AMINE OM Part-1 Rev.3

JOB No.DOC. No.REV.0-0800S-810-1230-001 3DATE 29-OCT- 1998 SHEET 1 OF 125 PREP’DT.TakedaCHK’DN.A.APP’DT. KimuraINDEXREV.DATEPAGEDESCRIPTIONPREP’DCHK’DAPP’D029-OCT-98AllFOR REVIEWT. TakedaN.A.T. Kimura316-APR-99As markedISSUED FOR CONSTRUCTION(REVIEWED WITH X-JY/PY-4279 AND UPDATED)T. TakedaN.A.T. Kimura

Project Specification

OPERATING MANUAL FOR Unit : 810 AMINE TREATING PROCESS UNIT

DI S T RI B U TI O N P A R C O K P OI P M TB K W P A R C O SI TE P M T PC O N T C O N S TE N G P R O C E S S 1 PI PI N G 1 CI VI LI N S TE L E C R O T A R Y FI R E A C O U S TI C E Q UI P P AI N T/ IN S U P K G( P K) P K G( S H) C O M B B L D G/ H V A C O P E R TLA A B O L E G A L P P M P U R C H 11 P U R C H 12 P U R C H 13 P U R C H

PAK-ARAB REFINERY LIMITED MID-COUNTRY REFINERY PROJECT MAHMOOD KOT, PAKISTAN

0

H 22E P U R C H 22IE X P E D ႒ G S HI P PI N G Q A Q C J P C M

AR UB EN I

SI TE TI C J U S J E U

Since the Amine Treating Process Unit consists of Amine Treating Section and Sour water Stripping Section which are quite different processes from each other, this operating manual is divided into two PARTs as below: PART Ⅰ AMINE TREATING SECTION

from page 3

PARTⅡ SOUR WATER STRIPPER SECTION

from page 84

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OPERATING MANUAL OF AMINE TREATING UNIT 001

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PART Ⅰ AMINE TREATING SECTION CONTENTS PAGE 1. GENERAL DESCRIPTION....................................................................................................... 1.1. PLANT DUTY.................................................................................................................... 1.2. DISCUSSION OF PROCESS.................................................................................................. 1.3. DESIGN BASIS FOR FEED AND PRODUCTS........................................................................... 1.3.1. Feeds............................................................................................................................. 1.3.2. Products........................................................................................................................ 1.3.3. Design Considerations................................................................................................... 1.4. MATERIAL BALANCE / B.L. CONDITIONS........................................................................... 1.4.1. Material balance............................................................................................................ 1.4.2. B.L. conditions.............................................................................................................. 1.5. UTILITY AND CHEMICALS REQUIREMENTS......................................................................... 1.5.1. Utility requirements....................................................................................................... 1.5.2. Chemical requirements.................................................................................................. 2. OPERATING CONDITIONS AND CONTROLS..................................................................... 2.1. DISCUSSION OF PROCESS VARIABLES................................................................................. 2.1.1. Absorption..................................................................................................................... 2.1.2. Regeneration................................................................................................................. 2.2. PROCESS FLOW AND CONTROL......................................................................................... 2.2.1. Description of process flow........................................................................................... 2.2.2. Control Flow Plan......................................................................................................... 3. EMERGENCY EQUIPMENT................................................................................................... 3.1. SAFETY VALVES................................................................................................................ 3.1.1. Summary of Safety Valves............................................................................................. 3.1.2. Summary of Flare Loads............................................................................................... 3.2. CAR SEALED VALVES........................................................................................................ 3.3. REMOTE OPERATING VALVES............................................................................................. 3.4. INSTRUMENT ALARMS...................................................................................................... 3.5. INSTRUMENT TRIP SETTINGS............................................................................................. 3.6. PROCEDURES FOR SETTING PROTECTIVE RELAYS.............................................................. 4. PREPARING UNIT FOR PRE-COMMISSIONING................................................................. 4.1. PRE-COMMISSIONING........................................................................................................ 4.2. COMMISSIONING OF UTILITIES.......................................................................................... 4.3. PRESSURE TESTING.......................................................................................................... 4.4. FLUSHING OUT................................................................................................................. 4.5. ACID CLEANING OF RECIPROCATING COMPRESSOR LINES.................................................. 4.6. INSPECTION AND RUN-IN OF PUMPS AND FANS................................................................. 4.7. LEAK TEST....................................................................................................................... 4.8. INSPECTION AND RUN-IN OF RECIPROCATING COMPRESSOR.............................................. 4.9. INSPECTION AND RUN-IN OF CENTRIFUGAL COMPRESSOR................................................. 4.10. LOADING INTERNAL MATERIAL REQUIRED FOR ABSORBERS, VESSELS, PACKED COLUMNS. 4.11. DRYING OUT FIRED HEATER...........................................................................................

4.12. DRYING OUT REACTOR SECTION..................................................................................... 4.13. PREPARING REACTORS.................................................................................................... 4.14. LOADING CATALYST....................................................................................................... 4.15. DEGREASING FOR AMINE CIRCULATING SYSTEM............................................................. 4.16. PURGING AND GAS BLANKETING..................................................................................... 4.17. PRE-COMMISSIONING CHECK LIST................................................................................... 5. COMMISSIONING................................................................................................................... 5.1. GENERAL OVERALL COMMISSIONING PLAN....................................................................... 5.2. DETAILED STEP-BY -STEP START-UP PROCEDURE................................................................ 5.3. SPECIAL PRECAUTIONS..................................................................................................... 5.3.1. Precaution for entering a contaminated or inert atmosphere........................................... 5.3.2. Draining Amine Solution............................................................................................... 6. NORMAL START-UP & SHUTDOWN.................................................................................... 6.1. NORMAL START-UP AFTER PROLONGED SHUTDOWN.......................................................... 6.2. NORMAL OPERATION PROCEDURE AFTER SHORT SHUTDOWN............................................. 6.3. NORMAL OPERATION........................................................................................................ 6.3.1. Product quality monitoring............................................................................................ 6.3.2. Operation Conditions Monitoring.................................................................................. 6.4. ROUTINE OPERATION........................................................................................................ 6.4.1. Trouble shooting............................................................................................................ 6.4.2. Miscellaneous procedures.............................................................................................. 6.4.3. Routine control tests to be performed by operators........................................................ 6.5. GENERAL OVERALL SHUTDOWN PLAN.............................................................................. 6.6. DETAILED STEP-BY -STEP SHUTDOWN PROCEDURE............................................................ 6.7. BLANKING OFF................................................................................................................. 6.8. OPENING EQUIPMENT....................................................................................................... 6.9. SPECIAL PRECAUTIONS..................................................................................................... 7. EMERGENCY SHUTDOWN.................................................................................................... 7.1. GENERAL INSTRUCTIONS.................................................................................................. 7.2. FIRE................................................................................................................................. 7.3. POWER FAILURE............................................................................................................... 7.4. INSTRUMENT AIR FAILURE................................................................................................ 7.5. LP STEAM FAILURE.......................................................................................................... 7.6. WATER FAILURE............................................................................................................... 7.6.1. Cold Condensate failure................................................................................................ 7.6.2. Cooling Water failure.................................................................................................... 7.7. FEEDSTOCK FAILURE........................................................................................................ 7.8. EQUIPMENT FAILURE........................................................................................................ 8. MAJOR EQUIPMENT & ITS SERVICE.................................................................................. 8.1. SUMMARY TABLES............................................................................................................ 8.2. TOWER SUMMARY............................................................................................................ 8.2.1. Fuel Gas Amine Absorber ( 810-V2 )............................................................................ 8.2.2. Amine Regenerator ( 810-V5 )....................................................................................... 8.3. DRUM SUMMARY............................................................................................................. 8.3.1. Fuel Gas Amine Absorber Knockout Drum ( 810-V1 ).................................................. 8.3.2. Rich Amine Flash Drum ( 810-V4 ).............................................................................. 8.3.3. Amine Regenerator Receiver ( 810-V6 )........................................................................ 8.3.4. Lean Amine Carbon Filter ( 810-V7 )............................................................................ 8.3.5. Amine Sump Tank ( 810-V8 )........................................................................................

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8.3.6. Fuel Gas Amine Absorber Interface Pot ( 810-V9 )....................................................... 8.4. REACTOR SUMMARY......................................................................................................... 8.5. FIRED HEATER SUMMARY................................................................................................. 8.6. EXCHANGER SUMMARY.................................................................................................... 8.6.1. Amine Regenerator Reboilers ( 810-E2A/B )................................................................. 8.6.2. Rich/Lean Amine Exchanger ( 810-E3 )........................................................................ 8.6.3. Lean Amine Trim Cooler ( 810-E9 ).............................................................................. 8.6.4. Amine Regenerator Condenser ( 810-EA1 )................................................................... 8.6.5. Lean Amine Cooler ( 810-EA2 ).................................................................................... 8.7. PUMP SUMMARY.............................................................................................................. 8.7.1. Rich Amine Flash Drum Slop Oil Pumps ( 810-P1A/B )............................................... 8.7.2. Rich Amine Pumps ( 810-P2A/B )................................................................................. 8.7.3. Lean Amine Pumps ( 810-P3A/B )................................................................................ 8.7.4. Amine Sump Pumps ( 810-P5A/B )............................................................................... 8.7.5. Amine Transfer Pumps ( 810-P6A/B )........................................................................... 8.8. COMPRESSOR SUMMARY.................................................................................................. 8.9. SPECIAL EQUIPMENT SUMMARY........................................................................................ 8.10. LIST OF INSRUMENTS..................................................................................................... 8.11. SUMMARY OF ALL EQUIPMENT ’S DRIVERS....................................................................... 8.12. CONTROL VALVES........................................................................................................... 8.13. FIRED HEATERS.............................................................................................................. 8.14. MISCELLANEOUS............................................................................................................ 9. FLOW PLANS AND PLOT PLAN............................................................................................ 9.1. PFD, MSD AND P&IDS................................................................................................... 9.2. DESIGN ENGINEERING, UTILITY AND SAFETY FLOW PLANS................................................ 9.3. PLOT PLAN...................................................................................................................... 9.4. SAFETY SHUTDOWN FUNCTION CHARTS............................................................................ 10. SAFETY................................................................................................................................... 10.1. EMERGENCY FIRE PLAN.................................................................................................. 10.2. FIRE FIGHTING AND PROTECTIVE EQUIPMENT.................................................................. 10.3. FIRE PROTECTION.......................................................................................................... 10.4. MAINTENANCE OF EQUIPMENT AND HOUSEKEEPING....................................................... 10.5. REPAIR WORK................................................................................................................. 10.6. THERMAL EXPANSION IN EXCHANGERS........................................................................... 10.7. WITHDRAWAL OF SAMPLES.............................................................................................. 10.8. SAFE HANDLING OF VOLATILE AND TOXIC MATERIALS INCLUDING CATALYST.................... 10.8.1. Respiratory Protection................................................................................................. 10.8.2. Breathing Apparatus ( B. A. )...................................................................................... 10.8.3. Poisonous Material...................................................................................................... 10.9. PREPARING FOR ENTERING PROCESS EQUIPMENT............................................................. 10.10. OPENING EQUIPMENT................................................................................................... 10.11. WORKING IN COLUMNS OR VESSELS.............................................................................. 10.12. ENTERING TANKS, DRUMS OR OTHER VESSELS.............................................................. 10.13. PROCEDURE FOR REMOVING SAFETY VALVES................................................................ 10.14. WORK PERMIT PROCEDURE AND WORK PERMIT FORMATS............................................. 10.15. OPERATION NOTES RELATING TO HAZOP REVIEW......................................................... 10.16. MATERIAL SAFETY DATA SHEET (MSDS) OF ALL THE CHEMICALS, CATALYSTS................ 11. MISCELLANEOUS................................................................................................................. 11.1. CONVERSION TABLES...................................................................................................... 11.2. GENERAL PRE-START UP PROCEDURES............................................................................

11.3. OVERALL START-UP AND SHUTDOWN OUTLINES.............................................................. 11.4. OFFSITE SYSTEMS........................................................................................................... 11.5. CATALYST AND CHEMICAL LOADING / UNLOADING........................................................... 11.6. CATALYST AND CHEMICALS REQUIREMENTS.................................................................... 11.7. ANALYTICAL PLAN..........................................................................................................

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General Description This manual covers the operation of the Amine Treating Process Unit of PARCO MIDCOUNTRY REFINERY PROJECT for PAK-ARAB REFINERY LIMITED (PARCO) in Pakistan. Plant duty The Amine Treating Process Unit shall consist of an Amine Absorber Section to treat fuel gas, an Amine Regeneration Section, and a Sour Water Stripper Section ( See Part II - Sour Water Stripper Section ).. The Amine Treating Process Unit will be designed to remove H2S from off gases derived from various process units in the Refinery. Treated gas from the Fuel Gas Amine Absorber shall not exceed 100 mol ppm H2S. The Amine Treating Process Unit will be designed to regenerate rich amine from various process units, and to provide lean amine back to those units. Acid gas from the regeneration section will be routed to the Sulfur Recovery Process Unit (hereinafter called SRU). Discussion of process Amine solution of 20 wt % DEA (di-ethanol amine) employed for acid gas removal. For simplicity, only the chemistry involved in H2S removal will be discussed. It should be realized, however, that other acid gases ( such as CO2 ) will also undergo similar reactions. Hydrogen sulfide, H2S or HSH, is a weak acid and ionizes in water to form hydrogen ions and sulfide ions: H2S  H+ + HSSince it is a fairly weak acid, only a fraction of the H2S will ionize. Similar ionization reversible will occur for the other acidic compounds present, for example CO 2: CO2 + H2O  H+ + HCO3Ethanol amines are weak bases and ionize in water to form amine ions and hydroxyl reversible ions: (HOCH2CH2)2NH + H2O  (HOCH2CH2)2NH2+ + OHWhen H2S dissolves into the solution containing the amine ions, it will react to form a weakly bonded salt of the acid and the base. (HOCH2CH2)2NH2+ + HS (HOCH2CH2)2NH2SH The disulfide ion is thus absorbed by the amine solution. This salt formation reaction does not go to completion. As the arrows indicate, an equilibrium level of hydrogen sulfide remains in the hydrocarbon stream. The overall reaction can be summarized by the following equations: (HOCH2CH2)2NH + H2S  (HOCH2CH2)2NH2SH Operating variables are adjustable to favor the forward reaction of the equation above in the absorption step of the process and, conversely, adjusted to favor the reverse reaction in the amine regeneration step of the process. It is the reversibility of this reaction that permits solvent regeneration and continuous removal of H2S by amine treating. Design basis for feed and products Feeds

The Fuel Gas Amine Absorber ( 810-V2 ) in the Amine Treating Process Unit shall be designed to process off gases from the following: Absorber at the Gas Concentration Process Unit Additional gas streams, if any, to be determined during the process design Stripper Off Gas from a future Distillate Hydrotreating Process Unit. The Amine Treating Process Unit shall be designed to provide lean amine to, and to regenerate rich amine from, the following: Amine Absorber at the LPG Merox Process Unit Recycle Gas Scrubber at the DieselMax Process Unit Fuel Gas Amine Absorber at the Amine Treating Process Unit Products Off gas from the Fuel Gas Amine Absorber ( 810-V2 ) shall be sent to the refinery fuel gas system. The design H2S level in the treated fuel gas shall not exceed 100 mol ppm. Acid gases from the Amine regenerator shall be routed to the Sulfur Recovery Process Unit ( SRU ). Design Considerations 1. 2. 3. 4. 5. 6.

Rich amine will be loaded to no more than 0.33 mol H2S/mol DEA. Lean amine will be regenerated to 0.03 mol H2S/mol DEA. The Fuel Gas Amine Absorber ( 810-V2 ) will be designed to produce a treated gas having no more than 100 mol ppm H2S. wt% DEA will be used in the Amine Treating Process Unit. An acid gas flare will be provided as a means to dispose of H2S rich gas when the Sulfur Recovery Process Unit is shut down. Mechanical and carbon filtration will be included on the lean amine stream leaving the Amine Treating Process Unit. An allowance for future Distillate hydrotreating Process Unit will be provided in the design of the Fuel Gas Amine Absorber. This allowance will be 0.85 MMSCFD and be of the same composition as the gas from the Gas Concentration Process Unit.

