Operating Manual For Ammonia_rev 2

PUSRI – IIB PROJECT 2000 MTPD AMMONIA & 2750 MTPD UREA OPERATING MANUAL FOR AMMONIA UNIT

OWNER

: PT. PUPUK SRIWIDJAJA PALEMBANG

CONTRACTOR

:

PROJECT TITLE

: PUSRI – IIB PROJECT

LOCATION

: PALEMBANG, SOUTH SUMATERA INDONESIA

JOB NO.

: 12-1812 / BA1066

DOCUMENT NO.

: P2B – 10 – 04 – MN – 0001 – R

2 1 0

07 Nov 14 18 Dec 13

Jan 15

REV.NO.

DATE

CONSORTIUM OF PT. REKAYASA INDUSTRI TOYO ENGINEERING CORPORATION

Issue for Approval Issue for Approval Issue for Preliminary DESCRIPTION

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JOB NO. : 12-1812/ BA1066 .

OPERATING MANUAL FOR AMMONIA UNIT

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REVISION HISTORICAL SHEET

Rev. No.

Date

0

18 Dec 2014

Issue for Preliminary

1

07 Nov 2014

Issue for Approval, revised based on the following:

2

Jan 2015

Description

-

Owner comments

-

Updated P&ID

-

Vendor’s Instruction Manual

Issue for Approval, revised based on the Owner comments

Table of Contents

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Contents 1. 1.1. 1.2. 1.3. 1.4. 1.5.

SAFETY AND HEALTH 1 PURPOSE AND APPLICATION.....................................................................................................1 PERSONNEL SAFETY................................................................................................................ 1 ENVIRONMENTAL SAFETY......................................................................................................... 1 EQUIPMENT SAFETY................................................................................................................ 2 SAFETY SYSTEMS.................................................................................................................... 2

2. 2.1. 2.2. 2.3. 2.4.

FACTORS THAT AFFECT QUALITY 1 GENERAL................................................................................................................................ 1 PROCESS TROUBLESHOOTING..................................................................................................1 SAMPLING............................................................................................................................... 1 RECORD KEEPING................................................................................................................... 2

3. 3.1. 3.2. 3.3. 3.4.

ROUTINE OPERATOR DUTIES 1 ROUTINE DUTIES FOR CONSOLE OPERATORS...........................................................................1 ROUTINE DUTIES FOR OUTSIDE OPERATORS............................................................................1 HOUSEKEEPING....................................................................................................................... 2 OPERATING INSTRUCTIONS / LOGS, MECHANICAL BOOKS AND VENDOR IMOI BOOKS..................2

4. 4.1. 4.2. 4.3. 4.4. 4.5. 4.6. 4.7. 4.8. 4.9. 4.10. 4.11. 4.12. 4.13. 4.14. 4.15. 4.16. 4.17. 4.18. 4.19. 4.20. 4.21. 4.22. 4.23.

OVERVIEW 1 KBR’S PURIFIERTM PROCESS...................................................................................................1 PROCESS SEQUENCE.............................................................................................................. 2 FEED GAS SUPPLY.................................................................................................................. 3 DESULFURIZATION................................................................................................................... 3 REFORMING SECTION.............................................................................................................. 4 PRIMARY REFORMING.............................................................................................................. 5 PROCESS AIR COMPRESSION...................................................................................................6 SECONDARY REFORMING.........................................................................................................7 SHIFT CONVERSION................................................................................................................. 8 CARBON DIOXIDE REMOVAL..................................................................................................9 METHANATION....................................................................................................................13 DRYING............................................................................................................................. 14 CRYOGENIC PURIFICATION..................................................................................................15 SYNTHESIS GAS COMPRESSION..........................................................................................17 AMMONIA SYNTHESIS.........................................................................................................18 AMMONIA REFRIGERATION..................................................................................................20 LOOP PURGE AMMONIA RECOVERY (2160 MTPD CASE).....................................................22 PROCESS CONDENSATE STRIPPING.....................................................................................22 STEAM SYSTEM.................................................................................................................. 23 STEAM SYSTEM CONTROLS................................................................................................25 COOLING WATER SYSTEM..................................................................................................26 FRONT-END STARTUP HEATING..........................................................................................26 PROCESS STEPS AFTER 131-J TRIP....................................................................................27

Table of Contents

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5. PROCESS OPERATING PRINCIPLES 1 5.1. NATURAL GAS SUPPLY............................................................................................................. 1 5.2. FEED GAS COMPRESSION........................................................................................................3 5.3. HYDROTREATER AND DESULFURIZERS (101-D AND 108-DA / DB).............................................4 5.4. PRIMARY REFORMER............................................................................................................... 6 5.5. PROCESS AIR COMPRESSOR – 101-J......................................................................................17 5.6. SECONDARY REFORMER / WASTE HEAT EXCHANGERS............................................................19 5.7. HIGH AND LOW TEMPERATURE SHIFT CONVERTERS................................................................24 5.7.1. LTS Reduction Piping...................................................................................................28 5.7.2. LTS Effluent Heat Recovery..........................................................................................30 5.7.3. Process Condensate....................................................................................................31 5.8. SYNTHESIS GAS PURIFICATION...............................................................................................34 5.8.1. Carbon Dioxide Removal..............................................................................................34 5.8.2. Process Flows / CO2 Product.......................................................................................36 5.8.3. Solution Flow................................................................................................................ 39 5.8.4. OASE Auxiliary Equipment...........................................................................................46 5.8.5. Methanator (Carbon Oxides Removal).........................................................................49 5.8.6. Molecular Sieves.......................................................................................................... 54 5.8.7. Purification.................................................................................................................... 57 5.8.8. 137-L Purifier Cold Box.................................................................................................62 5.9. AMMONIA SYNTHESIS.............................................................................................................63 5.9.1. 103-J Synthesis Gas Compressor................................................................................63 5.9.2. Synthesis Gas Conversion To Ammonia.......................................................................67 5.9.3. Ammonia Refrigeration System....................................................................................75 5.10. AMMONIA PURGE GAS RECOVERY SYSTEM.........................................................................84 5.10.1. Purge Gas Ammonia Recovery.................................................................................84 5.10.2. Ammonia Distillation Column.....................................................................................87 5.11. UTILITY FLOW.................................................................................................................... 88 5.11.1. Boiler Feedwater System..........................................................................................88 5.11.1.1. Demineralized Water.................................................................................................88 5.11.1.2. Deaeration................................................................................................................. 89 5.11.2. Steam Systems......................................................................................................... 94 5.11.2.1. High Pressure Steam Generation..............................................................................94 5.11.2.2. HP (123.1 Kg/Cm²g) Steam System..........................................................................97 5.11.2.3. MP (46.9 Kg/cm²g) Steam System............................................................................99 5.11.2.4. LP (3.5 Kg/Cm²(G)) Steam System.........................................................................100 5.11.2.5. Import Steam (OSBL)..............................................................................................101 5.11.2.6. Steam Condensate System.....................................................................................101 5.11.3. Jacket Water System...............................................................................................105 5.11.4. Cooling Water Systems...........................................................................................106 5.11.5. Service Water System.............................................................................................109 5.11.6. Potable Water.......................................................................................................... 109 5.11.7. Instrument and Plant Air Systems............................................................................109 5.11.8. Instrument Air System.............................................................................................109 5.11.9. Inert Gas System (Nitrogen)....................................................................................109 5.12. FUEL GAS SYSTEM...........................................................................................................110 5.12.1. Fuel Gas To 101-B...................................................................................................110 5.12.2. Fuel Gas To 102-B Start-Up Heater.........................................................................113 5.12.3. Fuel Gas To 101-B Superheater Burners.................................................................114 Table of Contents

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5.12.4. Fuel Gas To 101-B Tunnel Burners..........................................................................116 5.13. VENT AND RELIEF SYSTEMS..............................................................................................117 5.14. SAFETY SHOWERS / EYE WASHES SAFETY SHOWERS / EYE WASHES.................................120 6. UNIT CONDITIONING 1 6.1. INTRODUCTION........................................................................................................................ 1 6.2. PRESSURE TESTING................................................................................................................ 1 6.3. INSPECTION OF VESSELS.........................................................................................................3 6.4. CATALYST LOADING................................................................................................................. 4 6.5. PRIMARY REFORMER (101-B)..................................................................................................4 6.5.1. RELEVANT DATA................................................................................................................... 4 6.5.2. CATALYST..............................................................................................................................4 6.5.3. SCOPE ACTIVITY.................................................................................................................. 5 6.5.4. PD RIG.................................................................................................................................5 6.6. PACKED BED REACTOR CATALYST LOADING..............................................................................6 6.6.1. EQUIPMENT REQUIRED......................................................................................................... 6 6.6.2. PREPARATION....................................................................................................................... 7 6.6.3. RECORDS............................................................................................................................ 7 6.6.4. REACTOR CLOSURE ISOLATION & PRESERVATION....................................................................8 6.7. CATALYST LOADING OF 105-D AMMONIA CONVERTER................................................................8 6.7.1. SCOPE................................................................................................................................ 8 6.7.2. CATALYST............................................................................................................................ 8 6.7.3. RECORDS............................................................................................................................ 8 6.7.4. EQUIPMENT REQUIRED......................................................................................................... 8 6.7.5. PREPARATION....................................................................................................................... 9 6.7.6. CATALYST SCREENING........................................................................................................10 6.7.7. CATALYST WEIGHING..........................................................................................................10 6.7.8. LOADING............................................................................................................................ 11 6.8. LINE BLOWING AND FLUSHING................................................................................................13 6.9. STEAM LINE BLOWING........................................................................................................... 16 6.9.1. Scope........................................................................................................................... 16 6.9.2. Introduction................................................................................................................... 16 6.9.3. Prerequisites to an Effective Steam Blow.....................................................................17 6.9.4. Cleaning Effect............................................................................................................. 18 6.9.5. Steam Blow Preparations.............................................................................................19 6.9.6. Steam Blow Target Acceptance Criteria........................................................................19 6.9.7. Safety and Environmental Precautions.........................................................................20 6.10. INSTRUMENTS.................................................................................................................... 21 6.11. RUNNING-IN PUMPS........................................................................................................... 21 6.12. CALIBRATING PROPORTIONING PUMPS.................................................................................23 6.13. STEAM SYSTEMS................................................................................................................ 24 6.14. TURBINES AND COMPRESSORS...........................................................................................24 6.15. REFRACTORY DRYOUT........................................................................................................25 6.15.1. Dryout of the 101-B, Primary Reformer.....................................................................27 6.15.2. Dryout of the 102-B, Start-Up Heater.........................................................................28 6.15.3. 103-D Secondary Reformer Dryout...........................................................................31 6.16. OASE SYSTEM PREPARATION.............................................................................................31 6.16.1. Mechanical Cleaning and Inspection.........................................................................31 6.16.2. Initial Circulation and Degreasing..............................................................................32 Table of Contents

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6.16.3. Water Washing (Cool Water).....................................................................................32 6.16.4. Water Washing (Hot Water).......................................................................................34 6.16.5. Flushing with 3% Potash (Potassium Carbonate) Solution........................................34 6.16.6. First Condensate / Demineralized Water Flush.........................................................35 6.16.7. Second Condensate / Demineralized Water Flush....................................................36 6.17. FLUSH COOLING WATER SYSTEMS......................................................................................37 6.18. PROCESS LINE BLOWING....................................................................................................37 6.19. LEAK TEST UNIT................................................................................................................. 38 6.20. AMMONIA CONCENTRATION LIMITS AND EFFECTS.................................................................40 6.21. CHEMICAL CLEANING OF THE STEAM SYSTEMS...................................................................41 6.21.1. Purpose Of Chemical Cleaning and Passivation.......................................................41 6.21.2. Chemical Cleaning and Passivation Program Chemistry...........................................41 6.21.3. Items To Be Chemically Cleaned and Passivated......................................................41 6.21.4. Safety Health and Environmental Requirements.......................................................43 6.21.5. Construction Pre-requisites.......................................................................................44 6.21.6. Engineering Pre-requisites........................................................................................45 6.21.7. Preparations For Chemical Cleaning and Passivation...............................................45 6.21.8. Outline Of The Chemical Cleaning, Passivation, and Preservation Procedure..........48 6.22. METALLURGY..................................................................................................................... 51 7. SPECIAL INSTRUMENTATION AND CONTROLS................................................................................1 8. START-UP PROCEDURES............................................................................................................. 1 8.1. INTRODUCTION........................................................................................................................ 1 8.2. PRELIMINARY START-UP PHILOSOPHY......................................................................................2 8.3. INITIAL START-UP..................................................................................................................16 8.4. COMMISSION THE STEAM SYSTEMS........................................................................................16 8.5. COMMISSION 101-U.............................................................................................................. 17 8.6. PLACE HP BFW PUMPS IN SERVICE......................................................................................18 8.6.1. 103-JTC Surface Condenser for 103-JT.......................................................................23 8.6.2. 102-JTC Surface Condenser for 102-JT and 104-JT...................................................25 8.6.3. 101-JTC Surface Condenser for 101-JT......................................................................27 8.7. GENERAL.............................................................................................................................. 31 8.7.1. Prestart-up Conditions..................................................................................................31 8.7.2. Jacket Water................................................................................................................. 33 8.7.3. Fill 141-D...................................................................................................................... 34 8.7.4. Nitrogen Circulation......................................................................................................34 8.7.5. Primary Reformer Warm-up / Dryout...........................................................................35 8.8. COMMISSION 101-BJ/BJA, 101-BJ1/BJ1A - ID / FD FANS.....................................................37 8.8.1. Commission Natural Gas..............................................................................................37 8.8.2. 101-B Arch Burners......................................................................................................38 8.8.3. HP Steam Drum 141-D.................................................................................................39 8.8.4. 101-C Waste Heat Boiler Circulation............................................................................39 8.8.5. Steam Drum Operating Parameters..............................................................................40 8.9. INTRODUCTION OF STEAM.....................................................................................................41 8.10. COMMISSION REFRIGERATION SYSTEM................................................................................43 8.11. COMMISSION 120-J............................................................................................................ 44 8.12. START OASE SOLUTION CIRCULATION................................................................................45 8.13. NATURAL GAS HYDROGENATION AND DESULFURIZATION.......................................................51 Table of Contents

