughly corresponds to 0.24 kilograms of UOP Merox Reagent WS active ingredient per 1000 liters of caustic inventory. A regular schedule of catalyst addition must be followed to maintain this catalyst activity level. As an initial recommendation, catalyst should be added at a rate of 1 kilogram per 3500 to 5200 cubic meters of hydrocarbon feed. Plant performance will indicate if this catalyst addition rate is sufficient. Usually a much lower addition rate will be adequate. Note: A formal, analytical method to determine active catalyst concentration in the Merox caustic does not exist. 2.2.2. Oxygen Injection

Oxygen is supplied to the caustic regeneration section of the Merox unit in the form of compressed atmospheric air. The stoichiometric, or theoretical, amount of oxygen necessary is 0.25 kg per kg of mercaptan sulfur. At standard conditions of temperature and pressure, one cubic meter of atmospheric air contains about 0.28 kg of oxygen. Therefore, about 0.88 standard cubic meter of air is needed for each kg of mercaptan sulfur to be oxidized. It is necessary to have at least a slight excess of oxygen present but it is always recommended to keep the excess to a minimum. The amount of excess air injection necessary is highly dependent upon the individual feedstocks, but normally ranges between 1.2 to 2.0 times the theoretical requirements. Thus, a good initial injection rate at 1.5 times theoretical may be calculated from the formula below:

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(Air) = 1.5 ( K ) ( Feed rate ) ( S.G. ) (RSH) / (10,000) Where:

Air = Air injection rate Std m3/hr K = Constant (8.81) Feed rate = Feed flow rate m3/hr S.G. = Specific gravity @15 deg C RSH = Mercaptan sulfur wt-ppm

A graph of this formula, as shown in the following figure (Fig. 2.16), is helpful in maintaining the proper air injection rate as the feed rate and mercaptan level vary.

For extraction Merox units, the air is mixed with the caustic flowing to the oxidizer. All other variables being equal, an increase in air injection results in a more rapid and complete caustic regeneration. Thus, the regenerated caustic returning to the extractor would contain a lower sodium mercaptide content and possess a greater capacity to extract mercaptan. However, increasing air injection decreases residence time in the oxidizer. Unless a large excess of air is used, this has little effect. While a low mercaptan concentration is desirable, the caustic should never be completely regenerated for the following reasons: Oxygen can dissolve in the caustic and can cause sweetening to occur in the extractor. The spent air will have a higher oxygen concentration leading to increased corrosion and

potential hazards. An increase in catalyst consumption can occur due to increased settling of the catalyst at

the oil/caustic interface in the disulfide separator. Maintaining a small amount of mercaptide in the circulating caustic ensures better catalyst dispersibility in the aqueous caustic.

400

350

300

250

200

150

100

50

12011010090 80 70 60 50 40 20 30 10 150140 130

Mercaptan Sulfur in

Feed, (Wt ppm)

(m3/hr)

Figure 2.16 Air Injection Rate

Air Injection Rate, (m3/hr)

Basis: 30 scf of Air per poundof Mercaptan Sulfur

Example: If charge rate is 32m3/hr and Mercaptan sulfur is 300 wtppm then the air injection rate should be 102.5 m3/hr.

24 22 2018 16 14 12 10 8 4 6 2 30 28 26 32 34 36384042

44 464850

7065

52 54 58

5660

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2.2.3. Alkalinity

Alkalinity is provided by aqueous sodium hydroxide, or caustic solution. In both of the liquid-liquid versions of the Merox process (extraction and sweetening), caustic is the solvent provided for mercaptan extraction and also the medium in which catalyst is dispersed. In addition, it provides the alkaline environment necessary for the mercaptan oxidation reaction to proceed in all versions of the Merox process. For mercaptan extraction processing LPG hydrocarbon, 20o Baume (14.4 wt% or 4.25 g-mol/liter) caustic appears to be the optimum concentration for dissolution of the particular mercaptans present. For low molecular weight mercaptan molecules (methyl and ethyl mercaptan), increasing caustic strength increases extraction. As higher molecular weight mercaptan molecules are encountered, increasing caustic strength decreases extraction as shown in Figure 2.17. An upper limit of 30o Baume (23.5 wt%) is the maximum practical concentration. Above this strength, competition from the hydroxide ions already in solution hinders any increase in mercaptan solubility. Also, at these strengths emulsification problems begin to occur.