Material balance / B.L. conditions Material balance Stream Number* Stream Name ( FEED ) DEA NH3 H2S H2 H2O CH4 C2H6 C3H8 C4H10 C5H12

1

2

38

42

Off gas from GASCON

Future Use

Rich Amine from L-MRX 1.531 0.505 35.634 0.00004 0.004 0.003 0.00002

Rich Amine from DieselMax

24.98 80.98 1.74 148.76 99.49 5.76 0.76 0.20

6.3 20.51 0.44 37.68 25.2 1.46 0.19 0.05

276.761 0.045 91.372 5.450 6455.59 0.400 0.433 0.077 0.033 0.008

8

JOB CODE 0-0800 JGC DOC. NO. S-810-1230-

OPERATING MANUAL OF AMINE TREATING UNIT 001

SHEET 9 C6+ C2H4 C3H6 C4H8 C2H6S

0.01 0.84 0.35 0.01

0.00 0.21 0.09 0.02 -

0.0002 0.00005 0.0003

0.004 -

92.16 1,715 18.61

37.68 821 21.78

6830.17 148,569 21.75

-

-

0.81

144

8,618

2,183

1,031 -

1,032 137

0.786

0.786

-

0.28

-

Mole Flow, Kmol/hr Weight Flow, kg/hr Mole weight, kg/kg mole Liq Vol Flow, Std m3/hr Liq Density, kg/m3 Vap Vol Flow, m3/hr ( Norm ) Vap Density, kg/m3 ( Norm )

OF 126

363.80 6,773 18.62

Stream Number*

12

99

97

111

Stream Name ( PRODUCT )

Lean Amine to L-MRX

Lean Amine to DieselMax

Gas to SRU

DEA NH3 H2S H2 H2O CH4 C2H6 C3H8 C4H10 C5H12 C6+ C2H4 C3H6 C4H8 C2H6S

Treated Gas to Fuel Gas System 0.0003 0.012 101.413 8.615 186.275 124.572 7.215 0.948 0.250 0.012 1.047 0.439 0.012 -

1.544 0.002 0.033 0.000 36.037 -

276.75 0.03 5.73 6458.57 -

0.003 0.0007 117.07 0.09 10.66 0.01 0.01 0.002 0.003 0.0006 0.0003 0.0003 0.0001 0.00002 0.0003

Mole Flow, Kmol/hr Weight Flow, kg/hr Mole weight, kg/kg mole Liq Vol Flow, Std m3/hr Liq Density, kg/m3 Vap Vol Flow, m3/hr ( Norm ) Vap Density, kg/m3 ( Norm )

430.81 7,535 17.49 10,206 0.738

37.61 813 21.6 0.81 1,024 -

6,741.08 145,665 21.6 142.3 1,024 -

127.85 4,183 32.7 3,029 1.381

* Refer to the Process Flow Diagram( Attachment 9.1) for details.

B.L. conditions Fluid 1) Incomings Off Gas Rich Amine Sour Water 2) Outcomings Lean Amine Sour Gas

Origin / Destination

Available Pressure ( kg/cm2G )

Temperature ( oC )

Gas Concentration Unit LPG Merox Unit DieselMax Unit SRU

9.51 9.16 9.86 -

42 38 54 60

LPG Merox Unit DieselMax Unit SRU

13.73 1.05

61 61 61

Utility and chemicals requirements Utility requirements Refer to Attachment 1.1 ( Utility Summary, Doc. No. S-810-1223-501 ) Chemical requirements Refer to Attachment 1.2 ( Catalyst and Chemical Summary, Doc. No. S-810-1223-502) for details.

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Operating Conditions and Controls Discussion of process variables Absorption The absorption of H2S into the amine solution is favored by: 1. Low temperature 2. Low acid gas loading 3. High amine concentration 4. High H2S partial pressure in the feed stream 5. Intimate contact In general practice, items 4 and 5 are not operating variables, by itself, having been fixed by the design criteria for the unit and choice of equipment in the absorber design. Be aware, however, that low feed rates cause poorer tray efficiency and thus somewhat poorer H2S removal than will be possible at or near design flow rates. Low Temperature The lower the temperature of the lean amine solution, the better the H2S removal. When treating a hydrocarbon gas, however, the lean amine temperature is limited by the temperature of the gas being treated. The lean amine temperature must be maintained 3 o C higher than the temperature of the gas feed stream to avoid any possible condensation of these hydrocarbon vapors. The lean amine is usually cooled to between 27-49 oC. Acid Gas Loading Good acid gas loading removal efficiency depends on good amine solution regeneration, as will be discussed later. However, it also depends on restricting the H2S loading in the rich amine to favor the forward direction of the reaction given below. (HOCH2CH2)2NH +

H2S



(HOCH2CH2)2NH2SH

The H2S loading of the amine solution is controlled by adjustment of the amine circulation rate. In most cases, unless special design considerations have been employed, the rich amine acid gas loading ( H2S plus CO2 ) should not exceed 0.3 to 0.4 mols total acid gas per mol of amine present. High Amine Concentration The concentration of uncombined amine is favored by high amine solution, good regeneration, and freedom from strong acids. Practical and economical considerations confirmed by field experience have generally shown that the optimum amine concentration is 20 wt% for DEA. This is based on the lowest heat requirement for the desired H2S removal, the lowest chemical losses, and the fewest operational problems. The available amine concentration in the lean amine is mainly affected by the efficiency and control of amine regeneration. The lower the sulfide content of the lean amine, the greater the available amine concentration for removal of H2S. In most cases, properly regenerated lean amine will not contain more than 0.03 mol H2S per mol amine nor more than 0.1 mol CO2 per mol amine. Regeneration The regeneration of the amine solution, actually the breakdown of the weakly bonded amine-hydrosulfide salt, is favored by : 1. High Temperature

2. Low pressure 3. High stripping steam rate 4. Low amine concentration 5. Intimate contacting These conditions are controlled in the amine stripping column, subject to the following limitations. Item 5 is not an operating variable and is fixed during plant design. High Temperature The breakdown of the amine-hydrosulfide salt into H2S and amine, the reverse reaction of the equation below, is promoted by higher temperatures. (HOCH2CH2)2NH +

H2S



(HOCH2CH2)2NH2SH

However, the ethanol amines can be thermally decomposed at temperatures beginning at about 125 oC and becoming excessive at 150 oC. MEA is thermally more stable than DEA and can withstand somewhat higher temperatures. The decomposition temperature need not be approached to provide adequate regeneration of ethanol amine solutions. The stripper reboiler outlet temperature is generally less than 125 oC . This temperature is subject to variation with column operating pressure, amine concentration, and acid gas loadings. It should be noted that amine solutions are mostly water. Therefore, temperature changes with composition are small and it is the operating pressure of the stripper that determines the temperature of operation. Low Pressure The stripping column is operated at the lowest overhead receiver pressure possible consistent with downstream acid gas processing requirements. Generally, 0.35 to 1.0 kg/cm2G at the base of the stripper is sufficient pressure to feed the acid gas to the SRU. As noted above, the lower the pressure, the lower the stripper temperature. High Stripping Steam Rate The liberation of the H2S from its amine salt by temperature is assisted by the generation of steam in the stripper reboiler. The steam dilutes and carries away H2S vapor as it is dissociated from the amine. The resulting decrease in H2S concentration in the vapor allows for further amine-hydrosulfide dissociation. Normal stripper operations require a heat input at the stripper reboiler of 120 to 140 kg of reboiler steam pre cubic meter of amine solution circulated. This reboiler steam rate will result in a reflux rate of approximately 3 to 5 LV-% of the circulating amine rate. Low Amine Concentration Higher amine concentrations favor the retention of acid gas in the solution. Thus, the amine concentration is chosen to be high enough for efficient absorption but low enough for efficient regeneration. Unless special considerations are provided for during design, most unit will operate most efficiently at between 15 to 20 wt-% amine concentration. In most units, more water is lost with the acid gas than is introduced with the absorber feedstocks. Thus, a live steam injection point is usually provided directly into the reboiler outlet line to enable the addition of water to avoid amine concentration increases. In some units, more water is brought into the unit than is lost with the acid gas. A slip stream of reflux liquid can be drawn off the reflux pump and sent to the sour water stripper to eliminate the excess water build-up that could otherwise cause excessive dilution of the amine solution inventory.

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Process flow and control Description of process flow Sour fuel gas is fed to the Amine Treating Section from the Gas Concentration Unit. The system is designed to handle an extra 25 vol% of its capacity for future use. The sour gas enters the Fuel Gas Amine Absorber Knockout Drum ( 810-V1 ) where any liquid hydrocarbon is separated from the gas stream. Liquid which accumulates in the drum is periodically drained to the Acid Gas Flare Header. The gas stream is sent to the Fuel Gas Amine Absorber ( 810-V2 ) where it is scrubbed with amine to remove H2S. The treated gas flows through a back pressure control valve and is then sent to the refinery fuel gas system. Lean DEA enters the top of the Absorber on flow control. Rich amine solution leaves the bottom of the Absorber on level control and flows to the rich amine header system. Also at the Fuel Gas Amine Absorber, an Interface Pot ( 810-V9) is provided for hydrocarbon skimming and amine drainage to the Amine Sump Tank ( 810-V8 ). The rich amine header system collects rich amine from the Fuel Gas Amine Absorber located in the Amine Treating Unit, the Amine Absorber located in the LPG Merox Unit and the Recycle Gas Scrubber located in the DieselMax Unit. The combined rich amine stream flows to the Rich Amine Flash Drum ( 810-V4 ) where any hydrocarbon is separated from the rich amine. Liquid hydrocarbon is separated into a reservoir in the Rich Amine Flash Drum and can be periodically pumped to the Light Slop Oil Tank at the Tankage and Blending System via the Slop Oil Pump ( 810-P1A/B ). Hydrocarbon vapor separated in the Rich Amine Flash Drum, which contains H2S, is scrubbed with a small lean amine slipstream in the stack portion of the Rich Amine Flash Drum. The treated off gas is sent to the Acid Gas Relief Header. Rich amine from the bottom of the Rich Amine Flash Drum is pumped via the Rich Amine Pumps ( 810-P2A/B ) and heated in the Rich-Lean Amine Exchanger ( 810-E3 ). The heated rich amine flows on level control to the Amine Regenerator ( 810-V5 ). The Amine Regenerator strips nearly all of the H2S from the rich amine, thus regenerating it to lean amine. Heat is supplied to the Amine Regenerator through the steam-heated Amine Regenerator Reboilers ( 810-E2A/B ) by vaporizing a portion of the lean amine in the bottom of the column. A small quantity of live stripping steam is injected into the reboiler return lines to make water-balance the entire amine system. Offgas from the top of the Amine Regenerator, containing H2S, some light hydrocarbons, and water vapor is partially condensed by the Amine Regenerator Condenser ( 810-EA1 ). The two-phase stream from the Condenser enters the Amine Regenerator Receiver ( 810V6 ), where the liquid water is separated from the remaining acid gas stream. The liquid water from the Receiver is pumped as reflux to the top of the Amine Regenerator by the Amine Regenerator Reflux Pumps ( 810-P3A/B ). The acid gas from the Receiver flows on back-pressure control to the SRU. Lean amine from the bottom of the Amine Regenerator flows to the shell side of the RichLean Amine Exchanger, giving up some heat to the rich amine stream. The cooled lean amine is pumped by the Lean Amine Pumps ( 810-P3A/B ) to the Lean Amine Cooler ( 810EA2 ). A slipstream of cooled lean amine passes through a series of three filters: Mechanical Filters ( 810-ME1A/B ) to remove solids down to 20 microns, Carbon Filter ( 810-V7 ) to remove chemical impurities, and the Sock Filters ( 810-ME2A/B ) to catch carbon fines from the Carbon Filter. The slipstream of filtered lean amine recombines with the larger stream of cooled lean amine. The combined amine stream provides lean amine for the following services. A small stream of lean amine is sent on flow control to the stack of the Rich Amine Flash Drum to scrub the offgas from this drum. Another stream of lean amine is taken off for use in the LPG Merox Unit and DieselMax Unit. The last stream of lean amine is sent to the Fuel Gas Amine Absorber on flow control.

The Amine Treating Section also includes an Amine storage facility. Pure Amine ( 99 wt% DEA ) will be periodically delivered in bulk amounts and pumped directly to the Make-up Tank ( 810-TK1 ). The pure amine is diluted with cold condensate to the 20 wt% solution in the Amine Storage Tank ( 810-TK2 ).

Control Flow Plan Lean Amine supply to Absorbers (Figure 2.1) Regenerated, or lean, amine solution is pumped by the Lean Amine Pumps through the Lean Amine Cooler and the filtration system to the top of the H2S Absorber column on flow control. A part of the total lean amine stream provides lean amine for the following services. A small stream of lean amine is sent on flow control to the stack of the Rich Amine Flash Drum to scrub the off-gas from this drum. Another stream of lean amine is taken off for use in the LPG Merox Unit and DieselMax Unit. Rich Amine Return to Regenerator (Figure 2.2) The amine, rich in H2S, and for that reason called rich amine, exits from the absorber bottom, on level control and flows to the Rich Amine Flash Drum where entrained hydrocarbons are removed, and then sent to the Amine Regenerator.

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Figure 2.1 LEAN AMINE SUPPLY TO ABSORBERS

FRC Fuel Gas Amine Absorber 810-V1

Amine Regenerator 810-V5 F R C

1

1 3 4

Rich Amine Flash Drum 810-V4

Lean Amine Trim Cooler 810-E9 2

PDIC Lean Amine Cooler 810-EA2

0

2 3

Lean Amine Carbon Filter 810-V7 F R

Lean Amine Sock Filter 810-ME2A/B Lean Amine to DieselMax

Lean Amine to LPG Merox Unit

Rich-Lean Amine Exchanger 810-E3

Lean Amine Mechanical Filter 810-ME1A/B

Rich Amine Lean Amine Pump 810-P3A/B

Figure 2.2 RICH AMINE RETURN TO REGENERATOR Amine Regenerator 810-V5

Fuel Gas Amine Absorber 810-V1

1

Rich Amine from LPG Merox Unit Rich Amine from DieselMax Unit

2 0

L I C

Slop Oil to Tankage and Blending System ( Light Oil Slop Tank )

Gas to Acid Gas Flare Header

P I C

L I C

A u t o S t o p Slop Oil Pumps 810-P1A/B

Rich Amine Flash Drum 810-V4

L e a nL AI mC i n e Lean Amine to Lean Amine Pumps

M Rich Amine Pumps 810-V2A/B

16

Rich-Lean Amine Exchanger 810-E3

JOB CODE 0-0800 JGC DOC. NO. S-810-1230-

OPERATING MANUAL OF AMINE TREATING UNIT 001

SHEET 17

OF 126

Emergency Equipment Safety valves Summary of Safety Valves Summary of the safety valves provided for this unit is shown below. Refer to “DATA SHEET FOR SAFETY RELIEF VALVES” ( S-810-1374-301 ) . Tag. No. 810-PSV-001A/B 810-PSV-002A/B 810-PSV-003 810-PSV-004A/B 810-PSV-005A/B 810-PSV-006A/B 810-PSV-007 810-PSV-013 810-PSV-014 810-PSV-016

Set

Size and

kg/cm2g

Type

11.3 3.5 9.3 6.0 26.9 26.9 26.5 10.0 18.3 6.0

3K4 6Q8 3/4*1 3L4 3/4*1 3/4*1 1E2 4N6 3/4*1 1.1/2F2

Service

Location

Governing Relief Case

810-V2 810-V4 810-E3 810-V5 810-ME1 810-ME2 810-V7 810-V4 810-E9 810-ME4

Top mounted Top mounted Outlet Top mounted Inlet Inlet Top mounted Inlet Inlet Outlet

Blocked Outlet Blow by Thermal Fire Fire Fire Fire Blow by Thermal Blow by

Summary of Flare Loads Refer to “ Flare Load Summary”(S-810-1223-701). Car sealed valves Car Sealed Open or Car Sealed Close valves are listed below. Position

Line No. / Service

Size

Equipment / Line No.