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8.14. START FEED GAS TO THE PRIMARY REFORMER...................................................................54 8.15. REDUCE AND DESULFURIZE THE REFORMER AND HT SHIFT CATALYST..................................56 8.16. HP TO MP STEAM LETDOWN..............................................................................................56 8.17. START AIR INJECTION TO SECONDARY REFORMER 103-D.....................................................57 8.18. COMPLETE DESULFURIZATION OF HT SHIFT CONVERTER......................................................60 8.19. STEAM BLOW THE HP STEAM LINE.....................................................................................61 8.20. PROCESS CONDENSATE STRIPPER......................................................................................62 8.21. START CO2 ABSORPTION....................................................................................................64 8.22. LT SHIFT CATALYST REDUCTION AND ACTIVATION.................................................................68 8.22.1. LTS Reduction Procedure..........................................................................................68 8.22.2. Commission Low Temperature Shift Converter.........................................................73 8.22.3. Start Methanation......................................................................................................74 8.23. INCREASE FEED RATES......................................................................................................78 8.23.1. OASE System........................................................................................................... 78 8.23.2. Start the Hydraulic Turbine........................................................................................79 8.23.3. Primary Reformer......................................................................................................80 8.23.4. Secondary Reformer.................................................................................................80 8.23.5. Desulfurizer............................................................................................................... 80 8.23.6. Steam Systems......................................................................................................... 80 8.23.7. Start the 105-J Refrigeration Compressor.................................................................81 8.23.8. Start-Up Refrigeration Compressor 105-J.................................................................81 8.23.9. Start-Up Synthesis Gas Driers 109-DA / DB..............................................................84 8.23.10. Regenerate the Molecular Sieve Dryers....................................................................86 8.23.11. Cryogenic Purifier Start-up........................................................................................87 8.23.12. Cryogenic Purifier Dryout..........................................................................................87 8.23.13. Process Gas Dryout..................................................................................................88 8.23.14. Purifier Cool Down.....................................................................................................89 8.23.15. Start-Up Synthesis Gas Compressor 103-J...............................................................92 8.23.16. Pressure Testing of the Synthesis Loop.....................................................................95 8.24. SYNTHESIS CONVERTER CATALYST REDUCTION...................................................................96 8.24.1. General...................................................................................................................... 96 8.24.2. Water Content........................................................................................................... 96 8.24.3. Refrigeration System.................................................................................................96 8.24.4. Catalyst Poisons........................................................................................................97 8.24.5. Synthesis Loop Reduction Alignment........................................................................97 8.24.6. Ammonia Converter Catalyst Reduction....................................................................99 8.24.7. Phase 1: Inlet Temperature to 343°C.......................................................................100 8.24.8. Start-Up Heater Precautions....................................................................................100 8.24.9. Phase 2: First Bed Activated - Hot Spot From 343°C to 427°C................................102 8.24.10. Phase 3: Heater Shutdown......................................................................................103 8.25. TRIM UNIT CONDITIONS AND STABILIZE AMMONIA PRODUCTION..........................................105 8.26. CRYOGENIC PURIFIER BYPASS OPERATION MODE..............................................................105 8.27. START THE PURGE GAS RECOVERY SYSTEM / AMMONIA STRIPPING SYSTEM.....................106 8.27.1. Place Ammonia Recovery In Service (2160MTPD Case)........................................106 8.27.2. Start Circulation.......................................................................................................107 8.28. COMMISSION PURGE GAS TO THE PROCESS OR FUEL GAS SYSTEM..................................110 8.29. SECONDARY BURNER FIRING.............................................................................................111 8.30. STARTUP AFTER EMERGENCY SHUTDOWN..........................................................................111 8.30.1. Package Boiler Trip / Loss Of Import Steam.............................................................111 Table of Contents

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8.30.2. Synthesis Gas Machine Trip.....................................................................................111 8.30.3. 105-J Refrigeration Machine Trip.............................................................................112 8.30.4. Purifier Trip.............................................................................................................. 113 8.30.5. Methanator Trip........................................................................................................113 8.30.6. OASE Solution Circulation Failure...........................................................................115 Shift Converters....................................................................................................................... 116 8.30.7. Loss of Process Air..................................................................................................118 8.30.8. Loss of Feed Gas....................................................................................................118 8.30.9. Loss of Process Steam............................................................................................119 8.30.10. Loss of Boiler Feedwater.........................................................................................120 8.30.11. Loss of Power.......................................................................................................... 121 8.31. NORMAL START-UP OF THE AMMONIA PLANT....................................................................122 9. SHUTDOWN PROCEDURES........................................................................................................... 1 9.1. NORMAL SHUTDOWN PROCEDURE............................................................................................1 9.1.1. Introduction..................................................................................................................... 1 9.1.2. Reducing Unit Throughput..............................................................................................1 9.2. PLANT SHUTDOWN.................................................................................................................. 3 9.2.1. Normal Shutdown...........................................................................................................3 9.2.2. Purge Gas Ammonia Recovery System Shutdown.........................................................3 9.2.3. Synthesis Section Shutdown..........................................................................................4 9.2.4. Synthesis Gas Compressor Shutdown...........................................................................7 9.2.5. Depressure and Nitrogen Purge the Synthesis Converter..............................................7 9.2.6. Ammonia Refrigeration System Shutdown.....................................................................8 9.2.7. 105-J Ammonia Compressor Shutdown..........................................................................9 9.2.8. Purifier Shutdown........................................................................................................... 9 9.2.9. Methanator Shutdown...................................................................................................10 9.2.10. Low Temperature Shift Converter Shutdown..............................................................11 9.2.11. OASE System Shutdown...........................................................................................11 9.2.12. High Pressure Condensate Stripper Shutdown.........................................................14 9.2.13. High Temperature Shift Converter Shutdown............................................................15 9.2.14. Reforming Section Shutdown....................................................................................16 9.2.15. Shut down 103-JTC...................................................................................................18 9.2.16. Shut Down and Secure the Steam System................................................................19 9.2.17. Shut down 104-Js......................................................................................................20 9.2.18. Shut down 101-JTC...................................................................................................21 9.3. EMERGENCY PROCEDURES....................................................................................................21 9.3.1. Introduction................................................................................................................... 21 9.3.2. Loss of Ammonia Recovery System.............................................................................22 9.3.3. Loss of 103-J Synthesis Gas Compressor....................................................................22 9.3.4. Loss of 105-J Refrigeration Compressor......................................................................23 9.3.5. Loss of the Purifier........................................................................................................24 9.3.6. Loss of Methanator, 106-D............................................................................................25 9.3.7. Loss of OASE Solution Circulation................................................................................26 9.3.8. Loss of LTS Converters, 104-D2A/B.............................................................................27 9.3.9. Loss of HTS Converter, 104-D1....................................................................................28 9.3.10. Loss of Process Air....................................................................................................28 9.3.11. Loss of Primary Reformer Feed Gas.........................................................................29 9.3.12. Natural Gas Failure...................................................................................................30 Table of Contents

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9.3.13. Loss Of Process Steam.............................................................................................31 9.3.14. Loss Of Steam Pressure...........................................................................................31 9.3.15. Loss of Water - Steam Drum 141-D...........................................................................32 9.3.16. Loss of Make-Up Water to 101-U..............................................................................33 9.3.17. Cooling Water Failure................................................................................................34 9.3.18. Instrument Air Failure................................................................................................35 9.3.19. Electric Power Failure................................................................................................36 9.3.20. Electrical Equipment Interlocks..................................................................................37 9.3.21. UPS Load Schedule and UPS Capacity....................................................................37 9.3.22. Electrical Equipment with Auto Reacceleration After Power Dip................................37 9.4. REMOVING EQUIPMENT FROM SERVICE..................................................................................39 9.5. RETURNING EQUIPMENT TO SERVICE.....................................................................................40 9.6. CATALYST OXIDATION............................................................................................................. 40 9.7. Conclusions......................................................................................................................... 40

Table of Contents

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1. Safety And Health 1. Purpose And Application The main purpose of this manual is to provide the operational guidance in ammonia unit at the PT Pupuk Sriwidjaja Palembang (PT PUSRI), Palembang, South Sumatera, Indonesia. The document will be updated considering HAZOP result. The information in this manual emphasizes safe and efficient work practices, which must be followed to produce high quality products.  Think Safe  Work Safe  Be Safe 2. Personnel Safety It is the responsibility of each PT Pupuk Sriwidjaja Palembang employee to participate in accident prevention. Each employee has a responsibility to their family, fellow employees, and PT Pupuk Sriwidjaja Palembang to work safely. Therefore, in the performance of all duties, every employee is expected to observe safe practices and instructions relating to the efficient and safe handling of all work tasks. Responsibilities include but are not limited to the following:  Incorporate sound safety practices into all tasks and not take chances.  Know and follow established safety standards and use safety as a primary consideration in planning all work.  Consult a supervisor when doubt exists about the safety requirements of a task.  Report all injuries immediately and cooperate with all investigations into the causes and prevention of accidents.  Participate in safety efforts realizing that prevention is the key to personnel, environmental, and equipment safety. 3. Environmental Safety Environmental safety activities are mandated by State and / or Local Authorities for all chemical process plants that handle hazardous materials. Protection of air, water, land, and surrounding life from pollution must comply with controls established by governmental regulatory agencies. Environmental safety begins with each employee. It is the responsibility of each employee to safeguard the environment, both in the interest of PT Pupuk Sriwidjaja Palembang, as well as to the communities and companies in the surrounding area. Day to day operations must be

Section 1 – Safety and Health

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scrutinized to ensure proper handling of chemicals, and to avoid releases to the environment. Some basic examples of day to day environmental concerns are:  Proper disposal of chemicals  Efficient use of the storage and process flare systems  Unit monitoring for fugitive emissions  Prevention of unwanted run off onto the sewer system 4. Equipment Safety Equipment safety refers to verifying that a tool or piece of machinery is safe to use and that each person’s knowledge of using the equipment meets approved operating standards. This is accomplished through training, calibrating, and maintaining mechanical and electrical systems so that they function as intended. 5. Safety Systems Safety systems are provided as a function of the process design. Relief valves protect vessels, piping, and equipment from over pressurization, and fail-safe valves assume their designed positions in the event of failure of automatic positioning, electrical power, or instrument air pressure. These features provide protection against over pressurizing operating systems and loss of process chemicals to the atmosphere, which could impact personnel safety and the environment. Depending on the design application, relief valves are used for the following: • Over-pressurization • Thermal relief Alarms are installed at specific points in the processes to monitor parameters critical to the proper operation of the unit. These alarms provide operators with a warning of conditions that, if left uncorrected may activate specific automatic process flow failure responses. Some typical examples of failure responses are: Relief valve opening to vent. (Resulting in product loss to vent and possible environmental impacts) Activation of automatic shutdown systems. In addition, certain interlocks are provided to perform specific automatic actions, such as opening/closing valves, and/or shutting down pumps or compressors. (Results in down time, and in most cases product loss to the vent). Safety systems not related to the process that are just as vital are:  Safety showers / eye wash stations Section 1 – Safety and Health

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Fire monitors / fire water system Emergency Lighting Radio, Telephone, or Intercom Communication Devices Personnel Protective Equipment such as Breathing Air Systems

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2. Factors That Affect Quality 6. General While many elements must be considered when quality of a final product is discussed, two major areas are typically examined in the investigation of process problems: 1. Operator Error 2. Equipment Failure In order to maintain high quality products, operators must be trained to recognize acceptable process control parameters and be able to make adjustments as necessary. Equipment must always be in good working order to maintain and indicate the proper operating limits. 7. Process Troubleshooting Troubleshooting is a method of solving problems. Once the problem is identified, a cause can be attached to it. Careful analysis should be made such that the identified cause is truly the cause and not a symptom. Once the cause is identified, remedies or solutions can be implemented. Generally the problem solving technical sequence of steps is as follows: Step (1) Identify the Problem Step (2) Gather Information That Relates To the Problem Step (3) Identify the Root Cause Step (4) Formulate the Solution Step (5) Test the Solution Step (6) Implement the Solution Step (7) Measure Effectiveness of the Corrective Action If The Problem Persist Return To Step 1, Which Is To Identify the Problem Obviously, the identification of problems cannot take place unless standards of control limits are declared. Sampling, record keeping, monitoring, and the use of calibrated instrumentation are key factors in the assessment of process problems.

8. Sampling Sampling is a fundamental part of product verification and good process operation. A sample should be taken to ensure that process and product specifications are being met. Avoid catching samples from low flow or stagnant points. Allow adequate movement of the product prior to catching the sample. Section 2 – Factors that Affect Quality

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Refer to the Material Safety Data Sheet (MSDS) book to determine any required precautions necessary to safely collect specific chemical samples. Take samples only from designated sample locations. It is very important to always wear the proper personal protective equipment (PPE) when taking samples. The following is a general checklist for sampling in the ammonia unit: 1. Obtain the proper sample container for specific sample to be taken 2. Locate sample point 3. Inspect sample point for proper working condition 4. Using proper PPE equipment to catch sample 5. Isolate sample point and remove sample 6. Fill out sample tag and attach to sample or use a pre-labeled sample container 7. Take sample to designated lab pick-up point or to the lab directly 8. Log sample and results in the operators log book Refer to the PT PUSRI normal operation procedures covering sample procedures for detailed instructions. 9. Record Keeping Record keeping is a means to document quality, measure inventories, and generally track notable activities which could indicate trends before serious consequences result. Shipping, Receiving, Daily Production Logs, Environmental Reports, Operator Reading Log Sheets, and Safety Records are some examples of records which are maintained for production, business, and legal reasons. Some concerns, which are inherent to record keeping in general, include:  Allocation Of Time To Keep Records  Storage Space For Records  Retrieval Of Records After Storage  Length Of Time To Keep Stored Records Other quality control records include equipment inspection reports, calibration / test reports for relief valves, interlock systems, flow meters, temperature indicators, and pressure gauges, etc. Hand written records such as Daily logbooks should be clear, concise, and to the point. Take a few minutes to think about the main points of the event you are writing about before you start. Always leave out personal opinions, only state the facts. Records that are not retrievable are useless. Check with the unit supervisor to determine record retention times, and storage locations as required, to keep records current and useful. The key to record keeping is consistency. Try to take readings at the same time each day for continuously operated equipment. This will help negate the effect of varying outside factors on your data.

Section 2 – Factors that Affect Quality

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Environmental records as opposed to production records must be maintained to comply with federal, state, and local government regulations. This data must be accurate. For more details on how and when to record environmentally sensitive data consult the Environmental Department or the unit supervisor.

Section 2 – Factors that Affect Quality

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3. Routine Operator Duties 10. Routine Duties For Console Operators In performing the normal job duties in the ammonia unit operations, control console operators will be required to:  frequently monitor DCS and other consoles for safe and efficient operations  make necessary adjustments to keep process running smoothly  print and retrieve DCS generated reports  Record selected unit information on log sheets at pre-set intervals. Control console operators should always communicate with the outside operators using clear and precise instructions. 11. Routine Duties For Outside Operators In performing the normal job duties in the ammonia unit operations, outside operators will be required in part to:  climb ladders  climb stairs  open and close valves of all sizes  work around hot and cold equipment  work in elevated areas of the unit  lift various tools and small equipment  use hoses of varying services and sizes  handle chemicals  record selected unit information on log sheets Operators should pay special attention to, proper lifting techniques when operating valves, to prevent back injuries, and the proper working on elevated platforms or ladders. This does not preclude work standards, but simply highlights some of the hazardous areas sometimes are taken for granted and cause the worst injuries.

and proper body positioning use of fall protection when any or all of the other safe of the normal job duties that

The safest process operator is a well-trained and observant operator that applies all safe work practices and standards in performance of every task required. Operators should always take the time necessary to read or review the Material Safety Data Sheets, MSDS, and procedures for the task to be performed, and use the proper personal protective equipment, PPE, and tools.

Section 3 – Routine Operator Duties

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12. Housekeeping Housekeeping is an area of concern that must be addressed because of its direct impact on safety in the workplace and morale of the employees. Keeping an area clean and orderly, can provide the basis for positive attitudes and efficiency in operations and other related departments. Housekeeping must be applied not only to equipment maintenance where the need is obvious during or after maintenance work, but also to routine activities such as eating, smoking, and keeping break areas clean and orderly. The use of appropriate cleansers to clean soiled areas and putting items back in their proper place of storage after use, are major elements in the implementation of a good housekeeping program. Operators should write work orders for clean-up activities that fall outside the scope of their responsibility. Examples of tasks that may fall into this category are:  Removing scaffolds from process areas  Disposal of insulation Operators should always be aware of housekeeping; it takes a conscientious effort from everyone involved to accomplish a successful housekeeping program. 13. Operating Instructions / Logs, Mechanical Books and Vendor IOM Books Operators cannot properly operate a plant if they cannot find the appropriate vendor information to refer to. A complete set of as-built P&IDs and other drawings, mechanical catalogs, vendor instructions books and engineering data should be accessible to the operators at all times. These items should be stored in the control room in a controlled environment and available for anyone who requires information at anytime of the day or night.