2.2.4. Contact

Contact may be defined as the intimacy of mixing of the reactants. Contact is accomplished by one of several means. Contact can be characterized by duration of mixing time, by volumetric ratio of reactants, or by differential pressure which implies degree of dispersion. With a fixed flow restriction, the differential pressure is directly related to the linear velocity so that velocity is often taken to be the process variable. For extraction units, hydrocarbon tray hole velocity is one of the variables with which contact is characterized. The optimum hole velocity (Figure 2.18) is designed for each unit based upon the intended design throughput. As hole velocity decreases, extraction efficiency decreases. This fact should be kept in mind when operation is attempted at feed rates that are significantly less than the design rate.

C1SH

C2SH

C3SH

C4SH

C5SH

0

Caustic Concentration ( G-mol / liter )

KQ = [RS ]Aq . [RSH] Oil

(Logarithmic Scale )

Figure 2.17 Equilibrium Distribution

4 12 10862

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The other important contact variable for extraction is the volume of caustic circulated relative to the volume of hydrocarbon throughput. This is referred to as the caustic to hydrocarbon ratio (C/H). As this ratio is increased, contact is increased and the extraction potential is increased. Increased extraction occurs as a result of a favorable shift in the complex equilibrium conditions discussed earlier. In order to increase the C/H ratio at constant hydrocarbon feed rate, the caustic circulation rate must be increased. Any entrained disulfide oil remaining in the regenerated caustic, as it enters at the top of the extractor, is essentially completely extracted by the exiting hydrocarbon stream. Sulfur in the Merox product as a result of this effect is referred to as re-entry sulfur (Figure 2.19). At a constant feed rate, re-entry sulfur increases in the treated hydrocarbon in direct proportion to the caustic circulation rate increase. The re-entry sulfur in the product may be calculated as follows:

Where:

Sr = Re-entry Sulfur in the Product ( wt-ppm )

Sc = Disulfide Sulfur in the Regenerated Caustic ( wt-ppm )

C = Caustic Volumetric Flow Rate

H = Hydrocarbon Volumetric Flow Rate

Gc = Specific gravity of the Regenerated Caustic

Gh = Specific gravity of the Hydrocarbon

With: C & H expressed in the Same Volume Units.

Re-entry Sulfur

Sr = Sc (C/H ) ( Gc/Gh )

Hole Velocity

Theoretical Equilibrium

Design

Figure 2.18 UOP Merox Extraction Tray

Overall Efficiency

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Since increasing the caustic to hydrocarbon ratio increases re-entry sulfur proportionally and decreases mercaptan sulfur exponentially, there exists a single optimum ratio where total mercaptan sulfur plus re-entry sulfur is minimized, typically in the 1-3 % range (Figure 2.20). Above this optimum C/H ratio, increased re-entry sulfur can be excessive; below this optimum C/H ratio, mercaptan sulfur extraction may be inadequate.

Figure 2.19 Re-Entry Sulfur

Figure 2.20 Optimum Caustic

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2.2.5. Heat (Temperature)

Mercaptan extraction is favored by lower temperature. The lowest practical hydrocarbon feed temperature for extraction is about 20 oC. Below this temperature, caustic entrainment, or caustic haze, may become a problem. Above 50 oC mercaptan extraction will be poor. Liquid-liquid extraction Merox units are usually designed for optimum operation at 38 oC. The Merox caustic regeneration reaction is favored by higher temperature. Thus, in Merox extraction units a small heater or exchanger is provided to heat the rich caustic before it enters the oxidizer. Although the oxidizer temperature should always be kept as low as possible, the optimum caustic temperature at the oxidizer will normally be 38-43 oC. Occasionally it may be necessary to increase the oxidizer temperature to 50 oC. However, the oxidizer temperature should always be run at as low a temperature as possible while still maintaining the desired degree of mercaptan regeneration. This will avoid over-oxidation reactions, which can lead to acid generation and cause caustic neutralization. In any event, 60 oC would be considered an absolute maximum temperature because of metallurgical considerations (i.e. stress corrosion cracking which is commonly called caustic embrittlement).