P&ID No.

Open Open Open Open Open Open Open Open

810-¾”-FA-0301-A1A2P-ST 810-¾”-FA-0302-A1A2P-ST 810-¾”-FA-0303-A1A2P-ST 810-¾”-FA-0304-A1A2P-ST 810-¾”-FA-0305-A1A2P-ST 810-¾”-FA-0306-A1A2P-ST 810-¾”-FA-0307-A1A2P-ST 810-PSV-103 inlet line

¾” ¾” ¾” ¾” ¾” ¾” ¾” 3”

D-810-1225-103 D-810-1225-103 D-810-1225-103 D-810-1225-103 D-810-1225-103 D-810-1225-103 D-810-1225-103 D-810-1225-111

Open

810-PSV-103 discharge line

2”

Open

810-6”-SSW-1101-A1A2

6”

Open Open Open Close

810-¾”-FA-1301-A1A2P-ST 810-PSV-001A inlet line 810-PSV-001A discharge line 810-PSV-001B inlet line

¾” 4” 4” 4”

810-P7A/B 810-P8A/B 810-P11A/B 810-P1A/B 810-P2A/B 810-P4A/B 810-P10A/B 100-6”-SSW-3403A1A2 100-6”-SSW-3403A1A2 100-6”-SSW-3403A1A2 810-V1 810-V2 810-V2 810-V2

D-810-1225-111 D-810-1225-111 D-810-1225-113 D-810-1225-113 D-810-1225-113 D-810-1225-113

Open Open Open

810-PSV-001B discharge line 810-2”-FA-1304-A2A1P-ST 810-PSV-013 inlet line

4” 2” 6”

Open

810-PSV-013 discharge line

6”

Open Open Open Close Open Open Open Open Open Open Open Open Open Open Open Open Close Open

810-¾”-FA-1404-A1A2P-ST 810-PSV-002A inlet line 810-PSV-002A discharge line 810-PSV-002B inlet line 810-PSV-002B discharge line 810-2”-FA-1402-A1A2P-ST 810-PSV-006A discharge line 810-PSV-006B discharge line 810-PSV-007 discharge line 810-PSV-005A discharge line 810-PSV-005B discharge line 810-2”-N2-1701-A1A1 810-1”-N2-1701-A1A1 810-2”-N2-1702-A1A1 810-1”-N2-1702-A1A1 810-4”-FA-1702-A1A2P-ST 810-3”-AM-1707-A1A1P 810-PSV-003 inlet line

¾” 10” 8” 10” 8” 2” 1” 1” 2” 1” 1” 2” 1” 2” 1” 4” 3” 1”

Open

810-PSV-003 discharge line

1”

Open Open Close Open Close Open

810-PSV-004A inlet line 810-PSV-004A discharge line 810-PSV-004B inlet line 810-PSV-004B discharge line 810-1”-SSW-2001-A1A2 810-¾”-FA-2002-A1A2P-ST

6” 4” 6” 4” 1” ¾”

810-V2 810-V9 810-10”-AM-1101A1A2P 810-10”-AM-1101A1A2P 810-SN-8 810-V4 810-V4 810-V4 810-V4 810-V4 stack 810-ME2A 810-ME2B 810-V7 810-ME1A 810-ME1B 810-TK1 810-TK1 810-TK2 810-TK2 810-V8 810-V8 810-8”-AM-1803A1A2P-IH 810-8”-AM-1803A1A2P-IH 810-V5 810-V5 810-V5 810-V5 810-P4A/B 810-SN-10

D-810-1225-113 D-810-1225-113 D-810-1225-114 D-810-1225-114 D-810-1225-114 D-810-1225-114 D-810-1225-114 D-810-1225-114 D-810-1225-114 D-810-1225-114 D-810-1225-115 D-810-1225-115 D-810-1225-115 D-810-1225-116 D-810-1225-116 D-810-1225-117 D-810-1225-117 D-810-1225-117 D-810-1225-117 D-810-1225-117 D-810-1225-117 D-810-1225-119 D-810-1225-119 D-810-1225-119 D-810-1225-119 D-810-1225-119 D-810-1225-119 D-810-1225-120 D-810-1225-120

Remote operating valves No remote operating valves are provided in this unit. . Instrument alarms Instrument alarm type are listed below. Set values of each alarm are as shown below: (1) Level alarm Tag No.

Service

LI-019 LIC-007 LIC-010 LI-020

Absorber Knockout Drum Level Fuel Gas Amine Absorber Level Rich Amine Flash Drum Level R. Amine Flash Drum Interface

Unit: % ALL AL

AH

7 19.7 9.8

68.8 66.7 80.1 89.9

AHH

P&ID No. D-810-1225-113 D-810-1225-113 D-810-1225-114 D-810-1225-114

18

JOB CODE 0-0800 JGC DOC. NO. S-810-1230-

OPERATING MANUAL OF AMINE TREATING UNIT 001 LI-075 LI-023 LI-025 LI-033 LIC-041

SHEET 19

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18.8 9.3 14.9 20 22.5

92.5 95 85.1 80 84.3

D-810-1225-117 D-810-1225-117 D-810-1225-117 D-810-1225-119 D-810-1225-120

Unit: ℃ ALL AL

AH

Amine Make-up Tank Level Amine Storage Tank Level Amine Sump Tank Level Amine Regenerator Level A. Regenerator Receiver Level

(2) Temperature Alarm Tag No.

Service

TI-013 TI-011 TI-028

Lean Amine Cooler Outlet A. Regenerator Bottoms Outlet Desuperheater Outlet

56 140

AHH

66 137 150

P&ID No. D-810-1225-116 D-810-1225-119 D-810-1225-119

(3) Flow Alarm Unit: Nm3/h or m3/h ALL AL AH AHH

Tag No

Service

FI-004 FI-015 FIC-031 FIC-032

A. Absorber Ovhd ( Treated gas ) Mechanical Filters Inlet line Regenerator Reboiler-A Outlet Regenerator Reboiler-B Outlet

4825 15 2.8 2.8

P&ID No. D-810-1225-113 D-810-1225-116 D-810-1225-119 D-810-1225-119

22

(4O)Pressure Alarm Unit: kg/cm2g ALL AL AH AHH

Tag No

Service

PIC-002

Treated Gas to SRU/ FG System

8.6

P&ID No. D-810-1225-113

(5) Differential Pressure Alarm Unit: kg/cm2 ALL AL AH

Tag No

Service

PDI-079 PDI-080 PDIC-014 PDI-081

Lean Amine Sock Filters DP Lean Amine Carbon Filter DP PDV-014 DP Lean Amine Mech. Filters DP

1.3

AHH

1.0 1.0 1.7 1.0

P&ID No. D-810-1225-115 D-810-1225-115 D-810-1225-116 D-810-1225-116

(6) Other Alarm Tag No

Service

ALL

VSH-108 VSH-125

810-EA2 Vibration 810-EA1 Vibration

AL

AH x x

AHH

P&ID No. D-810-1225-116 D-810-1225-120

Tag No.

Service

P&ID No.

XA-918A/B/E/F XA-919A/B/E/F XA-920A/B/E/F

810-P1A/B Seal System Trouble 810-P2A/B Seal System Trouble 810-P4A/B Seal System Trouble

D-810-1225-114 D-810-1225-114 D-810-1225-120

Instrument trip settings Trip settings cause to plant shut down are listed below. Refer to “CAUSE AND EFFECT CHART “ ( S-810-1371-401)on Attachment 9.12. Procedures for setting protective relays Access control to various manipulations on DCS for this project is shown below and details of operating procedures is shown in the DCS vendor's operating manual :

Controller SP Alarm SP PID Tuning Constants OtherParameters (e.g. dir/rev)

Operator

Supervisor

Engineer

x

x x

x x x

Access control to various manipulations on ESD PLC for this project is shown below and details of operating procedures is shown in the DCS vendor's operating manual: Operator Trip SP Other Parameters (e.g. Timer)

Supervisor

Engineer x x

20

OPERATING MANUAL OF AMINE TREATING UNIT 001

JOB CODE 0-0800 JGC DOC. NO. S-810-1230SHEET 21

OF 126

Preparing Unit for Pre-commissioning The following section will discuss the various aspects associated with the commissioning of the Amine Treating Process Unit. This section contains information about the pre-commissioning and initial start-up of the unit. The pre-commissioning procedures ensure that the unit is safe, operable, and constructed as specified by thorough inspection and testing. 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. All of the following activities are required to properly pre-commission this unit. 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 Inspection 2. Inspection of other Major Equipment 3. Piping and Instrument Check 4. Hydrostatic Testing 5. Line Flushing 6. Run-in of Pumps and Drivers 7. Servicing and Calibration of Instruments 8. Commissioning of Utilities 9. Availability Check of Chemicals, Catalysts, and Other Materials 10. Plant Pressure Test 11. Air Freeing 12. Commissioning of Additional Plant Services Commissioning of Utilities Utilities are placed in service during commissioning ( preparation for start-up ). However, it should be verified that all utilities are in service or in readiness prior to start-up. Lines should be flushed and leak tested. Steam lines should be warmed up slowly to prevent damage from water hammer. All steam traps and control valves are to be placed into service and tested. The following list of systems should be commissioned: 1. Plant water and treated water systems. These systems should already have been commissioned prior to the line flushing procedure. 2. All electrical and light systems, including emergency power backups. 3. All plant and instrument air systems. 4. Nitrogen system. 5. Steam and condensate systems, excluding steam tracing for the moment.

6.

Condensate systems, receiving condensate from steam traps of several steam systems noted above, are ready for service. All steam traps should be checked for operability. 7. All drains and effluent systems. 8. All fire fighting and other emergency equipment. 9. All storage tanks must be thoroughly flushed, leak tested, dried, and perhaps airfreed if the tank is in hydrocarbon service. Those tanks that have been air-freed should be left under slight positive nitrogen pressure. All lines to and from tankage must be flushed, blown dry with nitrogen, and pressure tested. The steam tracing, plant cooling water, and flare systems will be commissioned after the plant pressure test has been completed. Pressure Testing No field hydrostatic pressure test of equipment is planned for the unit. Vessels are assumed to have met hydrotesting requirements in the fabricator shops. Hydrostatic tests are made on new or repaired equipment to prove the strength of materials and welds. This test is normally performed by construction personnel and it should not be confused with other less severe tests generally carried out before a start-up to check the tightness of connections. Flushing out 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. The following items are suggested as guide for line flushing: 1. Where practical, clean water should be supplied to the vessels, and contiguous lines should be flushed away from the vessel. Never flush into equipment. 2. No matter what the flushing medium - steam, air, or water - maximum volume and velocity should be used for thorough cleaning. 3. Remove orifice plates before flushing. 4. Control valves and in-line instruments should be removed. 5. Instrument lines should be closed off or disconnected. The instrument air header should be thoroughly blown with clean, dry air. 6. Relief valves should be blinded if they have been returned to service following hydrostatic test. 7. Regulate the flushing medium at its source. As examples, water from a vessel should be regulated at the vessel; and steam, at the valve in the supply to the line being blown. 8. Where possible, flush downward or horizontally. 9. Always flush through a piece of equipment’s bypass to an open end before flushing through the equipment. 10. Disconnect lines and exchangers and flush to the openings. 11. Flush through all vents and drains. 12. At pumps:  Disconnect suction and discharge piping and flush lines. Do not introduce any fluid into pump casing before cleaning the pump suction.  Install temporary screens in pump suction strainers.  Reconnect lines for circulating water.

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 See further discussion under “Run-in of Pumps and Drivers”. Flush or blow:  The main header, from source to end, then  Each lateral header, from the main to end, and  Each branch line, from the lateral header to end. 1. For steam systems, flush well through dirt leg drains and steam trap bypasses before placing the traps in service. 2. Supply steam lines to ejectors should be disconnected while being cleaned. 3. Flush through open end lines. Do not restrict flow in principle. 4. After placing the steam traps in service, check whether the traps operate properly. 5. After flushing operation, check that all orifice plates are installed and positioned correctly as per list. 6. When necessary vessels or drums are used as water reservoirs for flushing, check vessels for water-filled design. Moreover, a water-filled system must not be drained without adequate venting to avoid a vacuum condition and probable collapse of equipment not designed for vacuum. Upon completion of line flushing of any system, carefully check that all temporary breaks are reconnected, control valves are replaced, and pumps alignments are normal. Also, verify that all free water has been drained. 1.

Acid Cleaning of Reciprocating Compressor lines Not applicable to this unit. Inspection and Run-in of Pumps and Fans Proper installation and operation of pumps and drivers is essential for trouble-free performance. The pumps and drivers should receive careful handling during initial runin. The initial run-in of pumps is generally done by circulating water through the new equipment. Temporary strainers are installed in the suction line of the pumps, conveniently located for removal and cleaning. The screens should be positioned so that dirt particles will not gravitate to inaccessible places when flow is stopped. During run-in of pumps, the strainers may cause some restriction of flow. As debris collects in the strainers, flow to the pumps will fall off. When this happens to a centrifugal pump, it will be necessary to throttle the pump discharge by partially closing the discharge valve. This will prevent the pump from cavitating, which can cause damage to the pump. However, also avoid restricting the pump discharge to the extent that it causes internal slippage and excessive heat generation. In starting a turbine driven centrifugal pump, the rotation should be brought up to the speed as rapidly as possible. Normal operating speeds are usually attained rapidly and automatically with motor-driven pumps, assuming proper motor starting. The development of discharge pressure is essential to flush and lubricate the wearing rings. After initially starting the pump, close the discharge valve for a short time. Subsequently, it is always advisable, where practical, to close the pump discharge valve immediately prior to shutting down a centrifugal pump. However, discharge valves on operating positive displacement pumps should never be closed. These pumps can over pressure themselves and downstream lines and equipment. The following items are suggested for checking prior to run-in: 1. The manufacturer’s operating instructions for any specific precautions that should be observed. 2. Completion of overall installation.

3.