Section 3 – Routine Operator Duties

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4. Overview This manual has been compiled to assist those charged with the responsibility of the initial startup and subsequent operation of the 2,000 metric tons per day Ammonia Plant for PT Pupuk Sriwidjaja Palembang, South Sumatera, Indonesia. Its primary objective is to provide flow descriptions and discussions of the processes involved and related operating principles, suggested procedures for the initial commissioning and startup and shutdown of the plant. The contents should be regarded as a source of reference for information in resolving operating problems NOTE It is not possible to anticipate and present herein all potential circumstances, which confront the operators during the commissioning, startup, normal, and emergency shutdown of the unit. Consequently, this operating manual must be recognized as a GUIDE and that conditions stipulated are NOT rigid standards, unless specifically noted as such. The operating conditions and techniques will evolve from actual operating experiences. Under no circumstances should operations deviate from safety regulations and practices followed throughout the industry.

This Process Description covers an ammonia plant of PUSRI IIB being built for PT Pupuk Sriwidjaja, Palembang, South Sumatera, Indonesia, which is Natural Gas (NG) as the feedstock. The plant is designed with a name plate capacity of 2,000 MTPD of ammonia product. The ammonia plant design and performance estimates are based on the design Natural Gas composition shown in the Process Design Basis which provides other pertinent details. In normal operation, 1,595 MTPD of warm Ammonia is produced for supply to Urea plant and 405 MTPD of cold ammonia is produced at -33°C which is sent to offsite storage at atmospheric pressure. 14. KBR’s PurifierTM Process The process design of the ammonia plant is based on KBR’s Purifier technology. The key features of a Purifier plant, as opposed to a conventional ammonia plant, are as follows: - Mild primary reforming - A substantial amount of reforming duty is shifted from the primary to the secondary reformer. That causes the primary reformer to be smaller, have a lower process outlet temperature, and use less fuel. -

Secondary reforming with excess air - The excess air allows for more reforming to be done in the secondary reformer than in the primary reformer where there is heat loss to a stack. Section 4 – Overview

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Also, because of the downstream Purifier which reduces the excess nitrogen and methane, the methane slip from the secondary reformer can be higher. This gives a lower process outlet temperature from the secondary reformer and hence milder conditions for the downstream waste heat boiler. It also allows having a favorable lower steam/carbon ratio in the reformer feed. -

Cryogenic purification of the make-up synthesis gas - The excess nitrogen introduced with the excess air in the secondary reformer is condensed out via cryogenic purification. The nitrogen takes with it methane, argon and other impurities in the raw synthesis gas. This allows for a lower pressure in the ammonia synthesis loop, a lower recycle rate, a lower catalyst volume, and less purge from the synthesis loop.

CO2 removal unit is based on BASF’s 2 stage, OASE process well integrated into the ammonia plant. All the components of the ammonia plant are based on well-proven technology. All process equipment are single-train. All major compressors are centrifugal type. The Process Air Compressor, Synthesis gas Compressor and the Ammonia Refrigeration Compressor are driven by steam turbines. The Primary Reformer has two Induced Draft (ID) Fans and two Forced Draft (FD) Fans, all driven by steam turbines. One each of the Lean Solution Pumps and the Semi-Lean Solution Pumps are turbine driven with motor driven stand by pumps. Boiler Feed Water (BFW) pump is driven by steam turbine, with motor driven spare pump. The third Semi-Lean Solution Pump is driven by a hydraulic turbine. 15. Process Sequence The process scheme of the ammonia plant is shown on Process Flow Diagrams (PFDs). The main process steps are as follows: • Feed Gas Supply • Desulfurization • Primary Reforming • Process Air Compression • Secondary Reforming • Shift Conversion • Process Condensate Stripping • Carbon Dioxide Removal • Methanation • Drying • Cryogenic Purification • Synthesis Gas Compression • Ammonia Synthesis Section 4 – Overview

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Ammonia Refrigeration Loop Purge Ammonia Recovery Steam System Cooling Water System Miscellaneous Items

Each of these process steps is described in detail below, with main emphasis on the normal flow scheme and parameters as given in mass balance. Further description of operating variables and lines which are normally not in service, controls etc. will be included in the operating philosophy. 16. Feed Gas Supply The feed gas supply system is shown on Process Flow Diagram FD1. Natural Gas for feed and fuel is supplied to the ammonia plant battery limit (BL) at 14.0 o kg/cm2G and ~30 C temperature. The NG flows to the Feed Gas Knockout (KO) Drum 174-D where pressure is maintained / controlled. NG is supplied at B/L at a controlled pressure, however, pressure control is provided inside the plant especially for the low throughput operations to ensure stable operations. 17. Desulfurization The feed gas desulfurization system is shown on Process Flow Diagram. The natural gas contains total sulfur of maximum 15 ppmv and average 8 ppmv as H2S. This sulfur must be removed to prevent poisoning of the catalysts downstream. The feed gas is mixed with a recycle stream of hydrogen-rich synthesis gas from the washed purge gas, to obtain a hydrogen content of 2.0 mol%. The gas mixture is then heated to 371°C in a feed preheat coil, which is located in the convection section of the Primary Reformer 101-B. H2 can also be recycled from Methanator Effluent Separator 144-D at the outlet of Methanator or from existing Ammonia Plants per presence of organic sulfur in the feed gas. Desulfurization of the Natural Gas is accomplished in two stages. In the first stage, the heated gas goes to a Hydrotreater 101-D, where it is reacted over cobalt/molybdenum (CoMo) catalyst. The organic sulfur present in the feed gas is hydrogenated to hydrogen sulfide as follows: COS + H2

⇒ CO + H2S Section 4 – Overview

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⇒ RH + H2S

In the second stage, hydrogen sulfide is removed in the Desulfurizers 108-DA/DB to <0.1 ppmv and <0.01 ppmv of Total Sulfur in the outlet Natural Gas. Each Desulfurizer contains a bed of zinc oxide adsorbent. The hydrogen sulfide adsorbs on the zinc oxide to form zinc sulfide as follows: H2S + ZnO

⇒ ZnS + H2O

108-DA and 108-DB are arranged in series, in a lead-lag configuration. When the upstream vessel is saturated with hydrogen sulfide, it can be taken out of service for replacement of the zinc oxide, while the downstream vessel remains in service. The vessel with fresh zinc oxide is then placed in service as a clean-up step downstream of the vessel with partially used zinc oxide. This allows for maximum utilization of the zinc oxide. A high concentration of ammonia in the Natural Gas feed could restrict the activity of the hydrotreating catalyst. High partial pressures of carbon dioxide and water could inhibit the adsorption of sulfur on the zinc oxide by reacting with the zinc oxide to form hydrates or carbonates. At the expected operating conditions, no such adverse reactions are foreseen. The HDS catalyst needs to be in sulfided state to be active for hydrogenating organic sulfur. During normal operation with some sulfur present in NG, HDS catalyst will stay sulfided. However if during an unforeseen scenario, NG is supplied totally free of sulfur for long sustained time, H2 recycling will need to be reduced or stopped to avoid reduction of the unsulfided HDS catalyst which is detrimental to catalyst. During initial plant start-up, there will be a period of time until the Methanator is brought on line, when no recycle hydrogen is available. During this period, hydrogen can be sourced from OSBL for meeting the hydrogen demand for HDS reactor. Once the feed has been cut in and plant is producing hydrogen in the Reforming / Shift sections, this hydrogen-containing gas is cooled down in the heat exchange train downstream of the reformers, and can be recovered from Methanator Effluent Separator 144-D. The OSBL recycle hydrogen import can be stopped once sufficient hydrogen is being produced by the steam reforming of Natural Gas in 101-B. H2 recycle is critical if NG has organic sulfur. 18. Reforming Section The feed natural gas, after mixing with steam, is reformed to produce reformed gas using primary reforming and secondary reforming. The reforming system is shown on Process Flow Diagram. Medium pressure process steam is added to achieve a 2.7 steam-to-carbon molar Section 4 – Overview

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ratio in the mixed feed gas to Primary Reformer. 19. Primary Reforming The Primary Reforming system is shown on Process Flow Diagrams. Desulfurized Natural Gas feed is mixed with process steam from the Process Condensate Stripper 130-D to give a steam-to-carbon molar ratio of 2.7 to 1.0. The feed gas flow is controlled by ratio to the process steam flow. This feature protects the reforming catalysts in the event of a loss of process steam. The mixed feed is preheated in the mixed feed coil located in the convection section of 101-B. The hot mixed feed is distributed between the catalyst tubes in 101-B. These high-alloy tubes are suspended from the roof of the radiant section of the furnace and packed with nickel based reforming catalyst. As the mixed feed flows down over the reforming catalyst, steam reforming and water gas shift reactions take place forming hydrogen, carbon monoxide and carbon dioxide. The inlet temperature of 101-B is 488 oC. The pressure inlet of 101-B is 46.2 kg/cm2G, while pressure drop across 101-B is 4.75 kg/cm2. The steam reforming reaction converts hydrocarbons in the Natural Gas to hydrogen and carbon monoxide: CnHm + nH2O ⇔ nCO + (2n+m)/2H2

For methane the above reaction becomes: CH4 + H2O

⇔ CO + 3H2

The water gas shift additional hydrogen: CO +

2

reaction

converts

carbon

H2O ⇔ CO2 + H2

monoxide

to

carbon

dioxide

and

The steam reforming of heavier hydrocarbons goes to completion, but the steam reforming of methane and the water gas shift reactions are limited by chemical equilibrium. Overall, the combination of reactions taking place in 101-B is strongly endothermic. The net heat of reaction is supplied by fuel gas being fired in burners, which are located in the arch of the radiant section of 101-B, between the rows of catalyst tubes. The burners operate in a downward firing mode. This causes the highest heat flux to exist in the top section of the tubes, where the temperature of the process gas is lowest and where most of the endothermic reactions are taking place. This results in a relatively even metal wall temperature across the length of the catalyst tubes. The process gas conditions at the outlet of the catalyst tubes are about 715°C and 41.5 kg/cm2 (A). The effluent gas from 101-B contains ~28.50 mol% of unreacted methane on a dry basis. Due Section 4 – Overview

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to the relatively mild temperatures of radiant tubes, these are not in creep mode service and are more reliable and operationally flexible and give long service life. Maximum skin tube temperature is 864.4 oC 101-B is designed to obtain maximum thermal efficiency. To avoid heat loss, the outlet manifold and the outlet “riser” pipes are located inside the furnace. In addition, heat is recovered from the flue gas in the convection section. The convection section includes coils for the following services: - Preheating of mixed feed for Primary Reformer 101-BCX (feed gas and process steam). - Preheating of process air 101-BCA2 and 101-BCA1 (hot and cold coils) - Superheating of HP steam 101-BCS2 and 101-BCS1 (hot and cold coils) - Preheating of Natural Gas feed 101-BCF - Combustion Air Preheat Coil 101-BC A steam attemperator is provided between the hot and cold sections of the steam superheat coil to inject BFW into the steam, as needed, to prevent too high a steam superheat temperature and / or to increase steam production. The steam superheater coils also have additional firing superheat burners. Normally these burners will be used to control temperature of the superheated steam. The radiant box in 101-B is fired with a combination of Natural Gas and waste gases. The later include: - HP flash gas from the carbon dioxide removal system - Purifier waste gas - LP Scrubbed synthesis flash gas The waste gases are burned in separate burner ports (in center) of each burner rather than premixed in the upstream piping. This is optimum arrangement for different type of fuels and it allows for swings in the waste gas pressure and temperature, especially when the Molecular Sieve Driers 109-DA/DB are being regenerated. Only NG fuel gas is used in 101-B steam superheat burners and 102-B Ammonia Converter Start-Up Heater (only during start-up) 101-B is equipped with two Induced Draft (ID) Fans 101-BJ/BJA and two Forced Draft (FD) Fans 101-BJ1/BJ1A. All the four machines are steam turbine driven. 20. Process Air Compression The process air compression system is shown on Process Flow Diagram. Process air is compressed to 44.5 kg/cm2(A) in a four-stage centrifugal Process Air

Section 4 – Overview

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Compressor 101-J. Inter-stage cooling and separation of condensate is provided by Intercoolers 101-JC1, 101-JC2 and 101-JC3. 101-J provides air for the Secondary Reformer 103-D (on FD-1) plus an additional 3000 Nm3/h for instrument and plant air. The air compressor driver is a medium pressure to condensing steam turbine, 101-JT. Any excess low pressure steam can also used by 101-JT. The Process Air flow is controlled with 101-JT steam turbine speed. In case of turndown operation, enough compressed air is vented to maintain the minimum load on 101-J, thereby preventing it from going into surge. The compressed process air is heated to 497°C in the process air pre-heat coil. A small quantity of MP steam is injected upstream of the process air preheat coil to protect the coil from overheating during startup and shutdown conditions and also ensures forward flow in the event of emergency shutdown of the air compressor. Design temperature of Cold Process Air Coil 101-BCA1 is 422 oC, while Hot Process Air Coil 101-BCA2 is 535 oC. 21. Secondary Reforming The secondary reforming system is shown on Process Flow Diagram. In a conventional ammonia plant, the quantity of process air is controlled to produce an ~3 to 1 molar ratio of hydrogen to nitrogen at the inlet to Ammonia Synthesis Converter 105-D. In a KBR Purifier ammonia plant, about 50% excess (additional) air is used in 103-D. This results in a hydrogen-to-nitrogen ratio of about 2 to 1 at the inlet to the cryogenic Purifier. The excess air provides additional reaction heat and reforming in 103-D. Also, the slip of unreacted methane from 103-D is higher in a KBR Purifier plant (about 1.59 mol% for PUSRIIIB) than in a conventional plant (0.25 – 0.3 mol%), as unreacted methane is removed in the cryogenic Purifier downstream. These process features relax the reforming severity and lower the outlet temperatures of both the Primary and the Secondary Reformers in Purifier plants as compared to conventional plants. The process gas leaving Primary Reformer 101-B goes through Primary Reformer Effluent Transfer Line 107-D and enters the combustion chamber of Secondary Reformer 103-D. Here the gas mixes with process air from Process Air Compressor 101-J. A small quantity of MP steam is added to the process air. This is to ensure forward flow in the line to the combustion chamber in the event of loss of process air. In the 103-D combustion chamber, 101-B effluent and preheated process air mix, and spontaneous combustion occurs. This results in a high temperature of about 1349°C The hot gas flows down through a bed of nickel-based reforming catalyst, where steam reforming and shift reactions occur. Due to the overall endothermic nature of the reactions, the Section 4 – Overview

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gas temperature leaving 103-D is reduced to about 898°C. The unreacted methane content in the outlet gas is about 1.59 mol% on dry basis. The pressure drop across 103-D is 0.96 kg/cm2. The chemical reactions are the Reforming and Shift Reaction mentioned above under Primary Reforming Section, as shown below: CH4 + H2O + heat ⇔ CO + 3 H2 CO + H2O ⇔ CO2 + H2 + Heat

Because of the very high process gas temperatures, 107-D and 103-D are internally insulated with refractory and externally water-jacketed. The jacket water is provided from steam turbine condensate header 119-J/JA or from demineralized water. Steam generated from the water jackets is vented. A refractory failure can be detected early by increased water consumption in the water jackets. 22. Shift Conversion The shift conversion system is shown on Process Flow Diagram. In the shift conversion step, carbon monoxide reacts with steam to form equivalent amounts of hydrogen and carbon dioxide: CO + H2O ⇔ CO2 + H2

The shift reaction is reversible and exothermic. The reaction rate is favored by high temperature, while the equilibrium conversion is favored by low temperature. Hence the reaction is carried out in two stages with inter-stage cooling. Maximum conversion of carbon monoxide results in maximum yield of hydrogen for ammonia synthesis. The bulk of the shift reaction takes place in the first stage, the HTS (high temperature shift) Converter 104-D1. 104-D1 contains copper-promoted iron catalyst. This catalyst is relatively low-cost and durable. The copper promoter suppresses unwanted side reactions that could occur on the shift catalyst due to the relatively low steam-to-gas ratio used. The EOR (end-ofrun) operating temperature is 371ºC at the HTS inlet. About 70% of the carbon monoxide in the effluent from the Secondary Reformer 103-D, is converted to carbon dioxide in 104-D1. The carbon monoxide content in the effluent from 104-D1 is about 3.41 mol% on dry basis. The effluent from 104-D1 is cooled by heating BFW and generating HP steam in the HTS Effluent / BFW Preheater and Steam Generator 103-C1 / C2. A bypass is provided on 103-C2 BFW side to allow control of the LTS (low temperature shift) inlet temperature.