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3. EMERGENCY EQUIPMENT 3.1. Safety Valves and Their Set Pressure

3.1.1. Summary of Safety Relief Valves

Summary of the safety valves provided for this unit is shown below. Refer to FLARE LOAD SUMMARY FOR UNIT 2600 (S-260-1223-701).

Tag. No.

Set Pressure

barg

Size and

Type Service Location

Governing

Relief Case

26RV001A/B 25 3K4 C-2651 Outlet Fire

26RV002A/B 25 3K4 V-2601 Outlet Fire

26RV003A/B 25 3J4 C-2602 Outlet Fire

26RV004A/B 25 4L6 V-2602 Outlet Fire

26RV005A/B 25 3K4 V-2603 Outlet Fire

26RV006 8.8 1D2 V-2610 Outlet Fire

26RV007A/B 32.5 1.5G3 V-2605 Outlet Fire

26RV008A/B 6.9 1.5H3 V-2607 Outlet Fire

26RV009A/B 6.9 4N6 V-2606 Outlet Fire

26RV010A/B 6.9 1D2 26-FV-003A/B Outlet C/V Failure

26RV011A/B 24 1.5F2 A-2651 Outlet Fire

26RV012A/B 25 1.5F2 26-FV-001 Outlet Blocked Outlet

3.1.2. Summary of Flare Loads

Refer to Flare Load Summary(S-260-1223-701). 3.2. Car Sealed Valves

Car Sealed Open or Car Sealed Close valves are listed below.

Position Service Size Equipment / Line No.

P&ID No.

Open 26RV001A (or B) Outlet line 6 FL26010201-6- A1A1-N

D-260-1225-102

Open 26RV001A (or B) inlet line 6 P26010202-6- A2A1P-N

D-260-1225-102

Open 26RV012A (or B) Outlet line 3 AMD26010201-3- A1A1-N

D-260-1225-102

Open 26RV012A (or B) inlet line 3 AM26010205-3- A2A1P-N

D-260-1225-102

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D-260-1225-103


D-260-1225-103


D-260-1225-104


D-260-1225-104


D-260-1225-104


D-260-1225-104


D-260-1225-105


D-260-1225-105


D-260-1225-106


D-260-1225-106

Open Flare Line from V-2609 3 NA26010703-3- A1A1P-N

D-260-1225-107

Open 26RV010A (or B) inlet line 4 A26010801-1.5- A2A1-N

D-260-1225-108


D-260-1225-109


D-260-1225-109


D-260-1225-110


D-260-1225-110

Close V-2607 Pump Out Line 1 P26011004-1- A1A1-N

D-260-1225-110

Open Balance line between V-2606

and V-2607

3 P26011002-3- A1A1P-N

D-260-1225-111


D-260-1225-111


D-260-1225-111

3.3. Remote Operating Valves No remote operating valves. 3.4. Instrument Alarms

Refer to Attachment 3.1 DCS & ESD Function List. 3.5. Instrument Trip Settings

Trip settings causing plant shut down are listed below. Refer to CAUSE AND EFFECT CHART _

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(S-260-1223-602) on the Attachment 9.12, for details.

Tag No. Service Trip Set P&ID No.