Alignment of pump and driver for cold operation. No undue strain by the piping on the pump or driver is allowable. 4. Cooling fluid piping and seal or gland oil piping:  Conventionally packed pumps in hot service are generally furnished with gland oil. Verify that this installation is correct and complete.  For pumps with mechanical seals, verify that all of the components of the flushing system ( such as strainers, separators, restriction orifices, and coolers ) have been correctly installed and are clean. Loss of flush or dirty flush may cause the failure of seals. 1. Packing or seals are installed. 2. Bearings and shafts have been cleaned prior to final lubrication. 3. Pump and driver are lubricated according to lubrication instructions. 4. Rotation of electric motor drivers uncoupled from the pump. Run-in uncoupled for a minimum of four hours, verifying good motor operation. During run-in, many pumps are delivering a higher density liquid ( water ) than the normal process fluid. But the pumps drivers are sized for the normal pumping fluid. Consequently, there is potential for the overload of many electric motors. To avoid overloading the motor of a centrifugal pump, the flow must be limited by throttling the pump discharge valve. When doing so, if possible, check the amperage usage against design. The following procedure is suggested for pump run-in: 1. Rotate pump and driver by hand, verifying that they roll freely. 2. Check that run-in water circulation is lined up. 3. Open suction valves fully, venting air from piping and pumps, completely filling with liquid. 4. Establish flow of cooling fluid, where required. 5. Check that lubrication is satisfactory. 6. Make sure that electric power is available from the switch gear to the starter of the electric motor driver. 7. Barely open the discharge valve on the centrifugal pump. 8. Start the pump; if the pressure does not build immediately, stop and resolve the problem. 9. When the discharge pressure has increased satisfactorily after starting, gradually open the discharge valve to obtain the desired flow rate. 10. In the event of unusual noise, vibration, overheating, or other abnormal conditions, shut the pump down immediately. Correct the cause before resuming use of the pump. Continue to check for abnormal conditions as these may occur after prolonged operation. 11. Check shaft sealing; mechanical seals should show no leakage. Conventionally packed stuffing boxes must always be permitted to leak slightly to provide some lubrication and to prevent overheating. Stuffing box gland nuts are generally only finger tight. A leaking mechanical seal will show some leakage on start-up. However, after the pump is started and stopped a few times, the leakage may stop. 12. Operate the pump, directing flows through all suction and discharge piping circuits. 13. Inspect and clean screens as required. 14. Recheck and realign if required, after any disturbance of piping, such as required for suction screen inspection if pipe flanges have to be parted for screen removal. 15. When shutting down, close the discharge valve first, maintaining discharge pressure while the pump rolls to a stop. This will protect against the pump rolling

24

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OF 126

backwards should the discharge check valve leaks, and gives the wearing rings a quick flush. After all lines available to a pump have had suitable flushing, the temporary screen may be removed, but only after it has shown free of debris on two successive examinations. The permanent strainers may then be installed where required. Leak Test The purpose of the leak test is to check the piping and equipment for tightness of flanges, connections, and fittings. These tests should not be confused with the hydrostatic tests made during construction. Generally plant air or nitrogen is used for this test. Prior to test, all the instruments which have been unmounted in the previous steps must be remounted. The temporary isolating blinds must be removed for a final pressure test, but the battery limit blinds must remain in the closed position. The tightness test must be conducted within certain blocks divided according to the design pressure of each vessel.  The recommended pressure for the tightness test is about 7.0 kg/cm2G ( available pressure in air system ) or the normal operating pressure, whichever is smaller.  Leakage shall be checked with soap solution.  All flanges shall be checked for leakage and re-tightened, if leakage is found.  During the tightness test, the operating pressure shall be maintained as shown above.  A final leak/pressure test with process fluids at working pressure is made as part of the plant start-up described in the next section. The test pressure should be held for a minimum of one hour, while every flange and joint in the system is closely examined for leaks. Stubborn flange leaks may often be stopped by simply unbolting and rebolting the flanges. Screwed connections may require Teflon tape. Inspection and Run-in of Reciprocating Compressor Not applicable to this unit. Inspection and Run-in of Centrifugal Compressor Not applicable to this unit. Loading internal material required for absorbers, vessels, packed columns Not applicable to this unit. Drying out Fired heater Not applicable to this unit. Drying out Reactor section Not applicable to this unit.

Preparing Reactors Not applicable to this unit. Loading Catalyst Not applicable to this unit. Degreasing for Amine Circulating System The presence of heavy hydrocarbon, such as grease or rust inhibition coatings on vessel walls and internals, could cause serious amine emulsification problems if allowed to remain. Also any rust present will quickly react with H2S on start-up to form particulate iron sulfide. Accordingly, all piping and equipment that will be in contact with the amine solution must be thoroughly cleaned and degreased. The preferred cleaning solution is 2 wt% solution of sodium carbonate ( Na2CO3, also called soda ash ). This degreasing and cleaning solution is prepared in the Amine Storage Tank (810-TK2) and circulated throughout the amine treating unit, employing the normal amine circulation flow path. While circulating, the solution is mildly heated with the stripper reboiler to 60 oC to aid in the grease removal. Following thorough cleaning, the soda ash solution is drained and replaced by condensate water and the circulation scheme repeated to rinse the equipment. A detailed degreasing procedure follows. Note: This procedure presumes that the amine treating unit pre-commissioning activities are complete, all utilities are available, and instrumentation has been checked out and is ready for service. The gas blanketing system for Amine Storage Tank can be commissioned at this time to have it ready when amine solution is prepared. Preparation of Degreasing Solution Prepare a 2 wt% solution of soda ash with steam condensate in the Amine Storage Tank. The volume of soda ash solution required will be approximately equal to the volume of amine inventory in the bottom of the stripper, plus each absorber to a 50% gauge glass level, plus 20 percent of the Amine Storage Tank volume, plus approximately 25% of this total volume to allow for line volumes, vessel tray inventories and complete column flooding, one at a time. This quantity of solution is easily prepared using the amine make-up facilities and the amine storage tank. The amine storage tank can be used to dissolve the soda ash in water as a concentrated solution. The soda ash should be completely dissolved to avoid “lumping” of the solid which would cause pumping and pump screen plugging problems. The amine transfer pump is used to circulate the soda ash solution in the storage tank to provide a homogeneous solution. Sample and analyze the solution to determine the soda ash concentration. Add more water or soda ash as indicated by the sample result to adjust the soda ash concentration to approximately 2 wt%. Temporary Modifications to the Unit 1. Remove the filter elements from the amine filters. If activated charcoal has already been loaded into the filter, isolate the filters with block valves and blinds to avoid circulation of soda ash solution through them. 2. Connect plant air or nitrogen hoses fitted with temporary pressure regulators to the overhead line of each absorber column. This will provide a pressure source

26

OPERATING MANUAL OF AMINE TREATING UNIT 001

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OF 126

with which to maintain adequate pressures in the column to circulate degreasing solution back to the stripper. Determine the required absorber operating pressures to assure circulation back to the Rich Amine Flash Drum(810-V4). In case of high pressure absorbers with their respective high pressure drop rich amine control valves, special provisions should be made to allow for control of the absorber level at the lower-than-design pressure of degreasing. 3. Make provisions to vent the regenerator pressure as it slowly increases during circulation. If air is being used to pressure the absorbers, venting of excess regenerator pressure to a commissioned flare header must be avoided. Similarly, amine vessel relief valves must be isolated to prevent flare gas leakage into the system which might form a combustion mixture. 4. Make a temporary hose connection between the lean amine circulation pump discharge and the steam-out or other suitable connection the Amine Regenerator Receiver (810-V6) to include this vessel in the degreasing procedure. Inventory and Circulate Prior to inventory of amine solution, cold and hot water circulation shall be conducted with clean water to make pre-cleaning of the system. 1. Gauge the Amine Storage Tank and record the actual volume of the soda ash solution available. Keep a record for future reference of the total volume of soda ash solution ultimately required to establish stable circulation in the unit. This measurement will also be helpful when the initial amine volume is blended for start-up of the unit. 2. Using the Amine Transfer Pump, fill the Amine Regenerator Receiver with soda ash solution via the temporary hose connection. Empty the receiver to the Amine Regenerator using the reflux pump. Repeat this filling and emptying three times. If time permits, with the regenerator off gas control valve blocked in, fill the Amine Regenerator Condenser and overhead line with soda ash solution once via the same temporary hose connection and empty with the reflux pump. CAUTION: Do not fill the overhead line if the overhead condenser tubes are aluminum. Generally, the amine transfer pump capacity is small and this initial inventorying will be time consuming. 3. Following the cleansing of the regenerator overhead system, route the incoming soda ash solution from the transfer pump discharge into the suction of the lean amine circulation pumps. This will back solution into the regenerator bottoms by way of the lean/rich exchanger. 4. When a 50% level appears in the amine regenerator bottom level glass, start the lean amine circulation pump, and begin to inventory working levels in each absorber via the normal lean amine transfer line. This may have to be done batchwise to prevent a loss of level in the regenerator bottom. 5. When working levels have been established in the absorbers and the regenerator, pressure each absorbers and the regenerator, pressure each absorber to its predetermined circulation pressure with the temporary hose and pressure regulator connection on the overhead line. 6. Begin circulation to each absorber. Commission each absorber bottom level controller when levels are established and return the soda ash solution back to the regenerator. 7. Supplement the regenerator soda ash solution level as necessary with additional solution to or from the lean amine storage tank to maintain a 50% working level in the regenerator. 8. Line out the circulation rates at or near design amine circulation rates.

9. 10. 11.

12. 13. 14.

15. 16.

With the circulation flows stabilized, carefully commission the amine regenerator reboiler and gradually increase the circulating soda ash temperature to 60 oC. NOTE: The lean amine cooler should not be in service. Maintain soda ash solution circulation for a minimum of four hours, preferably 24 hours, to assure that all surfaces are contacted by the soda ash solution. Remember to route a slipstream through the empty filter housings. After the soda ash solution has circulated four hours, flood each absorber with soda ash solution until it is completely full to make sure that all internal surfaces have been wetted and degreased. Make sure that no equipment is over-pressured during this step. Also flood the amine storage tank when appropriate. Sample and analyze the soda ash solution during circulation to assure that the soda ash is not totally consumed. If this is the case, additional soda ash should be added to the circulating solution. Slowly reduce the steam flow to the regenerator reboiler but continue the soda ash circulation for a few additional hours to allow it to gradually cool to approximately 38 oC . Shut down the lean amine circulation pump and discontinue circulation. Pressure the soda ash solution from each absorber to the amine regenerator. If the regenerator foundation loading will permit, it too can be flooded with soda ash solution for the most effective degreasing. As soda ash solution is drained from pumps, lines, and vessels, the amine sump will be filled with the used soda ash solution. The sump is pumped out via a temporary hose to the refinery oily water sewer system. Finally, drain all vessels, tanks, pumps, and lines of the dirty soda ash solution making sure some residual pressure remains on all columns to avoid any chance of a vacuum.

Water Rinse 1. Reestablish working levels in the regenerator and absorber(s) as before but this time use cold condensate instead of soda ash solution. This may be done as previously outlined for the soda ash solution or by multiple hose connections to the treated water supply header, whichever is more convenient. Do not forget to rinse the regenerator overhead system. 2. Proceed as outlined for the soda ash solution except that circulation of the water for four hours can be done at ambient temperature unless climatic conditions favor slight warming. 3. When rinsing is complete, drain the water to the sewer, again taking care to maintain positive pressure on all equipment. 4. Reinstall the amine filter elements when washing and rinsing is complete. 5. Check and clean up pump screens one final time. Purging and gas blanketing Before admitting hydrocarbons into any process lines or vessels, safe refinery practice requires that the unit be freed of air. The air may be displaced with water, steam, or inert gas, such as nitrogen. The system must be purged to prevent formation of explosive mixed gas prior to admitting flammable materials. If steam is used, precautions should be taken to avoid the following potential problems or hazards: 1. Collapse Due to Vacuum: Some of the vessels may not be designed for vacuum. This equipment must not be allowed to stand blocked in with steam since the condensation of the steam will develop a vacuum. Thus, the vessel must be

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vented during steaming and then immediately followed up with fuel gas or nitrogen purge at the conclusion of the steam-out. Flange and Gaskets Leaks: Thermal expansion and stress during warm-up of equipment along with dirty flange faces can cause small leaks at flanges and gasketed joints. These must be corrected at this time. Water Hammering: Care must be taken to prevent “water hammering” when steam purging the unit. Severe equipment damage can result from water hammering. The following steps briefly outline air freeing by steam purging: 4. Portions to be steam purged include all the columns, vessels, heat exchangers, and lines. 5. Pumps, sight glasses, level gauges and instruments are not to be steamed-out. This can be done by closing their inlet and outlet valves. 6. When the unit is divided into a number of sections for steam purging, it must be so arranged that steam is injected from one end of the section and blown out from the other end. 7. Open high point vents and low point drains on the vessels to be steam purged. After opening all vents and drains, steam purge is conducted by opening the valve at the steam outlet and blowing in steam from the steam out connection. Care must be taken not to cause hammering when introducing steam. It may be necessary to make up additional steam connections to properly purge some piping which may be “dead-ended”. 8. Thoroughly purge all equipment and associated piping of air. The progress of the steam purge can be followed by marking up the P&I diagram to indicate the lines purged. Verify that sufficient drains are open to drain the condensate which will collect in low spots in the unit. 9. When the steam purging is completed, start to close all the vents and drains. To prevent the creation of negative pressure within the system, the injection of a little steam must be continued until the subsequent filling of fuel gas or nitrogen is started. 10. After steam purging all the sections of the unit, open all the block valves that has been closed during the steam purging operation to enable the subsequent fuel gas or nitrogen filling throughout the system. 11. Start to introduce fuel gas or nitrogen into all vessels and then cut back the steam flow until it is stopped. Regulate the fuel gas or nitrogen flow and the reduction of steam so that vacuum due to condensing steam is not created in any vessel or that the refinery fuel gas system pressure is not appreciably reduced. Introduce fuel gas or nitrogen into the system to prevent vacuum. Maintain the pressure within the system at 0.5 ~ 1.0 kg/cm2G. When the system is under fuel gas pressure, check the O2 content. ( O2 content shall be less than 1.0 vol%. ). At every purging step, the pressure of each equipment must be kept under its respective design pressure. 12. Drain any residual condensate from the unit.

Pre-commissioning check list This procedure describes in general terms the steps to be followed for placing the unit on stream. The exact sequence of events depends on the flow scheme of the particular unit. However, the following steps must be completed before charging feed gas to the Unit. 1. All unnecessary blinds are removed, 2. All relief valves are tested and installed.

3. 4. 5. 6. 7. 8.

The flare header is purged and in service. The sewers are in service. The fuel gas is in service. All instruments and control systems are ready for service. All utilities are in service. Control valves and bypasses are blocked in.

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Commissioning General overall commissioning plan With the unit degreased, rinsed, and under an oxygen-free gas positive pressure, the unit is now ready for start-up. The amine solution can be prepared and inventoried into the unit. The actual volume of amine solution required can be best ascertained from the data obtained during the degreasing operations. The initial start-up consists of the following sequential activites: 1. Preparation of amine solution. 2. Inventorying amine to Regenerator and Absorbers. 3. Introduction of feed to unit. 4. Establishing Amine circulation. 5. Commissioning of Regenerator Reboiler. 6. Commissioning of Amine filters. 7. Final Adjustments of Operating parameters. Detailed step-by-step start-up procedure Preparation of Amine Solution Refer to the section 11.5. Inventorying Amine to Regenerator and Absorbers. 1. Confirm that the acid flare system has been air freed and is in service. Also confirm that any isolation blinds previously installed to isolate the unit from the flare system have been removed. 2. Transfer the amine solution from the Amine Storage Tank ( 810-TK2 ) to the Amine Regenerator ( 810-V5 ) with the Amine Transfer Pumps ( 810P6A/B ). As the amine level in the Regenerator increases, periodically start the Lean Amine Pumps ( 810-P3A/B ) and transfer amine to the absorbers until a visible working level is obtained in each absorber column. 3. With a working level ( ca. 50% ) in the absorber level glass, continue to inventory fresh amine to an 85% level in the Regenerator bottom. This additional volume of amine, and probably more, will be required when hydrocarbon flow to the absorber causes an increase in amine inventory on the absorber trays. 4. Verify that the amine regenerator off-gas line steam jacketing is commissioned and that all steam traps are passing condensate. These will require checking each and every shift. Initially, expect to clean these steam traps frequently until all of the dirt has been dislodged from the pipe jacket. Introduction of Feed to Unit 1. Introduce the hydrocarbon feed to each absorber, slowly pressuring each absorber to the design operating pressures. 2. Commission the pressure controller ( PIC-002 ) for the Fuel Gas Amine Absorber(810-V2). 3. Refer to the Operating Manual of the LPG Merox Process Unit for the Amine Absorber(802-V1) and that of the Dieselmax Process Unit for the Recycle Gas Scrubber(284-V5). Establishing Amine Circulation

1.