Section 4 – Overview

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The shift reaction goes almost to completion in the LTS Converters 104-D2A/B. Here the lower temperature provides a higher equilibrium conversion of carbon monoxide. 104-D2A/B contain copper/zinc catalyst, which is more expensive than the catalyst in 104-D1, and is also more sensitive to impurities such as sulfur in the process gas. The EOR inlet temperature to 104-D2A/B is about 205°C. The effluent from 104-D2A/B has a residual carbon monoxide content of about 0.31 mol% on dry basis. The pressure drop across HTS 104-D1 and LTS 104D2A/B are 0.26 and 0.41 kg/cm2. Heat is recovered from the LTS effluent in three heat exchangers (on FD-2): - LTS Effluent / BFW Preheater 131-C - CO2 Stripper Reboiler 105-C - LTS Effluent / DMW Exchanger 106-C The water condensed from the LTS effluent cooling is separated in the Raw Gas Separator 142-D1. This condensate is pumped by the Process Condensate Pumps 121-J/JA to the Process Condensate Stripper 130-D. The temperature in 142-D1 is controlled to maintain the water balance in the downstream carbon dioxide removal system. A higher temperature in 142-D1 will increase the amount of water vapor entering the carbon dioxide removal system. The process gas from 142-D1 overhead goes to the CO2 Absorber 121-D in the carbon dioxide removal system. Several of the catalysts in the ammonia plant need to be reduced during initial start-up. In most cases, this can be accomplished by using the process feed/steam or process gas, and discharging the reactor effluent to the flare system, until the effluent is suitable to forward to the next process step. For details of these operations, please refer to the operating philosophy. However, the LTS catalyst needs to be reduced in a special, well-controlled manner. Therefore, a separate LTS start-up system is provided. It consists of a LTS Startup Cooler 173-C, LTS Startup Separator 173-D, LTS Start-up Circulator 173-J (driven by a motor), and LTS Startup Heater 175-C (heated with MP steam). 173-J circulates nitrogen, which is the carrier gas, through the LTS catalyst. Hydrogen for catalyst reduction can come from the OASE CO2 Absorber outlet. Water formed during LTS catalyst reduction is drained from 173-D. The flow rate of nitrogen, the hydrogen concentration, the reduction temperature and the operating pressure are determined by the LTS catalyst supplier. 23. Carbon Dioxide Removal The carbon dioxide removal unit is shown on Process Flow Diagram. The carbon dioxide removal unit uses the energy-efficient two-stage OASE® process licensed by BASF. The unit is designed to remove carbon dioxide in the process gas from 18.5 mol% Section 4 – Overview

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down to 500 ppmv, both dry basis. OASE is an activated methyl diethanol amine solution, which is a proprietary solvent licensed by BASF. The absorption of CO2 takes place at relatively high pressure and low temperature. The regeneration of the solution takes place at relatively low pressure and high temperature. Operating pressure and temperature of CO2 Absorber are 36.7 kg/cm2G and 50 oC (top), 85 oC (bottom). Meanwhile, operating pressure and temperature of CO2 Stripper are 1.12 kg/cm2G and 126 oC. The process gas first enters the bottom section of CO2 absorber 121-D, where the bulk of the carbon dioxide is removed by contact with a semi-lean OASE solution. The gas then flows to the top section of 121-D, where most of the remaining carbon dioxide is removed by contact with a lean OASE solution. To remove any entrained OASE solution in the gas stream, the treated gas flows through several wash trays and a demisting pad in the top of 121-D, and then flows through CO2 Absorber Overhead Knockout Drum 142-D2. The gas is also sprayed with a small quantity of process condensate in the pipe ahead of 142-D2 to remove any traces of OASE. Condensate spray in pipe is optional and utilized if necessary in the plant. The rich OASE solution leaving the bottom of 121-D is almost completely saturated with carbon dioxide. It flows through a Hydraulic Turbine 107-JAHT, where power is recovered by letting down the pressure of the solution. 107-JAHT is used to drive one of the Semi-lean Solution Pumps (107-JA). A bypass is provided on 107-JAHT, in order to control the amount of power extracted and to provide a flow path during times when the hydraulic turbine is unavailable. The pressure at the exit of 107-JAHT (as controlled in 163-D) is set to allow a major portion of the inert gases, such as hydrogen, carbon monoxide and N2, which are dissolved in the solution, to be flashed off. The flashed gases are disengaged from the solution in CO2 HP Flash Column 163-D. 163-D has a single packed bed to promote the disengagement of the flash gas, and gas de-entrainment packing in bottom sump. The HP flash gas leaving 163-D flows as fuel to the Primary Reformer 101-B. Equipment 163-D thus ensures production of high quality CO2 byproduct by removing entrained gases. The solution from the bottom of 163-D is sent to the CO2 LP Flash Column 122-D1. In the LP flash, most of the absorbed carbon dioxide is released. The internals of 122-D1 consist of packed bed, water wash trays at the top and a demister to avoid OASE going with the overhead vapors. The LP flash overhead is cooled to 38ºC in the CO2 LP Flash Overhead Condenser 110C. Pressure outlet 110-C is 0.93 kg/cm2G. The condensed water is separated from the carbon Section 4 – Overview

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dioxide in CO2 LP Flash Reflux Drum 153-D. The CO2 by product of ammonia plant is sent to UREA plant and the rest is vented to atmosphere. CO 2 product concentration is min 99% vol. The water condensed out in 153- D is pumped by the CO2 Stripper Reflux Pumps 110-J/JA to the wash trays in the top sections of 121-D, 163-D and 122-D1 to maintain the system water balance. Normally seal flush for the OASE pumps is provided by cool lean solution exit 108-J/JA. At startup however, water condensate exit 110-J/JA is used for pump seal flush. The carbon dioxide removal unit is designed to have a slight water deficit. To maintain the water balance in the system, a small continuous stream of make-up demineralized water is added to 153-D. This design eliminates any liquid effluent from the carbon dioxide removal unit which avoids any potential loss of OASE from the system and effluent treatment requirements. As mentioned above, a second method to control the water balance in the carbon dioxide removal unit is the temperature in Raw Gas Separator 142-D1. A higher temperature in 142-D1 will increase the amount of water vapor entering the carbon dioxide removal system. The bottom product from 122-D1 is semi-lean OASE solution. Most of the semi-lean solution is pumped back to the lower section of 121-D by the Semi-lean Solution Pumps 107-JA/JB/JC. 107-JA is driven by 107-JAHT. 107-JB is turbine driven whereas 107-JC is motor-driven pump. The remaining semi-lean solution is pumped by the Semi-lean Solution Circulation Pumps 117-J/JA to the Lean / Semi-lean Solution Exchanger 112-C/CA. Here, the semi-lean solution is heated by exchanging heat with lean solution.The heated semi-lean solution is then sent to the CO2 Stripper 122-D2. A slip stream from the discharge of 117-J/JA is sent to OASE Solution Filter 104-L to remove any particulate matter entrained in the solution. The effluent from 104-L is routed to 122-D1. In 122-D2, remaining carbon dioxide dissolved in the semi-lean solution is stripped out with steam generated in CO2 Stripper Reboiler 105-C. A process bypass is provided on 105-C for temperature control in 122-D2 and to optimize process waste heat recovery. 122-D2 has two packed beds to facilitate the stripping. The overhead from 122-D2 is routed to 122-D1 that enhances stripping in the LP Flash. The bottoms from 122-D2 is lean solution. The lean solution is cooled first by heat exchange with the stripper feed in 112-C/CA, and then by 109-C Lean Solution/DMW Heater parallely 108-C/CA Lean Solution Cooler. Heat recovery in 109-C is maximized as far as the downstream 106-C is able to cool the 121-D inlet gas to a desired temperature of about 70ºC. Higher heat recovery in 109-C will lead to higher inlet Demineralised Water temperature to 106-C which will affect controllability of gas temperature exit 106-C. Section 4 – Overview

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Strainers are provided on OASE solution inlet to 112-C/CA on both the hot as well as cold side. It is absolutely essential to always keep one of these strainers inline (the other is cleaned with plant in operation) to avoid severe plugging and fouling of plate exchangers. Strainer internals must be confirmed to be effective without bypassing or damage all the time without exception. Exchanger 108-C/CA also has similar strainer at CW inlet and always must be maintained to avoid operational problems due to blockage/fouling of 108-C/CA on CW side. The cooled lean solution is pumped back to the top section of 121-D by Lean Solution Pumps 108-J/JA. 108-J is turbine driven whereas 108-JA is a motor-driven pump. The carbon dioxide content of the lean solution is low enough to meet the specification of maximum 500 ppmv of carbon dioxide in the 121-D overhead. To avoid foaming, OASE Anti-foam Injection System 109-L is provided. Anti-foam solution is added to the feeds to 122-D1, 117-J/JA and 108-J/JA. A solution handling system is provided. It consists of the following equipment: - OASE Solution Sump Tank 115-F - OASE Solution Mixer 110-L - OASE Sump Pump 115-J - OASE Sump Filter 115-L - OASE Solution Storage Tank 114-F - OASE Transfer Pump 111-J The system allows the following operations: - Makeup of normal solution by adding OASE premix (supplied by BASF) and demineralized water or condensate to 115-F, and mixing with 110-L. The mixed solution can be transferred to 114-F by 115-J, via 115-L. - Circulating 114-F with 111-J for homogenization. - Charging solution from 114-F into the process system by 111-J. The solution must always enter the operating solution inventory through the OASE Filter 104-L. - Draining the process system. This can be done by first pumping with 108-J/JA to - 114-F, and then draining from low points in the underground collection piping to - 115-F and transferring to 114-F. The solution concentration can be increased by adding concentrated OASE or reducing makeup demineralized water to 153-D. The solution concentration can be decreased by purging some solution to 114-F, and adding water to the circulating solution as demineralized water make-up. Each of the filters 104-L and 115-L have a construction to ensure that solids / dirt collected over filter elements is retained inside for cleaning and it does not go back to inventory while reclaiming the solution before flushing it with water or opening it. Filter 115-L has elements to

Section 4 – Overview

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filter >10 micron solids. The filter 104-L shall be supplied with a stock of four types of filter elements (1) >100 micron st (2) >30 micron (3) >3 micron. During 1 start-up and subsequent start-ups after plant shutdowns, initially element type #1 shall be used till cleaning frequency is reasonable. This will be followed by element type #2 and ultimately type #3 shall be used in normal steady operation when solution is very clean. Refer to the operating and lab analytical instructions from the licensor for further details including the pre commissioning cleaning requirements. 24. Methanation The methanation system is shown on Process Flow Diagram. The treated process gas from CO2 Absorber Overhead Knockout Drum 142-D2 is preheated from 50°C to 316°C in the Methanator Feed / Effluent Exchanger 114-C and in Methanator Startup Heater 172-C. The heat source in 172-C is saturated HP steam. A gas bypass is provided around these exchangers to control the inlet temperature to the Methanator 106-D. The gas then flows through 106-D, where remaining carbon oxides combine with hydrogen over a nickel catalyst to form methane and water: CO2 + 4H2 CO + 3H2

⇔ CH4 + 2H2O ⇔ CH4 + H2O

The methanation reactions are highly exothermic and could potentially overheat 106-D. This could occur if an upset in the shift (LTS) or carbon dioxide removal systems causes a breakthrough of carbon monoxide or carbon dioxide to 106-D. An automatic shutdown system is provided to prevent overheating. This is described in detail in the operating philosophy. The exothermic methanation reactions cause a temperature rise across 106-D. As a rough estimation, every increase 1% CO concentration in the feed gas may result a temperature rise of 74 oC, while an increase 1% of CO2 concentration may bring about temperature rise of 60 oC. The pressure drop across 106-D is 0.21 kg/cm2. At end-of-run of the LTS catalyst, the feed to 106-D will contain about 0.38 mol% carbon monoxide and about 500 ppmv carbon dioxide. However, when the LTS catalyst is fresh, the carbon monoxide content will be lower, resulting in less temperature rise across 106-D. At this time, heating in 172-C is essential to maintain the required inlet temperature to 106-D. The methanation reactions go almost to completion. The total amount of carbon oxides in the

Section 4 – Overview

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effluent from 106-D is <5 ppmv, and the outlet methane content at design conditions (EOR) is 2.20 mol%. A small amount of synthesis gas is drawn from 106-D downstream Methanator Effluent Separator for the hydrotreating in 101-D. 25. Drying The synthesis gas drying system is shown on Process Flow Diagram. In preparation for drying, the effluent from 106-D is cooled by heat exchange with methanator feed in Methanator Feed / Effluent Exchanger 114-C. The methanator effluent gas is cooled by cooling water in the Methanator Effluent Cooler 115-C to 38ºC, then combines with recycled synthesis loop purge from the Ammonia Scrubber 124-D (for 2160 MTPD case) and further cooled to 4°C by ammonia refrigerant in the Methanator Effluent Chiller 130-C1/C2. The chillers use boiling liquid ammonia pool at 15.3 / 1.1 ºC. The liquid ammonia to 130-C1 is supplied from 149-D through a level control valve. The shell vapour compartment of 130-C1 is connected to the corresponding compartment of 120-C i.e. 120-CF4. The vapour from 130-C2 is connected to 120-CF3 through a pressure control valve to ensure that temperature of gas outlet 130-Cs is always maintained above freezing temperature for water. Condensed water from 130-Cs is separated from the gas in the Methanator Effluent Separator 144-D and is pumped by the Process Condensate Pump for 144-D 122-J/JA to the Raw Gas Separator 142-D1. The chilled gas from 144-D flows to the Molecular Sieve Driers 109-DA/DB. The driers contain a solid desiccant with inlet composition of NH3 = 2 - 20 ppmv, CO 2 = 0 – 10 ppmv, and H 2O = 3.6 kmol/h.. Each drier is sized to remove water, ammonia, and carbon dioxide to less than 1 ppmv total (ie 0.5 ppmv, 0.3 ppmv, and 0.2 ppmv) for a 24-hour period on a type 13X Zeolite (alumino silicate) bead. Regeneration and cooling of the driers are done with dry waste gas from the downstream Purifier. For regeneration, the waste gas is heated in Molecular Sieve Regeneration Heater 183-C to 245°C using condensing MP steam. The spent regeneration gas is sent as fuel to the Primary Reformer 101-B. Following regeneration, 109-D is cooled with unheated Purifier waste gas. The drier cycle will be automatic and programmed in the DCS. The complete 48-hour cycle for each vessel is as follows: -