26-ASHH-001 V-2606 Vent Gas High Oxygen

Shutdown

26-UC-001 D-260-1225-111

20-PSLL-054 Shutdown Signal from F-2002

(from 20-UC-002)

26-UC-002 D-200-1225-139

26-LSHH-007 Disulfide Separator Stack 26-UC-002 D-260-1225-111

26-LSLL-009 Amine Absorber Interface Low Level

Shutoff

26-UC-005 D-260-1225-102

26-LSLL-010 Extractor Interface Low Level

Shutoff

26-UC-006 D-260-1225-104

26-LSLL-012 RFCC LPG Coalescer Low Level

Shutoff

26-UC-007 D-260-1225-103

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4. PREPARING UNIT FOR PRE-COMMISSIONING

The following section discusses the various aspects associated with the pre-commissioning of the facilities in the refinery. The pre-commissioning operations ensure that the unit is safe, operable, and constructed as specified. Each start-up preparation operations shall be performed in unit by unit. In addition to the procedures, the operator of one area (or unit) shall coordinate with the operator of the other area (or unit) to perform the pre-commissioning operation. A systematic program of start-up preparations must be drawn up and carried out to ensure that the start-up operation proceeds properly. This is particularly important when the unit has to be brought on-stream together with other units within a limited time.

4.1. General Preparation for Pre-commissioning As the construction of the unit nears completion, a large amount of work must begin in order to prepare it for start-up. These pre-commissioning activities have three main purposes: To ensure, by thorough inspection and testing, that the unit is safe, operable, and

constructed as specified; To operate equipment for by flushing, running in, etc., and To acquaint the operators with the unit.

The importance of these activities cannot be overemphasized. No matter how well a unit is designed, if the equipment is not as specified, not properly brought on stream, or not understood by operators, it will not perform as expected. The following activities are major Pre-commissioning activities. However, an exact order of presentation need not be strictly obeyed. Depending on the progress of construction, certain procedures may be required earlier or later that suggested here. A through knowledge of the entire pre-commissioning operation will allow the plant personnel to schedule activities in the most time-saving and labor efficient way. These are the necessary pre-commissioning activities:

1. Vessel and other Major Equipment Inspection 2. Line Cleaning 3. Servicing and Calibration of Instruments 4. Run-in of Rotary machineries 5. Chemical Cleaning 6. Refractory Drying 7. System Drying 8. Loading of Chemicals, Catalysts, and Other Materials 9. Operational Tightness Test 10. Air Freeing 11. Commissioning of Additional Plant Services

4.2. Vessel Inspection

The actual installations must be compared against the drawings and cleanliness check inside vessels to assure that the vessels will function as intended.

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4.3. Line Cleaning

All piping must be thoroughly clean of debris and scale. This may be done after hydrostatic testing, before the test water is drained. Care must be taken not to flush debris into equipment. Generally, liquid lines are flushed with water and thoroughly drained. Water flushed lines which do not drain freely should be blown clear with air. Gas lines may be either water flushed or air blown, but water should be blown from gas lines if water flushed. Gas lines to compressors must be free of water. Steam lines are steam blown using same steam it is designed for. Before steam blow, all steam traps, control valves, turbines, heaters, instruments, ejector and strainers should be removed or blanketed off from the system. Steam headers should be slowly warmed up one by one observing expansion of line. Special attention should be given to pipe support shoes. Condensate must be drained manually as it forms, thereby preventing steam hammering. Refer to S-000-172A-300 GENERAL PRECOMMISSIONING PROCEDURE FOR STEAM BLOWING for details.

4.4. Service and Calibrate Instruments Responsible instrument engineers at site shall check to ensure that the instrumentation is provided as specified by the design documents, thereby preventing or minimizing instrumentation problems when the unit is commissioned.

4.5. Run-in of Rotary Machineries

Proper installation and operation of rotary machineries is essential for trouble-free performance. Therefore, the rotary machineries shall be run-in during pre-commissioning with inert fluid, if it is practical. In case there is no practical method of run-in during pre-commissioning due to test fluid, circulation route, etc., the machineries shall be run-in at initial stage of start up with actual fluid. Details of run-in operation are described by the following documents:

- S-000-172B-100 : GENERAL PRECOMMISSIONING PROCEDURE FOR MECHANICAL RUN-IN OF PUMPS

- S-000-172B-200 : GENERAL PRECOMMISSIONING PROCEDURE FOR MECHANICAL RUN-IN OF C

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