Start the Lean Amine Pumps ( 810-P3A/B ) and send lean amine to each absorber. Set the flow controller ( FIC-016 ) at mid scale and verify its operation for the Fuel Gas Amine Absorber(810-V2). 2. Verify that each absorber bottom has a working level, unblock the level control valve ( LV-007 ), and verify that the level control is operating correctly and rich amine is being returned to the Rich Amine Flash Drum(810-V4). 3. When 810-V4 has a working level, commission the Rich Amine Pump(810-P2A/B) and then put LIC-010 into auto. 4. Transfer amine solution from the Amine Storage Tank(810-TK2) to the Amine Regenerator(810-V5) as required to maintain an adequate working level in the Amine Regenerator bottom. This is the surge reservoir for the entire amine system and must never be so low that the pump loses suction, or so high that the reboiler return line is flooded. Note: If the commission of the Dieselmax Unit is delayed and it is difficult to maintain sufficient amine circulation to operate the pumps, some of the lean amine shall be Bypassed to the Rich Amine Flash Drum(810-V4) by using a bypass line(810-6”AM-1503-A2A1P). Commissioning of Regenerator Reboiler 1. With the amine circulation established, commission the steam flow to the Amine Regenerator Reboiler ( 810-E2A/B ). Introduce the steam slowly so as to heat up the reboiler yet avoid water hammer caused by rapid condensation/expansion. 2. Commission the Lean Amine Cooler ( 810-EA2 ) and the Amine Regenerator Condenser ( 810-EA1 ). 3. As the Amine Regenerator pressure rises, commission the amine regenerator acid gas pressure control ( PIC-043 ) to send the acid gas to the acid gas flare. The Amine Regenerator Receiver ( 810-V6 ) operating pressure will be set between 0.35 and 0.7 kg/cm2G. 4. When condensed liquid begins accumulating in the Amine Regenerator Receiver, prepare the Regenerator Reflux Pumps ( 810-P4A/B ) for operation. When a working level is obtained, start the reflux pump and begin refluxing back to the Regenerator. Commission the Amine Regenerator Receiver level control ( LIC-041 ), verify its operation, and place it on automatic control. 5. Continue increasing the heat input to the Amine Regenerator Reboiler by increasing the steam rate until the design reflux rate is achieved. At this time, verify that the proper temperatures have been achieved; typical temperatures are often as follows: Regenerator Feed 88-93 oC Reboiler Vapor 110-121 oC Regenerator Top 106-116 oC Reflux 61 oC Lean Amine 61 oC Commissioning of Lean Amine Filters 1. 2. 3.

Verify that the amine filter elements were installed in the filters. Crack open the filter inlet and slowly fill with lean amine while venting any gas present. With the filters liquid full, fully open the inlet and outlet gate valves. Adjust the differential pressure or flow controller to send the design amount of amine solution through the filters. Do not exceed the manufacturer’s recommended maximum pressure differential across this filters. Typically, this maximum differential is 1.5 kg/cm2.

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Be prepared to clean the filters quite frequently during the first or two of week operation.

Final Adjustments of Operating Parameters 1. With the amine treating unit in full operation, increase the amine flow rate to each absorber to the design rate. This flow rate will probably be higher than necessary but will somewhat offset the lower tray efficiencies expected when absorber hydrocarbon feed rates are below design. 2. Anytime the amine circulation rate is adjusted, an adjustment of the steam rate to the Regenerator Reboiler will be required to keep the heat input and regeneration in the proper range. A useful key is to adjust the steam input to keep the Regenerator reflux rate at a constant percentage of the total amine circulation rate, consistent with good regeneration, of course. Typically, the total steam requirement ( Regenerator reboiler plus live steam ) will be in the range of 120 to 140 kg of steam per cubic meter of amine solution circulated. ). 3. The recommended sampling and analytical testing should be begun immediately to determine if further plant adjustments are required. Special precautions Precaution for entering a contaminated or inert atmosphere Nitrogen is non-toxic. 79 mol-% of the air we breathe is nitrogen, 21 mol-% is oxygen. However, in vessels or areas where there is a high concentration of nitrogen, there is also a deficiency of oxygen for breathing. Breathing an atmosphere deficient in oxygen (i.e., an inert atmosphere) will rapidly result in dizziness, unconsciousness, or death depending on the length of exposure. Do not enter or even place your head into a vessel which has a high concentration of nitrogen. Do not stand close to a valve where nitrogen is being vented from equipment at a high rate which might temporarily cause a deficiency in oxygen close to the valve. Refinery personnel who do have to enter a contaminated or inert atmosphere should follow all prescribed standard safety precautions and regulations which apply for the refinery. OSHA regulations concerning the use of respirators (29 CFR Subpart 1, Section 1910,134) should be read and thoroughly understood. It is also important to emphasize that if a person has entered a vessel and become unconscious, no individual should go in to help him without first putting on a fresh air mask, confirming that the air supply is safe, donning a safety harness, and enlisting the aid of a minimum of two other people to remain immediately outside of the vessel to assist him. This may seem to be an obvious warning, but people do forget this in the trauma of an emergency situation. Often the first thought is to save the person in distress and people enter the vessel without proper protection only to succumb to the same hazard without anyone else being present to save them. Draining Amine Solution During normal operation, hot amine solution above 60 ℃ must not be drained to the closed amine recovery. If do so, the underground pipe might be broken due to thermal expansion.

Normal Start-up & Shutdown Normal start-up after prolonged shutdown The procedure used for starting up the Amine Treating Section after any shutdown is identical to the procedure used for initial start-up. Follow Section 5.2 ( Detailed stepby-step procedure ) of this manual for restarting of the Amine Treating Section. Normal operation procedure after short shutdown It is assumed that the following conditions are maintained:  Normal level of amine solution is kept for each absorber and the Amine Regenerator  A positive pressure is kept in each absorber by means of feed fluid or fuel gas or nitrogen.  All pumps have been stopped. The unit can be commissioned, starting from Commissioning of Regenerator Reboiler of the step by step procedures given in section 5.2. Normal Operation Product quality monitoring The major concern in amine treated streams is the quantity of H2S in the treated product and the effectiveness with which the absorber is removing H2S. For this reason, regular analysis is normally made only for H2S. The recommended methods for daily analysis of appropriate streams are listed below. Stream Absorber feed Treated product

Lab Method UOP 9 UOP 212 UOP 212

Analysis H2S H2S, RSH, COS H2S, RSH, COS

It is also useful to have a feed composition analysis for reference if an upset occurs. Therefore, a GLC analysis of each absorber feed is also required on a daily basis. Operation Conditions Monitoring In order to maintain good H2S removal, the amine concentration, H2S content, and visual appearance of the lean amine must be continuously monitored. It is also important to monitor the mole ratio of acid gas to amine, or acid gas loading, of the rich amine solution from each absorber. When this mol ratio exceeds about 0.5 or 0.6, the amine solution becomes increasingly corrosive toward carbon steel piping, particularly at elevated temperatures. It is desirable to keep the mol ratio of acid gas to amine in the rich amine below 0.4 by increasing the amine circulation rate to each absorber until this ratio is attained. The recommended analytical methods for simple monitoring of these streams are listed below: Stream Lab Method Analysis Lean Amine UOP 824 or 825 Free Amine UOP 827 Apparent H2S Rich Amine UOP 827 Apparent H2S

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The apparent H2S content of the amine solution is generally reported in grains ( abbreviated gr ) of H2S per gallon of amine solution. This value is converted to the mole ratio of H2S to amine by the following expressions: ( H2S, gr / gal ) x ( 5.3 x10-3 / DEA, wt% ) = mole ratio Routine operation Trouble shooting There have been many papers published on the subject of analytical control of amine solution. Sophisticated procedures have been published to analyze and overcome chronic problems. It is beyond the scope of these operating instructions to reproduce those papers, but their existence should be mentioned for those who seek additional information. The following items are furnished as a guide for assistance when routine analytical tests intended for monitoring plant performance seem confusing or inconsistent. Total Amine The UOP test methods 824 and 825, referred to previously in the Operations Monitoring discussion, mention “free amine”. These methods merely titrate all basic compounds present in a sample with standardized acid to the methyl red indicator endpoint and call them “free amine” by calculating them as if they were all amine; this is quite suitable for routine control purposes, for example the need for water make-up, but is chemically incorrect, except for fresh solutions. Periodically, therefore, the lean amine should be checked for total amine by UOP Method 828 and “free amine” by UOP 824 or 825 is an indication of the presence of amine degradation products. As an initial goal and until plant operation dictates otherwise, do not let the “total amine” content to exceed the “free amine” content by more than 2 wt%.. This is controlled by partial purging and partial replacement of the plant inventory with fresh 20 wt% DEA solution. Thiosulfate Oxygen entering the amine system in any manner quickly reacts with aminehydrosulfide to form amine-thiosulfate. Unlike amine-hydrosulfide, amine thiosulfate is heat-stable under Regenerator conditions and will gradually increase in concentration unless removed by purging. Thiosulfate will react with iodine in the test to apparent H2S, UOP 827, and be included as H2S in the calculation. Therefore, thiosulfate should be determined weekly by the analytical test method UOP 818 to make certain that any high apparent H2S concentration in the lean amine is not thiosulfate. Thiosulfate concentration should be kept low and should not exceed 50 grains/gallon when calculated as apparent H2S. Apparent H2S As just discussed, UOP Method 827 for apparent H2S does not discriminate between true H2S and thiosulfate; both are included in the analysis. High values of apparent H2S in the lean amine could be wrongly interpreted as poor Regenerator performance when, in fact, thiosulfate or other compounds are at fault. For example, sodium sulfide, present because of caustic contamination, is also titrated as apparent H2S. There is a

simple test that can quickly determine if inadequate Regenerator performance or other compounds are the case of the high apparent H2S. Determine the apparent H2S content in a portion of a lean amine sample using UOP 827. Add 100 ml of the same lean amine sample to a 500 ml flask, add 100 ml of distilled water, drop in a few boiling stones, and boil the sample over a hot plate in a laboratory fume hood until the volume of sample is reduce to 100 ml. Remove the 500 ml flask from the hot plate, add distilled water if necessary to reconstitute the original sample volume, cool, and again determine the apparent H2S content of the resultant sample by UOP 827. If the sample after boiling now indicates a much lower concentration of apparent H2S, inadequate stripping in the plant Regenerator may be a problem; increase the reboiler steam rate. If, however, the apparent H2S concentration has not greatly diminished, the amine solution is probably contaminated with thiosulfate, sodium sulfide, or some other material which titrates as apparent H2S. additional laboratory work can pinpoint the problem. Foaming Foaming in the Regenerator or gas absorber and emulsification of amine and hydrocarbon in the liquid/liquid absorber are sometimes problems. These problems can be largely avoided by good quality control of the amine solution to keep amine and acid gas concentrations in the proper range and by good filtration system maintenance so that the amine solution is always clear and visibly free of particulate matter when a grab sample is viewed in direct light. Good plant maintenance to quickly remove any liquid hydrocarbon accumulation from knockout pots and absorber skim lines are essential. If foaming or emulsification occurs despite these precautions, judicious use of silicon antifoam agents will usually eliminate the problem. The simple foam test can be of benefit when used routinely to monitor plant solutions for foaming tendency, particularly taking note of any changes, and if used to predetermine minimum antifoam injection rates, should a plant foaming problem develop. There are effective antifoam agents for injection into the amine solution to suppress foaming. High boiling alcohols such as oleyl alcohol have been used as antifoam agents. Current practice favors the use of the highly effective and easily handled silicone antifoam agents, such as Dow Antifoam A. Antifoam agents should not be injected unless foaming experience in the plant indicates their need. When needed, only a few parts per million, usually less than 10 parts by weight of the silicone compound per million parts by weight of plant amine solution, will effectively suppress foaming. In the case of gas treatment, the silicones cannot escape the unit; thus, continuous addition is not required. Antifoam agents applied indiscriminately when plant operation does not require them can actually promote foaming and lead to operating difficulties. Miscellaneous procedures Filter operation To maintain the differential pressure across the entire filtering system( a series of mechanical filter, carbon filter and sock filter) from exceeding or failing below 1.5 kg/cm2, PDV-014 is opened or closed. The filters are for slip-stream flow and pass whatever flow is possible with a 1.5 kg/cm2 differential. The design flow is 21 m3/h, but when the cartridges are clean, more flow will pass through the filters. When the flow through the filters drops to 19 m3/h,at a differential pressure of 1.5 kg/cm2, the filters should be changed over and cleaned.

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Antifoam injection Antifoam agent should be injected if foaming experience in the plant indicates its need. Continuous addition is not required. Injection Points  Rich amine line upstream of Rich-Lean Amine Exchanger(810-E3) for Amine Regenerator(810-V5)  Lean Amine line upstream of Lean Amine Trim Cooler(810-E9) for Fuel Gas Amine Absorber(810-V2) Skimming operation To avoid foaming troubles it is important to remove liquid hydrocarbon accumulation in Fuel Gas Amine Absorber(810-V2). Monitor LG-T 003 periodically. And discharge liquid hydrocarbons to Fuel Gas Absorber Interface Pot(810-V9) Routine control tests to be performed by operators Refer to section 11.7. General overall shutdown plan Normal shutdown consists of the following sequential activities: 1. Cutting off feed streams 2. Regeneration of amine solution 3. Recovery of the regenerated amine solution 4. Water circulation Detailed step-by-step shutdown procedure 1. 2. 3. 4. 5. 6. 7. 8.

9. 10. 11. 12. 13.

Throttle the feed flow rates to each absorber down to 50 % load. And also throttle lean amine flow rates to each absorber down to 60% of design. Commission lean amine bypass line to 810-V4 to maintain amine solution circulation after shutting down each absorber.. Divert the acid gas discharge to acid gas flare. Block in feed stream to each absorber. And maintain enough pressure in each absorber to force rich amine to the Rich Amine Flash Drum( 810-V4). Stop the lean amine supply to each absorber. Maintaining at least one circulation. Stop the steam input to the Amine Regenerator Reboilers(810-E2A/B). Open the bypass of FV-039 to pump as much liquid as possible to the Amine Regenerator(810-V5) and then shut down the Amine Regenerator Reflux Pumps(810-P4A/B) . Shut down the Amine Regenerator Condenser( 810EA1) as well. When circulating amine solution has cooled to 55 to 60 ℃, transfer lean amine to Amine Storage Tank(810-TK2) by using amine pumpout line. Shut-down the amine circulating loop( Rich Amine Pumps(810-P2A/B), Lean Amine Pumps(810-P3A/B) and Lean Amine Cooler(810-EA-2)). Drain out remaining amine in all equipment and piping Conduct water circulation of overall amine circulating loop to wash out remaining amine inside the system. Steam out all vessels and drums for inspection.

Blanking off Every line connecting to a nozzle on the vessel to be entered must be blinded off at the vessel. This includes drains connecting to a closed sewer, utility connections and all process lines. Install additional blinds at the battery limits as necessary for safety. The location of each blind should be marked on a master piping and instrumentation diagrams (P&IDs), each blind should be tagged with a number and a list of all blinds and their locations should be maintained. One person should be given responsibility for the all blinds in the unit to avoid errors. Opening equipment The area around the vessel manways should also be surveyed for possible sources of dangerous gases which might enter the vessel while the person is inside. Examples include acetylene cylinders for welding and process vent or drain connections in the same or adjoining units. Any hazards found in the survey should be isolated or removed. Safe access must be provided both to the exterior and interior of the vessel to be entered. The exterior access should be a solid, permanent ladder and platform or scaffolding strong enough to support the people and equipment who will be involved in the work to be performed. Access to the interior should also be strong and solid. Scaffolding is preferred when the vessel is large enough to permit it to be used. The scaffolding base should rest firmly on the bottom of the vessel and be solidly anchored. If the scaffolding is tall, the scaffolding should be supported in several places to prevent sway. The platform boards should be sturdy and capable of supporting several people and equipment at the same time and also be firmly fastened down. Rungs should be provided on the scaffolding spaced at a comfortable distance for climbing on the structure. If scaffolding will not fit in the vessel, a ladder can be used. A rigid ladder is always preferred over a rope ladder and is essential to avoid fatigue during lengthy periods of work inside a vessel. The bottom and top of the ladder should be solidly anchored. If additional support is available, then the ladder should also be anchored at intermediate locations. When possible, a solid support should pass through the ladder under a rung, thereby providing support for the entire weight should the bottom support fail. Only one person at a time should be allowed on the ladder. When a rope ladder is used, the ropes should be thoroughly inspected prior to each new job. All rungs should be tested for strength, whether they be made of metal or wood. Each rope must be individually secured to an immovable support. If possible, a solid support should pass through the ladder so that a rung can help support the weight and the bottom of the ladder should be fastened to a support to prevent the ladder from swinging. As with the rigid ladder, only one person should climb the ladder at a time. Also refer to Section 10.12 “Entering tanks, drums or other vessels. Special precautions When draining out the amine solution from the Amine Regenerator, make sure that the amine solution in it has already cooled down to 60 ℃. Then open the drain valve for the closed amine recovery. Otherwise, the underground pipe might be broken due to thermal expansion.