Drying

24 hr

Downflow

Section 4 – Overview

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0.75 hr 2 hr 12 hr 6 hr

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The drying period may be extended / altered based on operational experience, if desired. The rate of depressuring and re-pressuring should not exceed 3.5 kg/cm2/min. If waste gas from the Purifier is unavailable, for instance during startup, a 2 to 3% slip stream of the dried synthesis gas from the active drier is used as regeneration gas. The stand-by period provides some opportunity for minor maintenance, or may be used for parallel operation of both driers. After 109-DA/DB, the synthesis gas flows through the Molecular Sieve Drier Filters 154LA/LB. This is to protect the Purifier plate-fin exchangers downstream from desiccant dust. It is vital to absolutely clean the system upstream of the purifier cold box including all the field installed piping during pre-commissioning. The filter 154-LA/LB guards against further scale/solids that may pass to downstream. Condition of the filter elements must be ensured good all the time with secured installation without damage or bypass. Isolation valves are provided to isolate/inspect one filter any time. 26. Cryogenic Purification The Purifier (137-L) is shown on Process Flow Diagram. Dried raw synthesis gas from the Molecular Sieve Driers 109-DA/DB is cooled to -129°C in the Purifier Feed / Effluent Exchanger (132-C), which is a plate-fin exchanger. The gas then flows through the Purifier Expander 131-JX, which is a turbo expander. Here work energy is removed to develop the net refrigeration required for the Purifier. The removed energy is recovered as electricity in Purifier Expander Generator 131-JG. The expander effluent is further cooled and partially condensed in Purifier Feed / Effluent Exchanger (132-C). The process stream then enters the Purifier Rectifier 137-D, which is a trayed column. Liquid from the bottom of Purifier Rectifier 137-D is let down to a low pressure and partially vaporized in the shell side of Purifier Rectifier Condenser 134-C. The pressure let-down causes a temperature drop in the stream. The colder low-pressure stream cools the overhead from 137-D, which flows on the tube side of 134-C, and generates reflux for 137-D. 134-C is a shell-and-tube heat exchanger. The bottoms stream from 137-D contains the excess nitrogen, which was added in Secondary

Section 4 – Overview

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Reformer 103-D as well as the excess methane from exit the 103-D. That leaves the purified synthesis gas with a hydrogen-to-nitrogen ratio of ~3 to 1, as needed for ammonia synthesis. The condensed excess nitrogen contains all of the methane and about 60% of the argon in the raw synthesis gas. The partially vaporized liquid leaving the shell side of 134-C is completely vaporized and reheated to 1.8ºC by exchange with Purifier feed in 132-C, and then leaves the Purifier as waste gas. The waste gas is used to regenerate the Molecular Sieve Driers 109-DA/DB, and is then sent as fuel to the Primary Reformer 101-B. During periods when drier regeneration is not needed, the waste gas is sent directly to the fuel. Other minor waste fuel streams are combined with the purifier waste gas and sent to the 101-B burners. The top product from 137-D is purified synthesis gas. It is reheated to 1.8ºC in 132-C by exchange with Purifier feed, and then sent to the Synthesis gas Compressor 103-J (on FD-4). The only impurities left in the purified synthesis gas are 0.19 mol% argon and traces of methane. The Purifier is controlled to maintain a hydrogen-to-nitrogen molar ratio of ~3 to 1 at the inlet to Ammonia Synthesis Converter 105-D. The control is done by adjusting the work taken out in 131-JX, and by adjusting the letdown valve on the bottoms stream from 137-D. Since changes to 131-JX and the letdown valve take some time to work their way through the Purifier and the synthesis loop, the adjustments are made manually. This is described in detail in the Operating Philosophy. To guide the operation, analyzers are provided on the purified synthesis gas and on the inlet to 105-D. The Purifier Cold Box is the heart of KBR’s Purifier ammonia process. Besides the main function described above, namely removal of methane and argon with the excess nitrogen, the Purifier provides several other advantages, as follows: - The Purifier can accept variations in the hydrogen-to-nitrogen ratio in the feed, while maintaining the ~3 to 1 ratio in the purified synthesis gas. This provides flexibility of operation in the front-end of the ammonia plant. Upset in flow of process air or firing in reformer furnace and consequent variations in H2/N2 ratio exit methanator do not affect the synthesis loop. - The Purifier design can accept variations in the methane, carbon monoxide and carbon dioxide contents in the feed, caused by variations in the feed NG composition or in operation of the reforming, shift and methanation sections. Thus upsets in the quality of methanator outlet gas during transient operations are smoothened as the Purifier will reliably remove the impurities thus the Synthesis loop remains unaffected. - Purifier does not require maintaining low methane in synthesis gas (since methane is anyway removed) so the plant has more flexibility in shutdown planning in event of catalyst deactivation in front-end. - Purifier provides purer make-up gas to synthesis loop which aids with in long ammonia Section 4 – Overview

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synthesis catalyst life and steady sustained performance. The purge gas from the ammonia synthesis loop is recycled to the Purifier for hydrogen recovery in 2160 MTPD case. No separate hydrogen recovery unit is needed. All the equipment and piping in the Purifier (except for 131-JG) are enclosed in a cold box filled with Perlite insulating material. This results in a very low heat leak into the system. The cold box is continuously purged with nitrogen, to prevent moisture ingress. Over time, ice may build up in the feed pass of 132-C, and/or solid carbon dioxide may build up in the feed pass of 132-C. This may cause pressure drop increase in those passes. It may also cause some loss of heat exchange, so that a higher pressure drop is needed in 131-JX to maintain the ~ 3 to 1 hydrogen-to-nitrogen ratio in the synthesis gas. The ice and carbon dioxide may be removed by deriming the Purifier with nitrogen. The upstream part of the ammonia plant can be kept running, with venting synthesis gas downstream of Methanator Effluent Separator 144-D. The synthesis loop needs to be stopped, but can stay warm. Nitrogen is preheated to about 35ºC in Molecular Sieve Regeneration Heater 183-C, and injected into the line from 132-C to 137-D. From here, the nitrogen can be routed backwards through the feed path of 132-C (with 131-JX on bypass and the outlet valve open), forwards through the synthesis gas path of 137-D, 132-C, and forwards through the waste gas path of 137-D, 134-C, 132-C. The exiting nitrogen is disposed off to the vent.

27. Synthesis Gas Compression The synthesis gas compression system is shown on Process Flow Diagram. The purified make-up synthesis gas is compressed to the synthesis loop pressure in the Synthesis gas Compressor 103-J, which is a two-casing centrifugal compressor. In the first casing, the gas is compressed from 32.5 to 83.3 kg/cm2 (A). The gas then flows to the Synthesis gas Compressor 1ST Intercooler 116-C, which is cooled with cooling water. The second compressor casing compresses the synthesis gas to 157.9 kg/cm2 (A). Recycle gas from the synthesis loop is added to the make-up synthesis gas before the last wheel of the second casing, at a pressure of 150.1 kg/cm2 (A). The synthesis gas compressor speed is controlled to maintain the suction pressure to the first stage. A kickback is provided from the discharge of 116-C to the suction of 103-J, to protect the first stage of 103-J against surging. Recycle gas, which is available at a temperature of 32ºC, is used for anti-surge kick-back on the second stage. The synthesis loop itself acts as anti-surge protection for the recycle wheel.

Section 4 – Overview

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103-J is driven by the Steam Turbine 103-JT that uses HP steam produced in the ammonia plant. Some of the steam is extracted as MP steam, and the remainder of the steam is condensed. 28. Ammonia Synthesis The ammonia synthesis loop is shown on Process Flow Diagram. The synthesis loop consists of the Ammonia Converter Feed / Effluent Exchanger 121-C, Ammonia Synthesis Converter 105-D, Ammonia Converter Effluent / BFW Preheater and Steam Generator 123-C1/C2, Ammonia Converter Effluent Cooler 124-C1/C2, Ammonia Unitized Chiller 120-C, Ammonia Separator 146-D and the recycle wheel of Synthesis gas Compressor 103-J. The converter feed is preheated in 121-C up to 175.6 oC. The preheated gas is fed to 105-D. The design ammonia concentration at the inlet to 105-D is 1.79 mol%. Ammonia is produced by reaction of hydrogen and nitrogen: 3H2 + N2

⇔ 2 NH3

The reaction is exothermic and limited by chemical equilibrium. Therefore a run-away reaction cannot easily occur. The design ammonia content in the converter effluent stream is 20.31 mol%. 105-D uses KBR’s three-stage horizontal converter design. This is a cold wall pressure vessel design where feed gas at relatively lower temperature is passed through the annular space between basket and pressure vessel to keep the pressure vessel cooler which makes the converter mechanically robust and cost effective. 105-D contains a removable basket, which includes four fixed-beds of catalyst and two built-in heat exchangers. The gas flow pattern in 105-D is arranged such that all of the synthesis gas passes through all of the catalyst. This results in maximum conversion. Each catalyst bed is filled with mostly 1.5 to 3.0 mm of promoted iron catalyst. The converter feed is split into three streams. The first stream (about 60% of total flow) passes through the annulus of 105-D, cooling the outer shell, and is then heated against bed #1 effluent in the Ammonia Converter Bed 1 Interchanger 122-C1. The second stream is preheated against bed #2 effluent in the Ammonia Converter Bed #2 Interchanger 122-C2. The third stream is not preheated and is fed directly to the inlet of bed #1 to control the inlet temperature. The three streams are mixed, and the total gas passes through catalyst in bed #1, is cooled in 122-C1, passes through catalyst in bed #2, is cooled in 122-C2, and passes through catalyst Section 4 – Overview

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in beds #3A and #3B. As there is no cooling between beds #3A and #3B, these beds serve as a single thermodynamic bed. By adjusting the three-way split of converter feed to 105-D and by adjusting the BFW flows and its bypass in 123-Cs, the inlet temperature to each of the beds can be individually controlled. Following are estimated inlet and outlet gas temperatures for each bed at the end of run (EOR), actual optimum temperatures, generally lower than the EOR, will be determined in operation after commissioning to maximize per pass ammonia conversion: EOR Inlet Temperature Operation deg C Bed-1 380 Bed-2 400 Bed-3 A/B 391

Outlet Temperature deg C 527 478 446

Outlet NH3 Concentration mole% 10.89 16.25 20.31

A fresh charge of ammonia synthesis catalyst will need to be activated (reduced). This is accomplished with synthesis gas from the front end of the ammonia plant. The gas is circulated through the synthesis loop by 103-J and is heated up in Startup Heater 102-B. 102-B is fired with NG. The conditions in 105-D are controlled carefully to obtain a proper reduction rate and complete reduction of the catalyst. The catalyst beds are reduced in sequence. The reduction generates water, which is separated in 146-D. To reduce the time needed for catalyst reduction, the first bed is typically charged with pre-reduced catalyst. 102-B is also used during subsequent plant start-up’s, to heat the catalyst in 105-D to a temperature where the synthesis reaction is self-sustaining. Catalyst reduction is performed following the heating-up criteria provided by the catalyst vendor. Water moisture content in the gas passing through catalyst as well as temperature rise is controlled accordingly to fully activate the catalyst. The converter effluent is cooled first by generating HP steam and preheating BFW in Ammonia Converter Effluent / BFW Preheater and Steam Generator 123-C1/C2. These exchangers are of special KBR-design with removable U-tube bundles, and water/steam on the tube side. Further cooling of the converter effluent takes place by preheating the converter feed in Ammonia Converter Feed / Effluent Exchanger 121-C. The converter effluent from 121-C is then cooled by cooling water in the Ammonia Converter Effluent Cooler 124-C1/C2. Because of the high conversion obtained in 105-D, the dew point of the converter effluent is several degrees above the outlet temperature of 124-C1/C2. This causes the condensation of ammonia to start in 124-C1/C2. This saves refrigeration duty downstream.

Section 4 – Overview

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The converter effluent is further cooled and condensed in the Ammonia Unitized Chiller 120-C. This KBR-proprietary exchanger provides cooling of the converter effluent by heat exchange with recycle gas returning from Ammonia Separator 146-D, and with boiling ammonia liquid at four different temperature levels (14.6°C, -4.5°C, -18.5°C and -33.3°C). This integrated design replaces four separate chillers, cold gas/gas exchangers, four refrigerant knock-out drums and the interconnecting piping. A lot of welding, instrument connections etc, potential source of leakage are eliminated by this simplification beside operator has less to look after and maintain. Mechanically, 120-C consists of multiple concentric tubes, which run through the compartments with boiling ammonia. Synthesis gas recycle from 146-D passes through the inner tubes counter-currently to the converter effluent, which flows through the annular space between the tubes. Thus, the converter effluent is being cooled from the outside by boiling ammonia refrigerant and from the inside by cold recycle gas. The converter effluent is cooled to -17.2°C. The condensed ammonia is separated out in 146-D 2 and is sent to Ammonia Letdown Drum 147-D, which operates at 19 kg/cm (A). In 147-D, the synthesis gas dissolved in the ammonia is flashed out. The flash vapor is sent to the LP Ammonia Scrubber 123-D after joining the inert gas purged from 149-D. Ammonia liquid from the bottom of 147-D is sent to Ammonia Refrigerant Receiver 149-D, then th st to the 4 compartment 120-CF4 and 1 compartment 120-CF1 of the unitized chiller before transferring cold Ammonia to storage. Warm Ammonia from 149-D is directly transferred to Urea plant through 113-J/JA. A small flow of ammonia is always maintained to the top of the packed bed provided on 149-D for ammonia removal. The gas from 146-D is reheated in 120-C, and then returns to the recycle wheel of the Synthesis Gas Compressor 103-J. To prevent build up of inerts (methane and argon) in the synthesis loop, about 2.7% of the vapor from 146-D is purged. The flow rate of the purge is adjusted to maintain the total inert content in the ammonia converter inlet at 3.5 mol%. For 2160 MTPD case, the purge is sent to HP Ammonia Scrubber 124-D, where it is washed by water to recover ammonia before sending the remaining gas to join the feed to purifier cold box. 29. Ammonia Refrigeration The ammonia refrigeration system is shown on Process Flow Diagram.

The refrigeration system provides the following:

Section 4 – Overview

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Cooling of converter effluent in 120-C for condensation of ammonia o Production of cold (-33 C) liquid ammonia product o Production of warm (38 C) liquid ammonia product (normal) Cooling of the makeup synthesis gas in Methanator Effluent Chiller 130-Cs. Condensation of recovered ammonia vapor from Ammonia Distillation Column 125-D for 2160 MTPD case. Condensation of Ammonia vapour from Storage

st Cold liquid ammonia product is produced in the 1 compartment 120-CF1, by flashing of product ammonia liquid from 147-D. The plant can deliver entire product as cold ammonia when required. This will happen if the urea plant, which uses the warm ammonia product, is out of service. The cold ammonia is exported to off-site storage by Cold Ammonia Product Pumps 124-J/JA. A small amount, 0.2%, of steam condensate is injected into the cold ammonia product, to protect against stress corrosion cracking in the storage tank. When urea plant is tripped, the refrigeration compressor 105-J is sized to produce all cold ammonia product at full capacity. When Urea plant is in operation, 1595 MTPD ammonia is produced as warm product whereas 405 MTPD of cold product is produced. Refrigerant and return vapor for 130-Cs is integrated with the warm compartments of 120-C, as explained earlier. Ammonia vapors from the four compartments of 120-C, and from off-site storage are routed to the appropriate four stages of the Ammonia Refrigeration Compressor 105-J. 105-J has kickbacks to provide turndown capability and to protect against surge. The ammonia vapor is 2 compressed to 16.2 kg/cm (A), which is high enough to allow condensation with cooling water. 105-J is a four casing centrifugal compressor. It is driven by a Steam Turbine 105-JT, which uses HP steam and discharges to the MP steam header. The compressed ammonia is condensed in Refrigerant Condenser 127-C, and flows to the Refrigerant Receiver 149-D. From here, it can be exported as warm ammonia product by the Warm Ammonia Product Pumps 113-J/JA. The warm ammonia product is routed to the urea plant. A small slipstream is used as reflux in the ammonia recovery system. Ammonia Injection Pump 120-J is provided for use during reduction of Ammonia Synthesis Catalyst. The pump is used initially to inject ammonia to process gas to avoid ice formation from catalyst reduction water in absence of ammonia during very early stages of catalyst reduction.