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Emergency Shutdown General instructions Emergency shutdown, capacity reduction, or modified operation of the Amine Treating Section can result from any of the following causes:  Loss of Utilities - loss of low pressure steam, cooling water, electrical power, or instruments air.  Equipment failure of some equipment items the plant require plant shutdown or capacity reduction.  Loss of Feed  Fire and other Emergencies  Loss of pump external flushing fluid The extent to which the plant will have to be shut down depends on the specific emergency. In any emergency, determine the extent of the emergency condition, and decide how to cope with it. Then proceed with one of the following actions as warranted by the emergency: Handle the emergency as a localized condition without shutting down the rest of the plant. For example, in the case of a faulty control valve. Block in and bypass the malfunctioning item until repairs can be made. OR Shut down the unit using the normal shutdown procedure described in Section 6.2. OR Shut down the unit using the emergency procedures given below for a specific emergency. In executing emergency shutdown steps, the normal shutdown procedure detailed in Section 6.2 should be followed as closely as possible. Fire Consequence If a fire occurs in the plant, that section of equipment in which the fire has occurred must be isolated to confine fire and depressured to eliminate the source of combustible material. Unless the fire is small and can be handled quickly the plant will shutdown. Operating supervisor on duty will advise on shutdown, based on refinery procedures in place. Actions Follow operation supervisor’s orders on shutdown and firefighting procedures. If plant must be shutdown:  Remove all heat input to the plant.  Block in feeds and product streams.  Isolate section or area where fire is occurring, to remove combustion source.  Depressure various columns and vessels to flare.  Shutdown remaining portions of plant as time and circumstances permit or require. Power failure When and electrical power failure occurs, the Amine Treating Section will be shut down. The plant is designed to fail safe when loss of power occurs,. A true emergency exists when an electrical power failure occurs. Consequence

The plant will have to be shut down. Feed will be lost , reflux to columns will be lost, and temperatures and pressures in columns will rise. Actions  Make sure all pumps are down (all electric driven).  Block in manually steam inlet valves to the reboiler and block in outlet valves.  Block in all feed and product streams in the plant.  Block in all pumps.  Follow the preceding action with an orderly shutdown using the normal shutdown procedures described in Section 6.2. Caution Maintain a positive pressure in the regenerator as it cools by using nitrogen. Instrument Air failure A true emergency exists when instrument air is lost. Consequence When an instrument air failure occurs the plant will shutdown. The plant is designed to fail safe when instruments air is lost. Actions  Block feed inlet valve at battery limits.  Follow the preceding action with an orderly shutdown using the normal shutdown procedure described in Section 6.2.  Maintain a positive pressure on the plant as it cools by using nitrogen. Do not let the regenerator go under a vacuum. LP Steam failure A true emergency exists when steam is lost . Consequence If low pressure steam is lost, amine stripping steam and heating steam to the reboilers will be lost. Therefore plant will be shut down. Actions Proceed with a normal shutdown when the emergency steps are complete. Water failure Cold Condensate failure Condensate is used intermittently in this unit, therefore, there is no serious consequence foreseen when it fails. However, a condensate failure when it is required will have an effect on the amine dilution operation of the unit.. Cooling Water failure When a cooling water failure occurs, the plant operation conditions must be adjusted. Consequences

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Cooling for lean amine coolers will be lost resulting in a slight increase in lean amine temperature to the absorber. Pump cooling will be lost. Actions  Monitor the H2S content in the treated streams.  Monitor the relevant pumps. If any pump has to be shut down, whole section will be shut down. Feedstock failure Consequence If feed is lost because of a power failure, the plant must be shut down as outlined under Electrical Failure. If lost because of feedstock failure then a unit shut down could happen. Action When loss of feed occurs, the following action should be taken:  Maintain plant in ”hot standby mode” until feed is available.  When feed is available, proceed with the plant start-up as discussed in Section 6.6.  If feed is lost for a long time period, follow emergency steps with and orderly shutdown using the normal shutdown procedure described in Section 6.2. Equipment failure Consequence A major equipment failure will shut down the unit for repairs. Action Under this emergency condition, immediately initiate the following procedure:  Proceed with a normal shutdown when the emergency steps are complete.  Have maintenance blind the involved equipment following the normal blinding procedure.  Await instructions from operating supervisor.

Major Equipment & its Service Summary tables Refer to Attachment 8.1 ( Equipment List of Amine Treating Process Unit, Doc. No. S810-1224-101 ). Tower summary Fuel Gas Amine Absorber ( 810-V2 ) This absorber is usually a valve or sieve tray column. Lean amine solution enters via a distributor near the top of the column, flows across each tray, and exits as rich amine from the bottom amine reservoir on level control. Feed gas first passes through a knockout drum furnished with a demister pad to remove entrained liquid mist, liquid, or condensate prior to entering the absorber. The feed gas enters through an inlet distributor located immediately below the bottom tray. H2S in the gas is removed as the gas passes upward through the tray openings and bubbles through the amine solution on each tray. The treated gas passes through a mist eliminator and exits from the absorber top, on pressure control. A skimming nozzle is provided in the wall of the bottom amine reservoir to permit removal of liquid hydrocarbon which might collect on the amine surface. Amine Regenerator ( 810-V5 ) This column is fitted with valve trays. Rich amine enters near the top side of the column through an amine feed distributor located below the top tray, three trays down from the top tray. The trays are the conventional type with the typical arrangement of weirs and chordal downcomers. The bottom tray is a liquid-tight accumulator tray with a center pipe for ascending vapor and a draw-off well directing all descending liquid to the steam heated reboiler. Heat input to the reboiler is controlled either by flow control of the steam condensate removed from the tubeside of this exchanger. A 110-120 oC reboiler outlet temperature is typical for a 20 wt% amine system at 0.7 kg/cm2G. A metered live steam connection is provided into the reboiler outlet line. Steam is injected at this point to compensate water lost with the acid gas from the overhead system and thereby adjust the amine concentration. Drum summary Fuel Gas Amine Absorber Knockout Drum ( 810-V1 ) The Fuel Gas Knockout Drum is a vertical vessel ( made of KCS ) furnished with a demister pad to separate entrained liquid mist, liquid hydrocarbon, or condensate from the off-gas stream prior to entering the absorber. The feed gas enters through an inlet distributor located less than a meter below the demister of the vessel. The feed gas passes through the mist eliminator and exits from the vessel top to the absorber. The accumulated hydrocarbon liquid is drained intermittently to the acid gas flare. Rich Amine Flash Drum ( 810-V4 ) The Rich Amine Flash Drum is a horizontal settler vessel with a small disengaging stack on the top. The combined rich amine stream from the upstream units flows to the

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Rich Amine Flash Drum where any liquid hydrocarbon is separated from the rich amine. An inlet distributor is provided to avoid excess inlet turbulence and promote an even flow distribution through the vessel. It consists of a single pipe arranged vertically through nearly the full width of the vessel diameter with one full length slot facing the nearest vessel partition. Liquid hydrocarbon is separated into a reservoir in the vessel and can be periodically pumped to the Light Slop Oil Tank. Hydrocarbon vapor separated in the Rich Amine Flash Drum, which contain H2S, is scrubbed with a small lean amine slipstream in the stack portion. The stack is packed with 25 mm diameter carbon Raschig rings for contact and the lean amine enters through a distributor located at the top end of the stack. Rich amine from the bottom of the Rich Amine flash Drum is pumped to the Amine Regenerator for regeneration. Amine Regenerator Receiver ( 810-V6 ) The Amine Regenerator Receiver is a vertical vessel that is made up of KCS. It is provided to separate the partially condensed ( two-phase ) stream from the Amine Regenerator condenser. The stream enters the vessel through a distributor located less than a meter below the mesh blanket. The vessel is provided with a thick mesh blanket to remove any entrained liquid from the acid gas stream. The liquid water from the receiver is pumped as reflux to the top tray of the Amine Regenerator. The acid gas flows on back-pressure control to the Sulfur Recovery Unit. Lean Amine Carbon Filter ( 810-V7 ) The Lean Amine Carbon Filter is a vertical vessel ( made up of KCS ) filled with granular carbon to a height of 2100 mm from bottom tangent line. The Carbon Filter is provided to remove chemical impurities from the slipstream of cooled lean amine. The regenerated lean amine solution enters the vessel through a 4” distributor at the top end of the vessel and flows downwards through the carbon bed, removing the impurities. The product stream goes out from the bottom of the vessel and sent to the final filtration system. The vessel is designed for both vacuum and liquid-full conditions. Amine Sump Tank ( 810-V8 ) An underground sump tank is provided to be the end destination ( final storage ) of lean/rich amine solutions discharged from the unit during normal operation, emergency situations and unit shutdown. The vessel will be made mainly from KCS and to be provided with 6 mm corrosion allowance. The indicated vessel and associated piping will be below grade. The vessel is provided with a dedicated pump for transferring amine solution to the Rich Amine Flash Drum. Fuel Gas Amine Absorber Interface Pot ( 810-V9 ) The Fuel Gas Amine Absorber Interface Pot is provided for hydrocarbon skimming and amine drainage to the Amine Sump Tank. The Interface Pot is a small vertical vessel made from KCS. The vessel is attached to the bottom-side of the Fuel Gas Amine Absorber to remove liquid hydrocarbon accumulating from the Absorber.

The vessel is supplied with stripping steam to vaporize the skimmed hydrocarbons from the Amine Absorber. Hydrocarbon vapor is sent to the acid gas flare from the top of the vessel and the rich amine solution drained to the Amine Sump Tank. Reactor summary Not applicable to this unit. Fired heater summary Not applicable to this unit. Exchanger summary Amine Regenerator Reboilers ( 810-E2A/B ) The Amine Regenerator Reboilers are tubular heat exchangers provided to supply heat to the Amine Regenerator. LP steam goes through the tube side while the lean amine is vaporized on the shell side. The two horizontal reboilers arranged in parallel are of BJU type heat exchangers with its shell and cover constructed with KCS and the tubes and other internals with Stainless Steel ( SS ). Both the shell side and tube side of the exchangers will be provided with insulation. Rich/Lean Amine Exchanger ( 810-E3 ) The Rich/Lean Amine Exchanger is a horizontal, AES type tubular heat exchanger which is provided for heat recovery purposes. The rich DEA solution from the Rich Amine Flash Drum, before entering the Amine Regenerator, is heated as it passes through the SS tube side of the exchanger while the lean DEA solution from the Regenerator bottom is cooled down on the KCS shell side. Lean Amine Trim Cooler ( 810-E9 ) The Lean Amine Trim Cooler is provided to give the necessary cooling to the lean amine solution prior to entering the Amine Absorber. This horizontal exchanger will be of type AES and will be constructed with KCS. Cooling water will be passed through the tube side and the lean amine to the shell side. Amine Regenerator Condenser ( 810-EA1 ) The Amine Regenerator Condenser is an air cooled exchanger used for cooling the overhead vapor of the Amine Regenerator from 107 oC to 61 oC. This condenser will be constructed with KCS with 5.0 mm corrosion allowance on the headers. Post-weld heat treatment is required. Fans in the air bay shall be the standard type ( SP ) where blade pitch can be adjusted manually when fan is stopped. Lean Amine Cooler ( 810-EA2 ) The Lean Amine Cooler is an air cooled exchanger provided for cooling the lean amine solution from the Amine Regenerator from 101 oC to 61 oC. This air fan cooler will be constructed with KCS and to be post-weld heat treated. One half of fans in the air bay shall be auto-variable ( AV ) type where the blade pitch is automatically adjusted to

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desired angle by manual adjustment of a remote control knob into a pneumatically actuated relay system. Remaining fan(s) shall be the standard type ( SP ) where blade pitch can be adjusted manually when fan is stopped. Pump summary Rich Amine Flash Drum Slop Oil Pumps ( 810-P1A/B ) The Rich Amine Flash Drum Slop Oil Pump is provided to periodically transfer the accumulated slop oil from the Flash Drum to the light slop oil tank at the Tankage and Blending System. The Slop Oil Pumps will be centrifugal type pumps and will be constructed with S-5 class steel. Rich Amine Pumps ( 810-P2A/B ) The Rich Amine Pump is provided to transfer the rich amine solution from the Rich Amine Flash Drum to the Amine Regenerator via the Rich/Lean Amine Exchanger. These rich amine pumps are of a centrifugal type and will be constructed with S-5 class steel. Casing to be post-weld heat treated. Lean Amine Pumps ( 810-P3A/B ) The Lean Amine Pump is provided to transfer the regenerated lean amine solution from the Amine Regenerator via the Rich/Lean Amine Exchanger to the lean amine users ( absorbers ). These lean amine pumps are of a centrifugal type and will be constructed with S-5 class steel. Casing to be post-weld heat treated. Amine Sump Pumps ( 810-P5A/B ) The Amine Sump Pump is provided to transfer intermittently the accumulated amine solution from the Amine Sump Tank to the Rich Amine Flash Drum. These pumps are mounted on the tank and they are of a centrifugal type . These pumps are constructed with steel. Amine Transfer Pumps ( 810-P6A/B ) The Amine Transfer Pump is provided to transfer the fresh lean amine solution from the Amine Storage Tank to the lean amine users ( absorbers ). These transfer pumps are of a centrifugal type and will be constructed with S-5 class steel. Casing to be post-weld heat treated. Compressor summary Not applicable to this unit. Special equipment summary Not applicable to this unit. List of Insruments Instruments provided for this unit are listed in “Instrument Schedule for Amine Treating Process Unit, Document No.: S-810-1370-101”.

Summary of all equipment’s drivers Refer to Attachment 8.1( Equipment List ) Control valves The following table is a summary of failure action of CVs and Uvs. Tag No.

Service

Failure

P&ID No.

Action 810-FV-016

Lean Amine to F.G. Amine Absorber

Fail Close

D-810-1225-113

810-PV-002

Treated Fuel gas from Amine Absorber

Fail Close

D-810-1225-113

810-LV-007

Rich Amine from F. G. Amine Absorber

Fail Close

D-810-1225-113

810-PV-008

Rich Amine to Rich Amine Flash Drum

Fail Open

D-810-1225-114

810-FV-017

Lean Amine to Rich Amine Flash Drum

Fail Close

D-810-1225-114

810-PDV-014

Lean Amine Bypassing Filters

Fail Open

D-810-1225-116

810-PCV-026

F.G. Purge to Amine Sump Tank Vent line

NA

D-810-1225-117

810-LV-010

Rich Amine to Amine Regenerator

Fail Close

D-810-1225-119

810-FV-029/30

Steam Injection to Amine Regenerator

Fail Close

D-810-1225-119

810-FV-031/32

Condensate from A. Regenerator Reboilers

Fail Close

D-810-1225-119

810-TV-027

Boiler Feed Water to Desuperheater

Fail Close

D-810-1225-119

810-FV-039

Amine Regenerator Reflux

Fail Open

D-810-1225-120

810-PV-043A

A. Regenerator Receiver gas to Sulfur Plant

Fail Close

D-810-1225-120

810-PV-043B

Regenerator Receiver gas to Relief Header

Fail Open

D-810-1225-120

Fired heaters Not applicable to this unit. Miscellaneous Refer to the Attachment 8.1.

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Flow Plans and Plot Plan PFD, MSD and P&IDs Refer to the following attachments: Attachment 9.1 Process Flow Diagram ( D-810-1223-101 ) Attachment 9.2 Material Selection Diagram ( D-810-1223-501) Attachment 9.3 Piping and Instrument Diagram (D-810-1225-101,102,103, D-810-1225-111,113 ~120, 130 ~ 134 ) Design Engineering, utility and safety flow plans Refer to the following attachments: Attachment 9.4 Piping and Instrument Diagram ( UFD )( D-801-1225-131 ~ 136 ) Attachment 9.5 Area Classification ( D-810-1380-001 ) Attachment 9.6 Fire Protection System Layout for Process Area ( D-926-1225-003 ) Attachment 9.7 Fire Extinguisher Layout for Process and Utility Area ( D-926-1225011 ) Attachment 9.8 Arrangement of Gas Detectors for Process Area ( D-926-1225-023 ) Attachment 9.9 Arrangement of Fire Alarm System Equipment for Whole Refinery Area ( D-926-1225-021 ) Attachment 9.10 Layout for Whole Fire Protection System ( D-926-1225-002 ) Plot Plan Refer to Attachment 9.11

Plot Plan of KMX/LMX/Amine Units ( D-810-1225-001 )

Safety Shutdown function charts Refer to Attachment 9.12

Cause and Effect Chart

( S-810-1371-401 )

Safety To prevent accidents it is of the utmost importance that all personnel be instructed properly of the following subject; The leaks and responsibilities of the operators The methods to accomplish this in a safe manner. The following safety regulation cover operations of particular concern to the personnel responsible for the Amine Treating Process Unit. They are intended to supplement any existing general refinery safety regulations which cover all units; reference should be made to the latter for all points not mentioned below;. Mechanical craftsmen working on his unit will be governed by their own departmental safety regulations, but the operator should see that none of the following safety regulations are violated by mechanical workers. In addition to specifically defined rules and practices, the exercise of good judgment by every person involved is essential to safe operation by every person involved is essential to safe operation. An operator should be alert for any situation which might present a personnel hazard. It should also be the responsibility of each person familiar with the plant to warn other workers who enter the plant of possible hazards they could encounter. All personnel must know the location and use of safely shower, fire extinguisher, plant fire alarm, and main isolation valves, fire hoses and hydrants, fire blankets, gas masks and respirators, and other protective equipment such as hard hats, rubber gloves, etc. Soda acid or foam type extinguisher must not be used on fire around electrical equipment because the water solution will conduct electricity and may aggravate the difficulty or result in the electrocution of personnel. Carbon dioxide or dry powder extinguisher may be used safely on electrical fires. The carbon tetrachloride extinguishers liberate poisonous fumes and should not be used in a confined space, unless precautions are taken to avoid breathing the vapors. Gas masks or breathing apparatus must be worn whenever toxic fumes are encountered. Safety hats must be worn when outdoors. Gloves and goggles or face shields should be worn where toxic or hot vapor or liquid is encountered, and are recommended for use while samples are being withdrawn and solutions made up. Fire extinguishers must be recharged immediately after use. All steam and water hose equipment must be put back in place after use. Access to such equipment must not be obstructed. Gas masks must have fresh cartridges installed after use. Emergency fire plan The fire protection system of the plant is designed to prevent fire occurrence, control fire escalation, or extinguish fire within short period of time, assuming there will be no outside fire fighting assistance, with only one major fire at a time. Fire fighting and protective equipment There are five water hydrants with monitors and live hose reels in the process area. Suitable fire extinguisher must be readily available. The area around an extinguisher or hydrant must be clear so that equipment is readily accessible in case of emergency. For details, see the relevant drawing for the fire fighting system. In case of fire in the process facility, there is a chance that vessels or drums will fall down because of overheating of the supports. The fire fighting should be done from the windward.

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In order to prevent the spread of fire, it is necessary to cool down near equipment using the fire water system, special equipment for fire fighting and also fire fighting trucks. If the process unit is in operation, it is necessary to shut down the unit. DO NOT EVACUATE or VENT any hydrocarbon to atmosphere. Refer to “ FIRE PROTECTION SYSTEM LAYOUT FOR PROCESS AREA“, D926-1225-003 ( Attachment 9.6) for details. Fire alarm system Refer to “ARRANGEMENT OF FIRE ALARM SYSTEM EQUIPMENT FOR WHOLE REFINERY AREA “, D-926-1225-021 ( Attachment 9.9). Also, Refer to “FIRE EXTINGUISHER LAYOUT FOR PROCESS & UTILITY AREA “, D-926-1225-011 ( Attachment 9.7 ). Fixed Water Monitors Provision for fixed water monitors shall be per “ LAYOUT FOR WHOLE FIRE PROTECTION SYSTEM”, D-926-1225-002 ( Attachment 9.10 ). Fixed water monitors have an effective nozzle range of at least 30 m and a discharge capacity of 1900 liter per minutes. Monitors are arranged so that any equipment to be protected may be covered by two fixed monitors with a radius of at least 30m. Monitors are located approximately 15 m from the equipment being protected. Fire Hydrants The maximum distance between fire hydrants serving the process units shall be 50 meters or less as determined by the equipment served. Live Hose Reel Stations Heavy duty hose reels having 40 meters of 32 mm hard booster hose equipped with 38 mm couplings and contain straight stream/fog nozzle, shall be provided as means for quick water application by one man. Fire Protection Refer to “LAYOUT FOR WHOLE FIRE PROTECTION SYSTEM”, D-926-1225002 ( Attachment 9.10) for details. Structure steel, Pipe racks, Equipment Supports, main supports of heater are fireproofed. ( Refer to S-000-13B0-001. ) The following are precautions to avoid fire: 1. Leaking flanges, glands, or broken gauge glasses can release any hydrocarbon gas or liquid to the area, creating a fire hazard. All equipment should be tested for leaks before start-up. 2. All systems are to be purged to give a non-explosive atmosphere. 3. Trash and rubbish are a fire and stumbling hazard. Pick it up, an operator should be proud of a clean unit. 4. Overheating vessels by steam may cause damage to the internal assembly. 5. Spilled oil or chemicals around units or in trenches should be cleaned up at once. 6. Smoking in the process area can cause fires and explosions. Smoke only in designated areas. 7. Welding or other work which can cause sparks in the process area can cause fires and explosions. Make the area safe for such work and obtain the necessary permit from the proper authorities before commencing work.

Maintenance of equipment and housekeeping 1.

2. 3. 4. 5. 6. 7. 8.

9.

Operating equipment should be checked frequently for signs of leakage, overheating, or corrosion, so that unsafe conditions may be corrected before they result in serious consequences. Unusual conditions should be reported at once. Guard around moving shafts, coupling belts, etc., which have been removed for repairs of the equipment must be replaced when repair work is completed. Tools, pieces of pipe etc., should never be left lying on platforms or railings of operation equipment where they can be knocked off and injure someone below. Access to ladders and fire escapes must be kept clear. Waste material and refuse must be put in proper locations where they will not offer fire or stumbling hazards. Liquid spills must be cleaned up immediately. Blanket gas leaks with steam and immediately report leaks for repair. In the event that electrical equipment does not function properly, notify the electrical department and stay clear of the equipment until the electrician arrives. Gas cylinders should be stored so that they cannot fall over. Guard caps must remain in place over the valves of cylinders which are not in use. Care should be taken when installing scaffolding to ensure that the wooden boards do not contact hot equipment and that no part is allowed to impair free access on operational equipment e.g. ladders, stairways, walkways or valves. Scaffolding should be removed immediately on completion of the work in hand. Switch pumps regularly when spares are provided. This will assure start the spare pump will be ready when needed.

Repair work 1. 2. 3. 4.

5. 6. 7. 8. 9.

Mechanical work around and operating unit must be kept to a minimum, and the minimum number of men should be used. No mechanical work on the equipment is to be done without a properly authorized work permit. Safety hats must be worn by all personnel in all areas at all times. No burning, welding, open fires, or other hot work shall be allowed in the area unless authorized by a work permit. Catch basins, manholes, and other sewer connections must be properly sealed off to prevent the leakage of gases which may ignite upon contact with an open flame. No personnel shall enter a vessel for any purpose whatsoever until it has been adequately purged, blanked off, then tested to ensure freedom from noxious or inflammable gases and an entry permit issued. When flushing equipment with a fire hose, the fire hose must be equipped with a check valve to prevent backflow into the fire main. Lines operation at a low temperature might fracture if unduly stressed; therefore, do not physically strike these lines and avoid operation conditions which would cause a water hammer to start. Do not use light distillates such as gasoline or naphtha to clean machinery or for any other cleaning purposes. Equipment should not be left open overnight. At the end of each day’s work blanks or spades should be installed to prevent entry of flammable materials due to valve let-by.

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10. Welding cylinders should be removed from site to a designate safe area at the end of each working day.

Thermal expansion in exchangers Because of serious accidents caused by thermal expansion of liquid trapped in exchangers the following procedures is outlined in an effort to eliminate this hazard. 1. When the cooler side of an exchanger is to be bypassed while hot material is passing through the other side, the drain or vent should be checked before bypassing to see that it is not plugged. 2. When the exchanger is bypassed, the bleeder or vent should be arranged so that the pressure can be dissipated to a suitable place. 3. Warning signs as follows should be installed on all exchangers where it is possible to block in the cold side of an exchanger with hot liquid going through the other side. Withdrawal of samples Samples shall be withdrawn from the unit only by authorized personnel. Protective equipment, face masks or goggles, and suitable gloves must be worn for sampling liquids or solids. A container must never be filled to the brim, in order to minimize risk of subsequent spillage. When sampling any product liquids, gloves and goggles will be worn. When sampling any material, gas or liquid, the sampling line must be flushed long enough to remove dormant materials to insure that the sample obtained represents the current stream. Pass enough gas through the sample vessel to insure the displacement of the purge gas and to adjust the temperature of the sampler to that the composition is not distorted by condensation or flashing, etc. When the sample composition is representative of the source material, undistorted by flash vaporization. Certain classes of samples may require inert atmospheres , cooling or special carrying devices. Wear approved personal safety equipment and exercise caution to avoid injuries. Safe handling of volatile and toxic materials including catalyst The safety rules given below are for the protection of life and limb, and the prevention of property loss. It is expected that refinery people will exercise common sense, alertness, and good judgment in carrying them out. If ever there is any doubt as to the safety aspect of a particular operation, consult your supervisor immediately. Respiratory Protection Refer to Attachment 9.8 “ ARRANGEMENT OF GAS DETECTORS FOR PROCESS AREA” ( D-926-1225-023 ). Most refinery gases, other than air, are harmful to human beings if inhaled in sufficient concentration. Toxic gases may be classified as either asphyxiating or irritating. Asphyxiating gases may cause death by replacing the air in the lungs or by reaction with the oxygen carried in the blood; examples are hydrogen sulfide carbon monoxide, and smoke. Irritating gases may cause injury or death not only by asphyxiating but also by burns internal and external/ examples are chlorine and sulfur dioxide. To guard against the inhalation of harmful gases:  Secure a gas test certificate showing the gas condition of the vessel is safe for entry.

  

Stand on the windward side of an operating from which gases escape. Provide proper ventilation. All personnel should become familiar with the accepted method of artificial respiration in order to render assistance to any one overcome by gas, electric shock, or drowning. If anyone is overcome by gas, his rescuer should:  Never attempt a rescue unless an assistant is standing by.  Protect himself before attempting a rescue by wearing breathing apparatus.  Get the victim to fresh air as soon as possible.  Give artificial respiration and send his assistant to call for medical aid. When using a breathing apparatus, be sure that the mask fits the face properly. Test it by the approved test method. Wear the correct type of breathing apparatus, suited to the situation encountered. Breathing Apparatus ( B. A. ) There are four types of breathing apparatus in general refinery service. They are the canister type mask, the fresh air hose line B. A., the compressed air self-contained B. A. and the compressed air line trolley B. A. 1. The canister type mask utilizes a filter element to absorb the poisonous gas from the air and is used only by personnel working at the TEL/TML building off/on loading. Use this mask only in the open air or where the gas concentration is less than 2%, not in a tank or other confined space. A canister type mask does not protect the user against a deficiency of oxygen. A lifeline should be used in questionable locations. When a seal is removed from a canister, mark the date on the canister, and after one year discard it regardless of how little it has been used. A record of the amount of time that the canister has been used must be kept on a tag attached to the canister. Do not exceed the permissible time limit for the particular canister being used. Inform Safety Department when time limit is near. 2. The fresh air hose line breathing apparatus has a length of air hose though which the wearer draws in the air required for respiration. When a man must enter a tank, sewer, or other confined area where the atmosphere is 20% or more of the lower explosive limit, or contains evidence of hydrogen sulfide or other toxic materials, a fresh air breathing apparatus must be used. It is to be used subject to the following conditions:  The free end of the air hose line must be placed where only fresh air can enter it, but not more than 100 meter of hose should be used.  A life belt and rope should always be used with the end fixed so that it will not fall back into the tank or sewer.  Be sure that the harness is buckled close to the wearer’s body so that it will not slip over his shoulders if a rope rescue is necessary. 1. The compressed air self contained breathing apparatus has a self-contained air supply carried on the back of the user. It is one of two of the four types that is completely independent of outside air. It is used principally in emergencies. After use, always notify the proper department so that they can recharge the cylinders as soon as possible.

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Compressed air line trolley breathing apparatus. This breathing apparatus is also completely independent of outside air. It is principally used where the fresh air line breathing apparatus would be unsuitable.

Poisonous Material A matter of utmost concern for all operating personnel is the presence of H2S in streams. Refer to “ ARRANGEMENT OF GAS DETECTORS FOR PROCESS AREA” ( D926-1225-023). Hydrogen Sulfide (H2S) H2S is a colorless gas slightly heavier than air (it accumulates in low spots- be aware!). It is highly flammable and a dangerous fire risk. Hydrogen sulfide is an explosive gas which will explode in concentrations of 4.3% (3.4% at 149 ℃) to 45% by volume in air. Hydrogen sulfide explosions are most likely to occur in the vapor space over liquid sulfur, because as liquid sulfur is cooled or agitated, it evolves H2S into vapor space above it. Such vapor exists above the liquid sulfur in the sulfur pit, which must be swept with air to prevent a buildup of H2S to explosive. H2S is easily identified in very low, non-fatal concentrations (0.13 ppm) by the strong pungent odor of rotten eggs. However, since H2S deadens your sense of smell, do not rely on its odor to warn you of its presence in lethal concentrations. Note H2S is extremely poisonous, (more poisonous than the hydrogen cyanide gas used in the “gas chambers”) and breathing any concentration must be avoided. Symptoms of poisoning vary with the concentration and length of exposure. H2S is present in the feed from the fractionator overhead system and in many lines and vessels in the plant. Note H2S leaks should never be approached without self contained breathing gear and a stand-by man in position with breathing gear. H2S monitors have been provided to detect H2S leaks in particular areas of moderate to high concentrations. Become familiar with the location of this safety equipment and its operation. Precautions to Avoid Danger from Hydrogen Sulfide Gas Working in any concentration of hydrogen sulfide is not desirable. Where necessary, work can be done for an eight hour period in a concentration up to 10ppm (0.001%) by volume in a air, providing continual checks are made by a qualified gas tester using an approved H2S Gas Detector. Under no circumstances should anyone work in concentration greater than 10 ppm without proper respiratory equipment and approval of a supervisor. Because of the dangerous from the release of hydrogen sulfide gas, the following precautions must be strictly observed: Do not work or permit anyone to work in an area suspected of containing a concentration of hydrogen sulfide gas without first having the area tested by a qualified gas tester, using an approved H2S detector. Report at once any leakage of gas or any gaseous areas as soon as discovered. Keep out of gaseous areas and keep others out. Stay on the windward side of the area as long as the condition exists.

When necessary to vent equipment containing hydrogen sulfide or hydrogen sulfide bearing material, use a vent or relief system, if provided. Avoid venting this gas directly to the atmosphere. Maintain adequate ventilation of any enclosed space where leakage of gases might occur. If it should be necessary in an emergency to enter and area where there is any possibility of hydrogen sulfide gas being present, particularly in enclosed locations where the gas could accumulate, use a Scott Air-Pak. Have a man standing by in a safe location equipped with a breathing apparatus and, if necessary, use a life line. Principles for Emergency Action If any emergency situation develops due to escaping hydrogen sulfide gas, observe the following principles for safety: First get out and warn all others to stay clear of the hazardous areas. Do not attempt to rescue anyone unless you are wearing breathing gear. Your first duty is to summon help before attempting a rescue. Do not, under any circumstances, try to determine the concentration of hydrogen sulfide as by it’s odor. If it’s presence is suspected, have the location tested with an approved Hydrogen Sulfide Gas Detector. In case a man is over come, summon help, get him into the fresh air at once, and begin artificial respiration, using an inhalator if available. Summon a doctor as soon as possible. But do not stop artificial respiration. Any person overcome by gas must be kept warm, even during artificial respiration. Use anything available which may be suitable for this purpose, such as emergency blankets, coats etc. When the patient has recovered and can be safely moved, he must be set to the hospital by ambulance and never allowed to stand until released by the doctor.