Section 4 – Overview

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Ammonia from the Ammonia Letdown Drum 147-D enters to 120-CF4 and 149-D as described above. Depending upon the production mode, cold or warm, the liquid from 147-D is diverted to either 120-CF1 or to 120-CF4. Liquid refrigerant ammonia cascades from higher pressure compartment to lower pressure through level control to meet the refrigeration duty. 30. Loop Purge Ammonia Recovery (2160 MTPD Case) The ammonia recovery system is shown on Process Flow Diagram. As described above, the loop purge gas is sent to the Ammonia Scrubber 124-D, which has two beds of packing. In 124-D the purge gases are scrubbed with water to recover ammonia as an aqueous ammonia solution. Similarly flash and inert gases are combined and washed off ammonia in 123-D, the outlet aqueous ammonia is combined with that from 124-D through pump 160-J/JA. The aqua-ammonia solution is preheated in the Ammonia Distillation Column Feed / Effluent Exchanger 161-C, and then fed to Ammonia Distillation Column 125-D. 125-D has two packed beds in the stripping section, and one packed bed in the rectifying section. In 125-D the ammonia is distilled out of the aqua-ammonia solution, and pure ammonia vapor is sent to Ammonia Refrigerant Condenser 127-C. Distillation heat for 125-D is provided by the Ammonia Distillation Column Reboiler 160-C, which is heated with condensing MP steam. Reflux for 125-D is provided by liquid ammonia from the Warm Ammonia Product Pumps 113-J/JA. The ammonia-free purge gas leaving from the top of 124-D is recycled to downstream of the Methanator Effluent Cooler 115-C. The circulation of the scrubbing water is accomplished by cooling the water from the bottom of 125-D in 161-C, raising the pressure in the Ammonia Scrubber Feed Pumps 161-J/JA to feed it to 124-D. Water circulation to 123-D is achieved through 161-J/JA. To maintain water balance in the ammonia recovery system, a small amount of steam condensate from 160-C is added to the bottom of 125-D. A bypass is provided on 124-D, for use if the ammonia recovery system is out of service. 31. Process Condensate Stripping The process condensate stripping system is shown on Process Flow Diagram. The process condensate from Raw Gas Separator 142-D1 contains dissolved impurities including ammonia, methanol and carbon dioxide. The process condensate is preheated in the Condensate Stripper Feed / Effluent Exchanger 188-Cs and sent to the Process Condensate

Section 4 – Overview

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Stripper 130-D. 130-D has two packed sections. In 130-D, the impurities are removed from the process condensate by stripping with live MP steam. The stripped condensate is cooled in 188-C, and further cooled to 390C by cooling water in the Stripped Condensate Cooler 174-C. The cooled, stripped condensate is exported to the offsite polisher for reuse as demineralized water. The steam leaving the overhead of 130-D contains impurities from the process condensate. This steam is mixed with the remaining bypass MP steam, and sent to the process feed gas / steam mixing to prepare reformer mixed feed for preheating. The impurities are broken down in Primary Reformer 101-B and will not be discharged to the environment. It is expected that proper stripping can be achieved with a steam-to-condensate flow ratio of ~0.3 to 1. To assure performance during contingency, 130-D is designed for a steam to condensate mass ratio of 0.4 to 1. It is cautioned that the use of steam ratios higher than 0.3 to 1 may cause the stripped condensate to become acidic and thus aggressive to metals. Consequently, the pH of the stripped condensate should be monitored closely at all times and lower steam be used to get right balance between pH and condensate quality. 32. Steam System The normal steam balance of the ammonia plant is shown on Steam Balance Flow diagram. The ammonia plant uses three steam levels – HP, MP, and LP. The MP steam header is connected to the overall OSBL plant steam system. The steam header conditions are as follows Header

Pressure

Temperature

High Pressure (HP)

123.1 kg/cm2 (G)

510 0C

Medium Pressure (MP)

46.9 kg/cm2 (G)

386 0C

Low Pressure (LP)

3.5

kg/cm2 (G)

236 0C

The ammonia plant generates HP steam in the Secondary Reformer Waste Heat Boiler 101-C, in the HTS Effluent / BFW Preheater and Steam Generator 103-C1/C2 and in the Ammonia Converter Effluent / BFW Preheater and Steam Generator 123-C1/C2. A small amount of saturated HP steam is used in the Methanator Startup Heater 172-C. The rest of the HP steam is superheated in the HP Steam Superheater 102-C and in the superheat coil of Primary Reformer 101-B. The superheated HP steam is routed to the synthesis Section 4 – Overview

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gas and refrigeration compressor turbines (103-JT and 105-JT on FD-6). In 103-JT, a part of the steam is extracted at the MP level, and the rest is condensed in the Surface Condenser 103JTC. The vacuum condensate is pumped to offsite by the Condensate Pumps 123-J/JA. 105-JT is a back-pressure turbine, discharging at the MP level. During start up of the plant, until the Ammonia plant reaches a certain level of plant rate to make it self sufficient in steam production / consumption, MP steam is imported into Ammonia plant frpm offsites Package Boiler. MP Steam not used in ammonia plant is exported to OSBL. The ammonia plant design normally exports 37 t/h of MP steam. As the plant is started-up sequentially, after bringing the synthesis loop online, ammonia plant will produce enough HP steam and reach to its MP steam export mode. The MP steam header is configured to be heated / pressurized by importing steam at the start-up. A letdown station with a desuperheater is provided from HP to MP steam. It is normally not unused, as 103-JT is adjusted to meet all the demand of the MP steam to maximize energy efficiency of the overall system. MP steam obtained from 103-JT and 105-JT is used to supply steam required by the process, as follows: - Process steam to Primary Reformer 101-B. Part of his steam flows through the Process Condensate Stripper 130-D. - Process steam to the air line to Secondary Reformer 103-D. - Steam to Ammonia Distillation Column Reboiler 160-C. - Steam to Mol. Sieve Regeneration Heater 183-C. - Steam to LTS Startup Heater 175-C. The condensate from the last three services 160-C, 183-C and 175-C is routed to the Deaerator 101-U. MP steam is also used to drive ID / FD Fans, Semi Lean Solution Pump 107-JB, Lean Solution Pump 108-J, BFW Pump Turbine 104-JT, Feed Gas Compressor 102-J and Process Air Compressor 101-J. The exhaust from 104-JT and 102-JT goes to a surface condenser 102-JTC whereas exhaust from 103-JT goes to Surface Condenser 103-JTC and from 101-JT goes to Surface Condenser 101- JTC. From here the vacuum condensate is pumped to DM Water header inlet 109-C by Condensate Pumps 118-J/JA (on 101-JTC), 119-J/JA (on 102-JTC) and 123-J/JA (103JTC). 119-J/JA pumps also supply the water jackets in the reforming section. LP Steam header is fed from ID / FD fan exhaust steam, Semi Lean Solution Pump 107-JB, Lean Solution Pump 108-J exhaust steam, blowdown vessel 186-D and MP/LP steam letdown Section 4 – Overview

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(normally closed). LP steam is used by the following: - 101-JT, Turbine for 101-J Process Air Compressor - Deaerator 101-U - Turbine Gland steam - Surface Condenser Ejectors - Service/utility stations Demineralized water from offsite along with turbine condensate from 118-Js, 123-Js and 119-Js is preheated against OASE solution in 109-C followed by LTS effluent in LTS Effluent / DMW Exchanger 106-C. The preheated water flows to 101-U. 2 The pressure in 101-U is maintained at 1.73 kg/cm (G). BFW from 101-U is pumped by BFW Pumps 104-J/JA and is preheated in 131-C, LTS Effluent BFW Preheater. The BFW is then split and heated in parallel by 103-C1/C2 and by 123-C1/C2. About 25% vaporization of the BFW takes place in the 103-C’s while about 22% vaporization takes place in the 123-C’s. These values are set to assure proper flow patterns in the heat exchangers. Both 103-C and 123-C have their maximum vaporization limits that must be followed in operation. 103-C can have up to 30% vaporization whereas 123-C can have up to 25%. The partially vaporized BFW is fed to Steam Drum 141-D. 141-D blowdown is flashed in186-D, which floats on the LP steam header. For the protection of the steam system against scaling and corrosion, the following chemical injection systems are provided: - Oxygen Scavenger Injection System 106-L, injecting into 101-U - Ammonia Injection system 107-L, injecting into 101-U - Phosphate injection system 108-L, injecting into 141-D

33. Steam System Controls The steam system is described here in very brief from a control prospective, as following. The operating philosophy and control narratives provide more details. The MP steam header is common between ammonia and offsites. Further MP steam is normally supplied by ammonia ISBL to OSBL. HP steam header ISBL ammonia will have its own HP to MP letdown station with fast acting control valves to letdown steam in case of tripping of 103-J and / or 105-J. During start up phase MP header imports MP steam from OSBL Package Boiler or from OEP MP steam header through a batterly limit import station in Ammonia Plant.

Section 4 – Overview

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An MP steam pressure control valve is provided at the battery limit on the MP header to avoid loss of steam from ammonia in case of OSBL disturbances. HP steam temperature control is normally done by adjusting firing in 101-B steam superheater burners with a back-up BFW desuperheater is also provided. The MP steam header pressure is normally controlled by 103-JT extraction through the turbine governor system. A back-up pressure controller is provided to open the letdown valve after first adjusting the 103-JT HP governor valve in case of falling MP header pressure. A separate back-up pressure controller is provided to avoid excessive rise of MP header pressure by venting it through quick acting pressure control valves to silencer.

34. Cooling Water System The cooling water is supplied from offsites at a temperature of 330C and is used for major cooling loads like surface condensers 102-JTC, 101-JTC and 103-JTC and ammonia condenser, 127-C. To lower cooling water usage, the surface condensers, 101-JTC, 102-JTC and 103-JTC are placed in series with the Ammonia Condenser, 127-C. Cooling water return temperature is approximately 42.8oC. CW supply shall be lined-up to various ammonia exchangers after initial cleaning and flushing of the supply header after mechanical completion. Special care shall be taken in ensuring that no debris and scale are pushed to the last exchanger in the circuit. The quality of the cooling water is controlled in the OSBL, special attention should be paid to filter the CW supply using screen to ensure debris and solids are not carried to ammonia exchangers anytime. CW flow distribution shall be optimized/ balanced at start-up and it will not be selectively trimmed later on. For reliable operation, it is mandatory to maintain velocities through each exchanger circuit close to the design value even if the heat exchanger is able to perform adequately at lower CW flow rate. Solid precipitation and fouling will occur due to low velocity (if flow is reduced below design) which may be followed by under deposit corrosion and exchanger leakage/failure. 35. Front-End Startup Heating Although later in this philosophy we provide the details, only the key points will be covered here. While starting-up from cold conditions, the process system from “Feed Preheat Coil inlet” to “Raw Gas Separator” will be heated up to well above the dew point of steam before charging

Section 4 – Overview

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steam to the catalyst. This is to positively avoid steam condensation over the various catalysts in the path. Bypassing in 101-C / 102-C will be opened during this heating to heat-up the HTS and downstream effectively. The BFW around the cold bundle of 103-C will be bypassed. N2 will be circulated through the above circuit using 102-J, the Feed Gas Compressor and 101-B firing is used to heatup step-wise. Besides heating up catalyst, this procedure will also help in avoiding steam condensation over the 103-C fins which is important in minimizing its scaling and fouling. The 102-J has been specified to perform the dual duties of front-end N2 circulation. 36. Process Steps After 131-J Trip If 131-J trips in operation and can not be restarted immediately such that cold box needs to be isolated due to lack of refrigeration, process gas will be bypassed and vented down stream. The back-end should be kept pressured till 131-J is started-up again, cold box is line-up fast as it will be still cold and should have liquid hold-up. Alternatively operation of the backend with purifier bypassed at low load may be carried on.

Section 4 – Overview

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5. Process Operating Principles 37. Natural Gas Supply The inlet normal Natural Gas compositions are as follows: Main

Inlet

N2 CH4 C2H6 C3H8 iC4H10 nC4H10 iC5H12 nC5H12 C6+ CO2 H2O S Mercury

1.00 % 82.78 % 6.04 % 3.41 % 0.55 % 0.66 % 0.26 % 0.14 % 0.25 % 4.91 % 0.00 % ≤15 ppmV (Design) <100 µg/Nm3

Natural Gas, which is used for feed is available at battery limit with a blindable isolation valve with a 1” gate valve equipped bypass. 50,770 kg/h. of feed gas and 10,172 kg/h of fuel gas at 30°C and 15.0 kg/cm²a are initially directed to the Feed Gas Knockout Drum 174-D, where any entrained liquids are removed. Any liquid from 174-D is withdrawn through control valve routed for proper disposal as needed. The total inlet gas stream to 174-D is DCS instrumented which differentiated to high and low range for monitoring using: High Range Low Range FI-1042A : compensated flow with low alarm FI-1042B : compensated flow with low alarm PI-1073 : pressure with low alarm TI-1308 : temperature The flow is compensated for pressure (PI-1073), temperature (TI-1308) and MW (FN-1042C) in the DCS function block FN-1042A (high range)/ B low range, and is totalized on FQI-1042A/B. The low range DCS instrumentation is use when initial start up due to inlet gas stream flows from line, and the high range is use in normal operation. A local pressure indicator PG-7521 is also provided. The temperature can be seen locally on TW/TG-1609 Section 5 – Process Operating Principles

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AE-1036 is installed at 174-D outlet measuring 6 components:  CH4 shown on the DCS on AI-1036A 

C2H6

shown on the DCS on AI-1036B



C3H8

shown on the DCS on AI-1036C



N2

shown on the DCS on AI-1036D



CO2 C4H10

shown on the DCS on AI-1036E



shown on the DCS on AI-1036F

It has a DCS alarm, XA-1110B for Instrument failure. Manual grab sample point is provided. Between the inlet isolation valve and the 174-D is a nitrogen purge line N1006-1.5”. Local pressure indicator PG-1690 shows the nitrogen purge pressure. A 6” bypass line takes off upstream 174-D carrying fuel NG to 101-B and 102-B burners. 174-D is provided with a level gauge LG-1602 and DCS level indicators LI-1227A/B/C with high level alarms leading to I-102J on 2oo3 voting logic. XA-1227A/B/C is generated in case of transmitter failure. After the gas passes through 174-D there are take offs for : 1. Gas to Feed Gas Compressor 102-J—NG1001-14” 2. Gas to 101-B Arch, tunnel and superheat burners and 102-B burners—NG1102-6” The downstream of 174-D joins natural gas to Feed Gas Compressor 102-J in line NG1001-14”. This line also has a tie in from line SG1500-2” start up hydrogen from OEP. The 174-D drum contains an inlet gas sparger nozzle and a demister pad covering the vapor outlet nozzle. Any level that accumulates in the drum will be automatically drained by LV-1002 to a condensate header leading to burner pit. A local pressure indicator, PG-1690, has also been installed downstream of 174-D.