Nitrogen N2 is an inert gas used for purging equipment or maintaining a positive pressure inert gas blanket on a vessel. N2 is neither poisonous nor flammable, but care must be exercised when working inside equipment that has beenN2 purged. Adequate ventilation must be provided and appropriate breathing devices worn. To breathe an atmosphere high in N2, could result in suffocation. Before entering vessels that have been purged with N2, a check must be made for proper oxygen content prior to entry. Rapid vaporization of liquid nitrogen can cause severe burns on contact with the skin.

Ammonia Ammonia is a colorless gas with an extremely pungent odor May cause varying degrees of irritation to the eyes, skin, or mucous membranes. Refer to MSDA Sheets for the above materials for more detailed information. Sodium Hydroxide ( NaOH Caustic Soda ) Refer to the appropriate safety bulletin published by the National Safety Council or the Manufacturing Chemists’ Association. Caustic solution, commonly called lye, and technically known as sodium hydroxide, is used so widely in petroleum refining, that its potential hazards are often carelessly overlooked. Certain general precautions should be observed.

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Goggles or face shields should be worn at all times in the processing area. Painful injury and possible blindness can result if caustic reaches the eyes. A bubbler fountain should be provided for the purpose of washing the eyes if an accident should occur. Boric acid solution should be available for first aid after washing the injured eye with copious quantities of water. All eye injury cases, even slight, should be referred to a physician. Workmen should be impressed that caustic does not give immediate warning of its presence on the skin by burning or irritation, as in the case of many other chemicals. A severe burn can result from caustic before the individual realizes its presence on the skin. However, the presence of caustic on the skin before burning sensation develops can be recognized by its slippery and soapy feeling. A physician should be consulted in case of a severe skin burn. Some refiners keep a tub of diluted vinegar handy to neutralize caustic on tools, rubber gloves, etc., after washing in water. In view of the foregoing, workmen should be instructed to wear, in addition to face shields or goggles, rubber gloves and rubber aprons when performing any work which exposes them to caustic. Depending upon conditions, it may be advisable to wear protective rubber footwear, as caustic is destructive to leather. Incidentally, cotton material is more resistant to caustic than wool, and therefore is preferable for clothing. Although it should not be considered as a protective material. When caustic has come into contact with the skin, the area should be immediately flushed with water for several minutes, and depending upon the severity of the exposure, this an be followed by a two percent acetic acid wash to neutralize any last traces of caustic. Facilities for quick action in the matter of water washing should be available. A treadle operated safety shower equipped with a quick opening valve should be installed in the area. In cold seasons provisions should , of course, be made to supply with warm water. Preparing for entering process equipment Anyone entering a vessel which may contain an inert or contaminated atmosphere must follow safety precautions and rules which apply. The vessels may contain H2s or other toxic material in addition to hydrocarbons. Therefore, the following precautions should be included in the standard procedure. The vessels should be isolated by positive action, such as blinding, to exclude all sources of hydrocarbon, fuel gas, steam, air, etc. the refinery safety officer and supervisory personnel will give their permission for vessel entry after they have made the appropriate tests. Install an air mover outside the vessel to sweep away any vapors. The man entering the vessel must be equipped with a fresh air mask in proper working condition, with a fresh air supply. There should be available and ready for immediate use and transfer to the man in the vessel, a separate air supply which is independent of electrical power. The man entering the vessel should wear a safety harness with properly attached safety line. If the work involves a large distance above the floor of the vessel, scaffolding or support flooring must be built to prevent dangerous falls. There should be a spare fresh air mask complete with its own separate air supply, to allow a second man to enter the equipment quickly in case of an emergency. This spare equipment must e compact enough to allow the second man to enter through the manway while entering the equipment. The API publication “Guide for Inspection of Refinery Equipment” or the NIOSH publication No. 87-113; “A Guide to Safety in Confined Spaces” can be referred to for

additional information on safety procedures for vessel entry and accident prevention measures. Opening equipment Every line connecting to a nozzle on the vessel to be entered must be blinded at the vessel. This includes drains connecting to a closed sewer, utility connections and all process lines. The location of each blind should be marked on a master piping and instrumentation diagram ( P&ID ), each blind should be tagged with a number and a list of all blinds and their locations should be maintained. One person should be given responsibility for the all blinds in the unit to avoid errors. The area around the vessel manways should also be surveyed for possible sources of dangerous gases which might enter the vessel while the person is inside. Examples include acetylene cylinders for welding and process vent or drain connections in the same or adjoining units. Any hazards found in the survey should be isolated or removed. Safe access must be provided both to the exterior and interior of the vessel to be entered. The exterior access should be a solid, permanent ladder and platform or scaffolding strong enough to support the people and equipment who will be involved in the work to be performed. Access to the interior should also be strong and solid. Scaffolding is preferred when the vessel is large enough to permit it to be used. The scaffolding base should rest firmly on the bottom of the vessel and be solidly anchored. If the scaffolding is tall, the scaffolding should be supported in several places to prevent sway. The platform boards should be sturdy and capable of supporting several people and equipment at the same time and also be firmly fastened down. Rungs should be provided on the scaffolding spaced at a comfortable distance for climbing on the structure. If scaffolding will not fit in the vessel a ladder can be used. A rigid ladder is always preferred over a rope ladder and is essential to avoid fatigue during lengthy periods of work inside a vessel. The bottom and top of the ladder should be solidly anchored. If additional support is available, then the ladder should also be anchored at intermediate locations. When possible, a solid support should pass through the ladder under a rung, thereby providing support for the entire weight should the bottom support fail. Only one person at a time should be allowed on the ladder. When a rope ladder is used, the ropes should be thoroughly inspected prior to each new job. All rungs should be tested for strength, whether they be made of metal or wood. Each rope must be individually secured to an immovable support. If possible, a solid support should pass through the ladder so that a rung can help support the weight and the bottom of the ladder should be fastened to a support to prevent the ladder from swinging. As with the rigid ladder, only one person should climb the ladder at a time. Working in columns or vessels It is recommended that any man working in a vessel which has an inert or contaminated atmosphere not be permitted to move too far away or into any tight areas, such as through a fractionator tray manway. The reason for this precaution is that should the man develop some difficulty while below a tray, for example, to a point where he could not function properly or lost consciousness, it would be extremely difficult for the surveillance team outside the vessel to pull the man up through the small tray manway by use of the safety line. Any one working in the bottom of the column or vessel should be aware of the hazard of falling objects. Hard hats should be worn , but these will not provide total protection against heavy objects. The workmen should be warned to pay attention, to look, and

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listen. The maintenance supervisor should be careful when scheduling work, to avoid having people in the bottom of the vessel when there is heavy work going on in the top of the column or vessels. A communication system should be provided for the manway watch so that they can quickly call for help in the event that the personnel inside the vessel encounter difficulty. A radio, telephone, or public address system is necessary for that purpose. Entering tanks, drums or other vessels Before entering a vessel, the refinery’s safety precautions should be observed. These usually include the following: sampling the vessel for toxic vapors and oxygen concentration, wearing a safety harness, and having an attendant outside the vessel. An unattended vessel should never be entered Procedure for removing safety valves Before removing the safety valve, it is required to confirm that both side of isolation valve are blocked and depressured safely. It is also required to confirm that the set pressure of spare safety valve is properly adjusted on the testing facility in warehouse and block valve of both inlet and outlet line in field are car-sealed-open. Work permit procedure and work permit formats Before entering the vessel, a vessel entry permit must be obtained. A vessel entry permit insures that all responsible parties know that work is being conducted inside of a vessel and establishes a safe preparation procedure to follow in order to prevent mistakes which could result in an accident The permit is typically issued by the safety engineer or by the shift supervisor. The permit should be based on a safety checklist to be completed before it is issued. The permit should also requires the signatures of the safety engineer, the shift supervisor, and the person that performed the oxygen toxic and explosive gas check on the vessel atmosphere. Four copies of the permit should be provided. One copy goes to the safety engineer, one to the shift supervisor, one to the control room, and one copy should be posted prominently on the manway through which the personnel will enter the vessel. The permit should be renewed before each shift and all copies of the permit should be returned to the safety engineer when the work is complete. Additional requirements or procedures may be imposed by the refiner, but the foregoing is considered the minimum acceptable for good safety practice.

Operation notes relating to HAZOP review Refer to “HAZOP STUDY REPORT”, S-810-1220-101 and “HAZOP ACTION FOLLOW-UP LIST”, S-810-1220-102. Action

Recommendation

No. R-22

Oper. Manual Section No.

Operating procedure will highlight that this line must not be

3 and 6.9

opened during normal operation and must be opened only when the liquid is cooled down below 60 ℃ during shut down operation. Material safety data sheet(MSDS) of all the chemicals, catalysts Refer to the Attachment 10.1.(later on)

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Miscellaneous Conversion tables

English - Metric Conversions and Abbreviations

length area volume

English Unit

Abbrev.

Multiplied By .

inch foot

in ft

25.4 304.8

millimeter millimeter

mm mm

square foot

ft2

0.09290

square meter

m2

cubic foot standard cubic feet of gas* gallon barrel

ft3 SCF

0.02832 0.02826

m3 std m3

gal bbl

0.003785 0.1590

cubic meter standard cubic meters of gas cubic meter cubic meter

temperaturedegrees Fahrenheit OF

Metric Unit

Abbrev.

O

C=5/9(OF-32) degrees Celcius

m3 m3 O

C

pressurepound per square inch psi inch of mercury at 32ºF in Hg inch of water at 4ºC in H2O pound per square inch psi

6.895 0.1333 0.2491 0.07030

kilopascal kilopascal kilopascal kilograms per square centimeter

kPa kPa kPa kg/cm2

mass

lb or lbm

0.4536

kilogram

kg

Btu

1.055

kiloJoule

kJ

hp Btu/hr

0.746 0.2931

kilowatt watt

kW W

pound mass

energyBritish Thermal Unit power

horsepower British Thermal Units per hour

*UOP calculates standard cubic feet of gas at 60º F and 14.696 psia. UOP proposes to calculate standard cubic meters of gas at 15º C and 101.325 kPa. General pre-start up procedures Refer to S-xxx-xxxx-xxx.(Hold) Overall start-up and shutdown outlines Refer to S-xxx-xxxx-xxx.(Hold) Offsite systems There is no interconnection between the amine treating section and the offsite system.

Catalyst and chemical loading / unloading Preparation of Amine Solution Amine will be supplied to the Amine Treating Unit in bulk quantity as 85 wt % DEA at the Amine Make-up Tank ( 810-TK1 ). The amine will be diluted to a 20 wt% DEA solution in the Amine Storage Tank ( 810-TK2 ) using Cold Condensate as the water source. 1. For the initial fill, an estimated quantity of 205 m3 of 20 wt% DEA solution will be required. This includes the volume requirement for all three absorbers at Amine Treating Unit, LPG Merox Unit, DieselMax Unit, one Rich Amine Flash Drum ( 810-V4 ), and one Amine Regenerator ( 810-V5 ). The 205 m3 volume is equivalent to 39 m3 ( 41,410 kg ) pure DEA plus 166 m3 ( 165,640 kg ) Cold Condensate. It is anticipated that the unit will start up in phases and that the entire initial fill will not be required at one time. 2. Prior to the preparation of the amine solution, clean the Amine Make-up Tank ( 810-TK1 ), Amine Storage Tank ( 810-TK2 ) and associated piping. Load the concentrated amine to the Amine Make-up Tank. 3. Charge Cold Condensate into the Amine Storage Tank up to the required liquid level. Line up the Amine Transfer Pump from the Amine Make-up Tank to the Amine Storage Tank. 4. And then start the Amine Transfer Pump ( 810-P6A ) for the transfer of the required concentrated amine. Commission the N2 blanket system of the Amine Storage Tank because air degrades the amine solution. 5. Make circulation of the amine solution stored in the Amine Storage Tank by using the circulation loop provided for the tank via the Amine Transfer Pump to homogenize the solution. 6. Analyze the amine content of the circulating solution and adjust the concentration to the required concentration. Catalyst and chemicals requirements Refer to the Attachment 1.2. Analytical Plan Refer to the operating manual for Laboratory regarding procedures to operate laboratory equipment and special precautions to chemicals, S-000-1230-xxx (Later). Recommended sampling requirements are provided in the table below. Test frequency shown is a rough figure and will be optimized with experience in plant operation. (1O Feed Sour Gas to Fuel Gas Amine Absorber (810-SN1) Item

Test Method

Normal

Start-up

Composition GLC As req.(1) As req.(1) H2S Detector tube or UOP 212 As req.(1) As req.(1) CO2 Deleted (2) Note(1) This stream is the same as sponge absorber lean off gas in unit 411. A sample will be normally taken from 411-SN5. Note(2) CO2 does not exist. (2O Treated sweet gas from Fuel Gas Amine Absorber (810-SN2)

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Item

Test Method

Normal

Start-up

H2S

Detector tube or UOP 212

1/D

1/D

(3O Rich Amine from Fuel Gas Amine Absorber(810-SN3) Item

Test Method

Normal

Start-up

Apparent H2S

UOP 827

As req.

As req.

Normal

Start-up

1/D 1/D 1/W 1/W

1/D 1/D 1/W 1/W

1/D As req.

1/D As req.

(4O Rich Amine from Rich Amine Flash Drum(810-SN4) Normally no test is required. (5O (6O Leqn Amine to Absorbers (810-SN5) Item

Test Method

Diethanolamine UOP 824 Apparent H2S UOP 827 Thiosulfate UOP 818 Total Amine UOP 828 Carbon Dioxide Deleted (1) Appearence Visual Foam Test See this manual Note (1) CO2 does not exist. (7O Lean Amine from Lean Amine Sock Filters(810-SN6) (8O Normally no test is required.

(9O Rich Amine from Fuel Gas Amine Absorber Interface Pot(810-SN7) (10O Normally no test is required. (11OSlop Oil from Rich Amine Flash Drum (810-SN8) Normally no test is required. (12OReflux water from Amine Regenerator Reflux Pumps (810-SN9) Normally no test is required. (13OAcid Gas to SRU (810-SN10) Item

Test Method

H2S CO2 Hydrocarbons Note(1) highly Toxic.

Deleted (1) Deleted (1) Deleted (1)

Normal

Start-up

(11O)Make-up Amine from Amine Storage Tank (810-SN18) Item

Test Method

Normal

Start-up

Diethanolamine

UOP 824

As req.

As req.

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AMINE SOLUTION FOAM TEST Scope: This test is intended for the determination of the foaming characteristics of aqueous amine solutions. It is particularly useful in comparing plant samples with clean, laboratory prepared solutions. Principle: Air is bubbled through the sample at a measured rate for five minutes, and the foam height and foam stability are measured. Apparatus: Stop watch, calibrated in seconds. Foam test apparatus; see Figure 11.7. Procedure: Pour 200 ml of an amine sample into the 1,000 ml cylinder. Connect the air delivery tubes and introduce oil-free air at four liters for minute. Allow the bubbling to continue for five minutes, stop the air flow and start the stopwatch. Immediately record the height of the foam and also record the time, in seconds, for the foam to break completely after the air supply is shut off. Foam Height: The difference in ml between the height of the foam and the initial height of the liquid ( 200 ml ). Foam Break Time: The time in seconds for the foam to break completely after the air supply is shut off. Comments: This method can be used to evaluate the effects of antifoam agents on the plant amine sample. Care should be exercised in cleaning the equipment since a very small amount of antifoam agent or surfactant may affect the test.

FIGURE 11.7

FOAMING APPARATUS AIR IN NO. 12 STOPPER FLOWMETER, MONOMETER TYPE AIR OUT

AIR IN

CAPILLARY TUBE

GAS DISPERSION TUBE

GRADUATED CYLINDER 1000 MILLILITER

1 0 0 0 7 5 m 0 l 5m 0l 0 2 m l5 0 m l

GAS DISPERSION TUBE CYLINDRICAL, FRITTED GLASS EXTRA COURSE, 8 x 550 - mm

64