Section 5 – Process Operating Principles

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38. Feed Gas Compression Feed gas exits the 174-D in line NG1001-14” for compression by feed gas compressor 102-J. Before NG enters the 102-J, about 2 vol% recycle hydrogen is added through FIC-1703 acting on FV-1703. FV-1703 is provided with recycle gas from 144-D (in case 2000 MTPD). 102-J inlet temperature is locally indicated at TW/TG-1619 and the inlet pressure is locally indicated at PG-1603. Discharge temperature and pressures are indicated locally at TW/TG1620 and PG-1604 respectively. PI-6271 and PI-6272 indicate the suction and discharge pressures whereas and TI-6170 and TI-6172 indicate the suction and discharge temperature respectively on DCS. The machine has an inlet strainer SP-STR-102J. 102-J is driven by STEAM TURBINE drive motor receiving signal from PIC-1007 at the exit of 101-D and 108-DA. Anti-surge controller for 102-J, FIC-1130 receives inputs from PI-6271A and TI-6170A on the suction and PI-6272A and FT-6172A on the discharge side. The discharge flow is indicated on DCS at FI-6130. FIC-1130 controls FV-1130 which fails open on loss of instrument air or loss of control signal. FV-1130 is a tight shut off class valve. The open or close indications from FV1130 are indicated on DCS at FZLO-1130 and FZLC-1130 respectively. The kick back flow from FV-1130 is cooled on the shell side of 143-C by cooling water. The NG exit line from 143-C NG1015-10” has a local TW/TG-1621 and the line joins the NG header upstream 174-D. 143-C can be isolated with butterfly valves on the cooling water side. The cooling water exit temperature from 143-C is indicated locally at TW/TG-7206. 102-J manual shut down switches HS-1310 and HS-1310A are provided locally and on the control room panels respectively. XA-1310 provides the running lamp indication on DCS.in case of a manual shutdown. 102-J discharge line is protected against over pressure by PRV-102J reliving into front end flare header at a set value of 58.3 kg/cm2G and has a bypass line with a double block and bleed arrangement. Compressed NG is preheated in 101-BCF. Before the NG enters the Hot Feed Preheat Coil 101-BCF about 2 vol % recycle hydrogen is added through FIC-1022 acting on FV-1022. FV1022 is provided with recycle gas from 124-D (in case 2160 MTPD). 2 FV-1022 has a double block and bleed arrangement and has a globe valve on a bypass line.

FIC-1022, provided with a high and a low alarm. Recycle hydrogen line joins the NG line through a check valve to prevent back flow of NG into the recycle gas system. The line is installed with a check valve and a block valve with a spectacle blind. end flare header. Upstream of 101-BCF there is a start-up nitrogen tie in line N5000-1.5”. It has a double block, Section 5 – Process Operating Principles

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with the upstream valve being a gate valve and a non return valve to prevent backflowing of gas/steam. There is also a figure ‘8’ blind for positive isolation. NG temperature exiting the Feed Preheat Coil 101-BCF coil is controlled by a bypass line with TV-1305 control valve. TV-1305 is controlled by TIC-1305 which ties in downstream of the bypass. TIC-1305 is DCS indicated and has a high and low alarm. DCS temperature indication TI1612 shows the temperature exit the coil and has a high alarm associated with it. 39. Hydrotreater and Desulfurizers (101-D and 108-DA / DB) The inlet and outlet design gas compositions are as follows:

H2 N2 CH4 Ar CO2 C2H6 C3H8 S (H2S)

= = = = = = = =

Inlet 2.00 % 1.97 % 80.30 % 0.01 % 4.76 % 5.85 % 3.31 % 15 ppmv

Outlet 2.00 % 1.97 % 80.30 % 0.01 % 4.76 % 5.85 % 3.31 % ≤0.1 ppmv

The Natural Gas feed flows through the feed preheat coil, 101-BCF, of the 101-B primary reformer to the inlet of the 101-D Hydrotreater. A temperature control bypass valve TV-1305 is provided around the feed preheat coil to provide a means of controlling the temperature of the feed gas entering the hydrotreater at 371 °C. There is a high and low temperature alarm with this DCS controller. The valve will fail closed if control signal or instrument air is lost and a handjack is furnished for manual operation. The temperature directly out of the preheat coil can be seen in the DCS on TI-1612 and has a high alarm. The coil and the downstream piping to the TV-1305 tie-in are designed for 447°C at 58.3 kg/cm²g. The heated feed gas then enters the Hydrotreater Vessel, 101-D, where any quantities of organic sulfur compounds are hydrogenated to hydrogen sulfide, H2S, in a bed of cobalt / molybdate (Co-Mo) catalyst. The H2S in the gas reacts with and is retained in a bed of zinc oxide (ZnO), producing an effluent stream containing less than ≤0.1 ppmv sulfur by volume. There are two ZnO beds in this unit,108-DA and 108-DB. The zinc oxide in each desulfurizer will need replacement approximately every 18 to 24 months based upon 25% absorption on the catalyst at ≤17.5 ppm content of sulfur compounds in the Section 5 – Process Operating Principles

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Natural Gas at 100% of normal flows for every day of the year.The lifetime is 2 years at 15 ppm sulfur max. If the sulfur content in the gas is less, the catalyst (absorbent) will last longer. The Co-Mo catalyst has an approximate 12 year lifetime. The 101-D and 108-DA/DB all have inlet and outlet gas distributors. The outlet distributor is screen covered to avoid loss of catalyst and support material to the process. There is one bed of catalyst, Cobalt - Molybdate, in 101-D and a bed of adsorbent, Zinc Oxide, in each 108DA and 108-DB vessel. Each vessel also has a catalyst dropout chute to unload the catalyst. Loading and unloading of the catalyst will be discussed later in section 6 of this manual. The 101-D has a local pressure indicator as well as a DCS pressure differential indicator. 101-D is monitored by PG-1721 for pressure and PDI-1105A with a high alarm for pressure differential. A sample point has also been placed on the outlet line that ties into a common line going to a sample cooler for grab sampling. The line has a gate valve for isolation and a upstream gate and a needle valve for sample flow control. The 108-DA and 108-DB have local pressure indicators as well as DCS pressure differential indicators. 108-DA is monitored locally by PG-1722 for pressure and PDI-1105B with a high alarm for pressure differential. 108-DB is monitored by PG-1723 for pressure and PDI-1105C with a high alarm for pressure differential. There are local outlet temperature indicators with TW/TG-1602 on 108-DA and TW/TG-1603 on 108-DB. Sample connection is located on the common outlet line with sample line from exit of each of the ZnO beds going to a sample cooler for grab sampling. Each line has a gate valve for isolation and an upstream gate and a needle valve for sample flow control and a bleed valve in between for positive isolation to prevent cross-contamination. Maintenance blinds are provided inlet, outlet, and on the crossover lines to each of the108-DA/DB vessels. A double block and bleed system is provided on each of the vent lines from each vessel outlet. Normally, the desulfurizers operate in series, but provision is made in the installation to allow single reactor or even parallel operation during catalyst change out while the plant remains in operation. The piping arrangement allows for either vessel to be the leading or the following vessel in the series operation. Each vessel is also equipped with a double block and bleed vent line that goes to the front end vent system. V1092-1.5” for 108-DA and V1091-1.5” for 108DB. Exit pressure 108-DA/DB can be seen locally on PG-1626. The common desulfurizer outlet line also has a manual vent valve in line V1090 to the hot vent vent system. This line will be used for start-up and shutdown activities only.

Section 5 – Process Operating Principles

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The overall reaction in the desulfurizers is exothermic but a heat loss of 11°C has been used for design purposes thus the exit temperature at 360°C but the actual temperature should follow within just a few degrees of the inlet temperature. Sulfur exit the 108-Ds is monitored in the DCS on AI-1107 with a high alarm and DCS alarm XA-1107 will sound upon a failure of the analyzer. Just downstream the common sampling point on the 108-DA/DB common exit line, takes off NG1021-8” for startup purposes. The flow is controlled by HIC-1107 acting on HV-1107, which fails close on loss of instrument air or control signal. It has a double block and bleed arrangement. 40. Primary Reformer The inlet and outlet design gas compositions of the radiant section at the end of run catalyst life are as follows:

H2 N2 CH4 Ar CO CO2 C2H6 C3H8 C4H10 C5H12 C6+ S

= = = = = = = = = = = =

Inlet 2.00 % 1.97 % 80.30 % 0.01 % 0.00 % 4.76 % 5.85 % 3.31 % 1.17 % 0.39 % 0.24 % ≤0.1 ppmv

Outlet 53.49 % 0.78 % 27.44 % 0.00 % 5.40 % 12.89 % 0.00 % 0.00 % 0.00 % 0.00 % 0.00 % ≤0.1 ppmv

The Primary Reformer, 101-B, is a gas fired, processing furnace containing radiant and convection sections. The pressure drop is around 4 kg/cm2G. Processing occurs in catalyst packed tubes contained in the radiant section. The desulfurized feed is mixed with 356°C medium pressure steam, part of which was used to strip the process condensate beforehand. The steam is added in a ratio of 2.97 moles of steam per mole of feed gas and 2.67 to 1 steam to gas weight ratio. The desulfurized Natural Gas flow rate to the 101-B radiant section is 51,640 kg/h and is controlled by DCS controller FIC-1001. FV-1001 valve fails closed if the instrument air is lost. It will be tripped closed by action of solenoid FY-1001 upon any feed gas trip and the solenoid has to be manually reset with HS-1001 before automatic control can be started again. FV-1001 valve Section 5 – Process Operating Principles

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position is shown in the DCS on FZSO-1001 and FZSC-1001. FIC-1001 is pressure and temperature compensated using PIC-1007 pressure and TI-1307 temperature through FN-1001. FN-1001 also receives a manually input DCS signal from FN-1001A to also correct for the actual molecular weight of the gas. FIC-1001 is furnished with low alarm and a low low feed gas flow trip is incorporated utilizing a separate flow measuring system on the same orifice FE-1201. All of these instruments are monitored in the DCS. The feed NG temperature can be seen on the DCS with TI-1307 indicating the combined outlet of 108-DA and 108-DB and also has a high and low temperature alarm to the DCS and provides input to FN-1001. TT-1204 is installed upstream TI-1307 and is used for temperature compensation in calculation blocks FN-1201-A/B/C. Similarly, PT-1200 located upstream of TT-1204 provides input to FN-1201A/B/C for pressure compensation. PI-1200 and TI-1204 indicate feed NG pressure and temperatures on DCS. XA-1200/1204 indicate transmitter failures on DCS respectively. FN-1201A/B/C leads to a 2 out of 3 voting for initiating I-101J on low low flow. FI-1201A/B/C indicate low flow conditions whereas FALL-1201 is generated upon low low flow conditions. Feed NG low-low flow will initiate a DCS alarm on FALL-1201 and if 2oo3 are low-low, Primary Reformer Process Trip I-101 logic will occur that initiates: 2 - Close XV-1212 process air valve - FV-1003 process air valve set to 0 (zero) kg/h - Preset of FV-1044, MP steam to cold process air coil preset set point to 35,000 kg/h - Activates I-104D2 to bypass the LTS - Activates I-103J to trip 103-J - Close XY-1331 sample to AE-1031 - Close XY-1311 sample to AE-1011 - Activates I-106D Methanator trip - Close XY-1030 sample to AE-1030 - Close XY-1208 sample to AE-1001 - Close XV-1201, mixed feed to 101-B 2 - Preset HV-1108 to set point and release for operator control - Close FV-1001 feed gas to 101-B control valve - Close HV-1061 bypass control valve of feed gas to 101-B - Preset FIC-1002 to set flowrate steam to mixed feed 10,000 kg/h - Preset FV-1019, steam to 130-D set manual output 0% - I-101B Primary Reformer Trip which will initiates :  I-101BBS Superheat burner trip  I-101BBT Tunnel burnes trip 2  Closes XV-1222A/B isolation valves and opens C vent valve on Secondary fuel gas to 101-B - Initiate I-101J process air compressor trip Section 5 – Process Operating Principles

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Initiate I-102J feed gas compressor trip Initiate I-105J ammonia refrigerant compressor trip

This takes the process air out of 103-D Secondary Reformer. Downstream of FV-1001 is trip valve XV-1201 which is an open or close valve which is tied into the I-101 trip circuit and must be reset with HS-1201 after an interlock trip. XY-1201 will activate the trip of XV-1201. DCS indicators ZLO-1201 and ZLC-1201 indicate valve position. Downstream of FIC-1001 control valve, the gas stream is joined by 138,424 kg/h of medium pressure steam controlled by DCS flow controller FIC-1002 with a low alarm after it passes through a blindable non-return valve. A sample cooler has been installed downstream to allow for getting samples of the mixed stream. There is also a permanently piped nitrogen purge line N1001-1.5” tied in downstream of XV-1201 through a double block and bleed system with a non-return valve and a figure eight blind for purging the front end after a shutdown or to help supply nitrogen. FIC-1002 is compensated steam flow signal from calculation block FN-1002 with a bias through DCS function block FN-1002A. This block compensates for the extra / consumed steam from / to the stripped condensate in the 130-D Process Condensate Stripper with manual input in a range of ±3000 kg at HN-1002A. This system will be explained later in more detail. Process Steam Flow is pressure and temperature compensated using DCS PI-1078 and TI-1008 through a function block FN-1002. FV-1002A/B valve fails open when instrument air pressure or the control signal is lost and have handjacks for manual operation. The flow meter run for the process steam is physically located upstream of the MP steam line to the Process Condensate Stripper 130-D. The line can be isolated with a lock open (LO) valve that has a 1” pressuring bypass. The process steam and gas feed to the primary reformer is controlled by a lead / lag control system that is designed to maintain the steam to carbon ratio during upsets. The FN-1002A steam flow signal is directed to FFI-1001 DCS division function block to calculate the steam to carbon mol ratio, FFI-1001 displays on DCS and has a low alarm. It is also directed to division block FFN-1001A where it is divided by the manually set desired steam to gas ratio as input on DCS FFN-1001. The output of FFN-1001A is directed to FFN-1001B low select function block where the lower of that signal or the signal from the manually set desired plant rate is input on HIC-1001 after passing through a ramp rate controller block HN-1001. The output of FFN-1001B low select block will go to FIC-1001 as the remote set point. Corrected feed gas flow from FN-1001 is directed to three function blocks FN-1001B where it is multiplied by the gas carbon number as input manually on FN-1001E to determine the steam Section 5 – Process Operating Principles

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to carbon mol ratio. Output from FN-1001B goes to high selector function block FN-1001C. The higher of this signal or the signal from HIC-1001 desired plant rate, after having passed through a ramp rate block HN-1001 is passed on to FFN-1001D which multiples the gas signal by the desired ratio setting on FFN-1001 and forwards that signal to FIC-1002 as a remote setpoint. Second output signal from FN-1001 goes to FFIC-1003 which calculates the Air/Gas ratio with the other input from FN-1003, the process air flow rate. This process steam flow control system has been designed to react to automatically reduce the gas flow should the steam flow be reduced for any reason to protect the reformer from coking the catalyst. An increase in steam rate for any reason other than an increase on the HIC-1001 plant rate control will not increase the gas rate. In addition, an increase in gas flow to the reformer for any reason other than an increase on HIC-1001 will result in an increase of the steam flow to protect the reformer but a decrease in gas will have no effect on the steam. A Full trip of I-101 Primary Reformer Process 2 Trip FIC-1001 will go to close position. All of the previously mention function blocks and manual input blocks for the lead-lag system are in the DCS. The normal steam to gas weight ratio for Primary Reformer is 2.67. The design steam to carbon molar ratio for Primary Reformer is 2.7. Steam flow measured at FT-1202A/B/C is pressure and temperature corrected in the SIS PLC function block FN-1202A/B/C using pressure and temperature compensation from PI-1053 and TI-1024 respectively. The corrected flow is indicated in the DCS on FI-1202A/B/C. DCS transmitter failure alarm XA-1024 will sound on a TT-1024 failure with XA-1053 alarming on a PT-1053B failure and XA-1202A/B/C used for a FT-1202A/B/C failure. PG-1606 is a local pressure gauge on the medium pressure steam line. The gas stream from FN-1201A/B/C is further compensated for carbon content in the SIS PLC using a manually input factor in bias function blocks FN-1201D/E/F. Manually entered bias via HN-1002A is provided. A bias range of ±3000 kg/h compensated for the difference in flow between MP steam supply to condensate stripper 130-D, and overhead process steam from 130D to primary reformer 101-B. FFY-1201A/B/C are SIS PLC internal ratio measuring blocks which ratio the compensated process steam from FN-1202D/E/F to the compensated process gas from FN-1201D/E/F. SIS PLC will alarm FI-1201A/B/C in the DCS if the steam to carbon molar ratio drops to a low value to alert the DCS operator of a low steam to carbon ratio and an impending process trip. Section 5 – Process Operating Principles

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FFALL-1201 will alarm if the steam to carbon mol ratio drops to low-low value at 2.3 S/C ratio and it initiates the following trip sequence: -

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Close XV-1212 process air valve FV-1003 process air valve set to 0 (zero) kg/h Preset of FV-1044, MP steam to cold process air coil preset set point to 35,000 kg/h Activates I-104D2 to bypass the LTS Activates I-103J to trip 103-J Close XY-1331 sample to AE-1031 Close XY-1311 sample to AE-1011 Activates I-106D Methanator trip Close XY-1030 sample to AE-1030 Close XY-1208 sample to AE-1001 Close XV-1201, mixed feed to 101-B Preset HV-1108 to set point and release for operator control Close FV-1001 feed gas to 101-B control valve Close HV-1061 bypass control valve of feed gas to 101-B Preset FIC-1002 to set flowrate steam to mixed feed 10,000 kg/h Preset FV-1019, steam to 130-D set manual output 0% I-101B Primary Reformer Trip which will initiates :  I-101BBS Superheat burner trip  I-101BBT Tunnel burnes trip  Closes XV-1222A/B isolation valves and opens C vent valve on Secondary fuel gas to 101-B Initiate I-101J process air compressor trip Initiate I-102J feed gas compressor trip Initiate I-105J ammonia refrigerant compressor trip

Control board mounted hand switch HS-1251 can be used to manually trip the process gas and air out of the front end of the unit with the same results as FFALL-1201. Use of this trip switch will activate DCS alarm HA-1251. There is a second DCS flow meter on the MS line to 130-D, FT-1019, which indicates the flow of steam to 130-D. This flow is controlled with FIC-1019/FV-1019 which has a high and low alarm. TI-1646, with a low alarm, denotes the temperature of MS1006-16” to 101-B on DCS. Downstream of MS / Process Gas mixing a syn gas line, SG5003-1½” , from battery limit has also been added for startup. The flow of syn gas is shown in the DCS on FI-6050 and has a non-return valve to prevent back flowing of gas / steam as well as an isolation valve for positive isolation.

Section 5 – Process Operating Principles

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Just upstream of the 101-B mixed feed preheat coil is a tie in line A1008-2” from the 101-J, air compressor, discharge and will be used for decoking to blow the process lines with air. This line has a removable spool piece and will be blinded after use. The combined gas and steam flow at 350°C, as indicated on TI-1310,with a high and low alarm. Mixed Feed is further heated in Primary Reformer convection section in Mixed Feed Preheat Coil 101-BCX. Temperature exit 101-BCX is indicated at TI-1313 with associated high and low alarms. Mixed feed pressure is shown locally on PG-1607 before entering the radiant section. The mixed feed leaves the coil then flows to the top of the radiant section where it is split into six equal and parallel sub-headers. The 6 sub-headers distribute the flow to 288 tubes typically packed with two sizes of nickel reforming catalyst. The tubes extend downward through the radiant section of the reformer to a horizontal bottom collection header. Each of the 6 collection manifolds contains a centrally located riser pipe that returns the flow through the radiant fire box to the Primary Reformer Effluent Transfer Line, 107-D. The transfer line is a refractory lined, water jacketed transition piece connecting the primary reformer with the secondary reformer, 103-D. Each of the collection headers has a double blocked drain for start-up only if steam is used for start-up in place of the normal nitrogen flow. The heat for the endothermic reforming reaction is supplied by ninety-eight (98) fuel gas burners located on either side of the rows of tubes with fourteen (14) burners in each of the seven rows. There are two sizes of burners in the reformer arch section. The burners located between the rows have a heat release design of 2.02 Gcal/h each. The burners between the furnace wall and the outer rows of tubes have a 1.32 Gcal/h design. The outer row burners are designed smaller than the inner row burners, taking into account that they only supply direct radiation to tubes in one direction, while the inner row burners supply direct radiation in two directions. Both Natural Gas and purge gas fuels will be used for normal operation. The burners are designed for design heat liberation for both Natural Gas and purge gas combined, or for Natural Gas alone. Note that these two fuel gas streams will not be combined upstream of the burners, but will have separate burner connections. The furnace arch burners operate firing down and develop a reformed gas temperature of 722°C at the outlet of the catalyst tubes. The normal end-of-run pressure at the outlet of the catalyst tubes is 41.5 kg/cm²G. The reforming furnace incorporates the use of internal manifolding (outlet manifolds) at the outlet of the catalyst tube leading to riser tubes that direct the reformed gases to the transfer line for heat conservation of the reformed gas and balanced coil expansion. The reformed gas continues to pick up heat in these risers and collector pipes while exiting the radiant section. This raises the gas temperature at the primary reformer exit by 16°C to approximately 738°C. The primary reformer is instrumented for monitoring the temperatures and pressures of the

Section 5 – Process Operating Principles

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process and the flue gases. The effluent process stream is continuously analyzed for methane content by AI-1001 on-stream mass spectrometer with low and high alarm. A manual sample cooler has been added to the stream to the analyzer for grab sampling the gas stream. Each row of tubes has two temperature indicators located on each side of the riser tube- TI-1315A through TI-1315F and TI-1316A through TI-1316F. All of the temperatures are indicated on the DCS and all have high temperature alarms. Pressure drop across radiant coil, including the crossover piping on the inlet, is measured by PDI-1101 in the DCS with a high alarm attached. There are also two local pressure gauges, PG-1607 showing inlet pressure and PG-1608 on the outlet. The reforming furnace is designed for 93% calculated fuel efficiency by recovering heat in the convection section from the flue gases. Flue gases consist of combustion products from the radiant section of the reformer. The flue gases are continually analyzed for oxygen content by analyzers AI-1010A and AI-1021A with associated low oxygen alarms and combustibles by analyzers AI-1010B and AI-1021B with high combustibles alarms located on each side of the convection section as the flue gas exits the radiant box and are displayed on the DCS. An additional set of analyzers, AI-1033A for oxygen with a low alarms and AI-1033B for combustibles with a high alarm are located in the convection section downstream of the superheater burners. The expected excess oxygen in the flue gasses is:

Radiant Exit Stack

= =

Mol % O2 Dry Basis 1.74 1.78

fule Combustion air is provided by 101-BJ1/BJ1A, Forced Draft (FD) Fans, normally driven by a MP steam turbines, 101-BJ1T/BJ1AT. Under normal operating conditions, the FD fan provides 147,680/h at a static pressure of 260 mmH2O. Fan discharge pressure, upstream of the preheater, is indicated locally by PG-1031 and PG-1131 and the temperature is indicated on the DCS by TI-1811. TI-1812/1813 with high alarms indicate the temperature of flue gas from feed preheat coil upstream of the combustion preheater.The discharge goes into the combustion air preheater, 101-BC, PDI-1214 and PDI-8011 with a high alarm provides control room indication of the differential pressure at 102 mmH20. Downstream of the preheater, temperature is indicated in the DCS on TI-1810 (with a high alarm) and with PT-1855 supplying a signal to PIC1855(with a low alarm) for control of the inlet guide vanes to the fan. PT-1231A/B/C 1

Section 5 – Process Operating Principles

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supply signal to PSLL-1231A/B/C to feed into the reformer trip circuitry and sounds an alarm in the DCS on PALL-1231 and PALL-1231A in the control room if a low-low pressure exists. DCS alarm XA-1231A/B/C will signal a transmitter failure. Pressure point PP-1812 is provided for further manual check on the duct pressure, if required. The duct exit the preheater provides air to three places: 1. 101-B Primary Reformer arch burners 2. 101-B Primary Reformer convection section superheater burners 3. 101-B Primary Reformer tunnel burners The arch burner combustion air duct branches each have a manually operated damper to control the combustion air pressure to the duct and individual dampers to each of the burners. The tunnel and superheater burners each also have individual adjustments to the burners. The combustion air flows through the burners, mixes with the fuel gas, combusts to provide heat for the reforming reaction to take place and becomes hot flue gases in the radiant and convection sections of the reformer. The flue gases are pulled through the reformer by the Induced Draft, ID, Fans, 101-BJ/BJA. The ID fans are driven by medium pressure steam turbines 101-BJT/BJAT. The hot flue gases are removed from the radiant and convection sections of the reformer, passed through the combustion air preheater, 101-BC, and then exhausted to the atmosphere through a stack. PDI-8011 provides control room indication and high alarm of the differential pressure of the flue gas through the combustion air preheater. 101-BJT/BJAT and 101-BJ1T/BJ1AT are back pressure turbines exhausting steam to the low pressure steam header. The speed of 101-BJT/BJAT is controlled by SI-1006/SI-1106 (with low alarms) based on draft needs. Both turbines will go to maximum speed on loss of control signal or loss of instrument air. Inlet medium pressure steam flow to 101-BJT/BJAT is indicated on the DCS by FI-3122/4122. PG-3849/4849, the steam inlet pressure and TW/TG-3751/4751 temperature are both local indications. TI-3745/4745 indicates steam inlet temperature on the DCS. PG-5128/6128 and TW/TG-5127/6127 have been provided locally in the exhaust line and the exhaust line is protected from overpressure by PRV-101BJT/BJAT set to relieve to the atmosphere at 5.3 kg/cm2G. Inlet steam flow to 101-BJ1T/BJ1AT is indicated on the DCS by FI-5122/6122. PG-5819/6819 indicates the pressure and TW/TG-5751/6751 indicates the temperature locally. The exhaust temperature is indicated locally by TW/TG-5132/6132 and pressure by PG-5133/6133. The

Section 5 – Process Operating Principles

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exhaust line is protected from overpressure by PRV-101BJ1T/101BJ1AT set to relieve at 5.3 kg/cm2G to the atmosphere. Both turbines have ¾” inlet isolation valve bypasses for line warming and pressure equalization as well as an inlet steam strainer. 179,947 kg/h of hot flue gases are normally pulled by the ID fan from the radiant section of the reformer exiting through seven tunnels. The tunnels, and the openings that allow the flue gases into them, are designed to give an equal flow throughout the radiant box of the reformer. Draft will be controlled by PIC-1019A, low range, or PIC-1019B, high range. The normal control will be PIC-1019A with B selected if the FD fan trips or other situations where higher than normal draft is experienced. The hot flue gases flow through the convection section across various coils giving up heat to the fluids in the coils so that as much heat as possible is recovered to make the reformer more efficient. The design Lower Heating Value, LHV, efficiency of the reformer is 93%. The flue gas heats the following coils in the order listed: Coil Design Case

Temperature (0C)

Pressure (kg/cm2G)

Radiant section catalyst tubes Radiant section riser tubes Mixed Feed Coil Hot Process Air Coil Hot Steam Preheat Coil Cold Steam Preheat Coil Cold Process Air Coil Feed Preheat Coil

------------530.0 535.0 538.0 505.0 422.0 447.0

41.7 40.2 56.0 48.0 139.9 139.9 48.0 58.3

WARNING The temperatures listed above are design maximum fluid temperatures for the coils. This is also the design temperature for the outlet manifolds. The operating temperatures should not exceed those listed at any time. The downstream piping may not be rated as high as the coils and, if this is the case, the maximum rating for the piping should not be exceeded.

Section 5 – Process Operating Principles

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The hottest portion of the catalyst tubes is in the lower portion of the tube just before it enters the insulation above the collection manifold. Optical pyrometer readings should be taken at this point for normal tubes and at the hottest spot for those that have hot spots. Pressure in the radiant section of the reformer is sensed by PT / PIC-1019A which has a high pressure alarm, normally controlled at -80 mmH2O untill -100 mmH2O and PT / PIC-1019B with a low pressure alarm and normally controlled at -6.0 mmH2O through an internal DCS switch block PN-1019. The controllers adjust the position of the fan inlet vanes to maintain the draft and sound a DCS alarm on PAH-1019. Radiant box pressure is also sensed by PT-1058 which will sound a horn, PAH-1058A, with a large warning light, PAH-1058B and a local panel light, XL-1058 in the reformer penthouse if the pressure not normal. XA-1061 in the DCS will alarm if there is a failure on PT-1058. PAH1058 and PI-1058 are provided on the DCS for high alarm and pressure indication. Three transmitters, PT-1059A / B / C also sense the radiant box pressure and will alarm on DCS PAHH-1059A and on PAHH-1059B in the control room, tripping the reformer if the box pressure goes to the set point on at least two out of the three transmitters. This will also sound the horn and activate the warning lights previously mentioned. The horn and flashing light can be silenced by pushing the local hand switch, HS-1058, but the local panel lamp will stay illuminated until the high pressure condition is resolved. XA-1059A / B / C will alarm in the DCS if there is a failure on any of the PI-1059A/B/C transmitters which also have associated high alarms. An additional DCS pressure alarm has been added upstream of the ID fan damper to alarm on low suction pressure to the fan. PI-1057 indicates the draft on the DCS Pressure points have been installed in numerous places on the radiant box and convection section for local measurement of the pressure. These points are: • • • • • • • • • •

PP-1802A / B PP-1803A / B PP-1805A / B PP-1806A/B/C/D/E/F/G PP-1807A / B PP-1809/1810 PP-1812 PP-1813 PP-1815 PP-1609

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Primary Reformer Radiant Box Primary Reformer Radiant Box Primary Reformer Radiant Box Primary Reformer Tunnels Primary Reformer Conv Section Hot Steam Preheat Coil Primary Reformer Burners Inlet Primary Reformer FD Fan Inlet Primary Reformer ID Fan Inlet Primary Reformer Stack

Section 5 – Process Operating Principles

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Temperature is another very important aspect to monitor as the radiant and tunnel temperatures can be very high, at approximately 1,000°C. Each tunnel has a monitor for the temperatures exiting the radiant section of the reformer. TI-1317A through TI-1317G is DCS configured and each has a high temperature alarm. Additionally, DCS flue gas temperature indications with high alarms are located at points along the convection length of each convection section coil as follows: • • • • • • •

TI-1318A / B-upstream of the hot process air coil TI-1319A / B-downstream of the hot process air coil TI-1320E / F-downstream of the hot steam preheater coil TI-1320C / D-upstream of the cold steam preheater coil TI-1320A / B-upstream of the feed gas and cold process air interlaced preheat coils TI-1813 / 1812 -upstream of the combustion air preheater. TI-1426-upstream of the ID fan.

The temperature at the outlet of the ID fan is expected to be 126 °C. The design maximum expected flue gas temperature inlet the ID fan is 350°C. The following catalyst removal equipment is typically designed for removing spent catalyst from the reformer tubes: •

One heavy duty, portable, 380 volt electric motor driven unit vacuum producer capable of flowing 820 m3 /h at 190 mmHg vacuum and equipped with a filter bag and 0.25 m3 capacity removable dirt can • One 508 mm diameter centrifugal "top hat" primary separator for use with a U.S. D.O.T. standard 55 gallon or equivalent steel drum • Two 7.6 meters long, 63.5 mm (2½”) diameter abrasive resistant flexible hoses with built in ventilated pick-up tool attached to one end • Two 4" (101.6mm) I.D. heavy duty flexible hose, 4 meters long, with a 4" (101.6mm) I.D. female slip coupling on each end. • Six hinged valves, 2½" (63.5mm) IPS male thread on one end and other end suitable for a slip connection with a 2½" (63.5mm) I.D. male coupling. • Three hinged valves, 4" (101.6mm) IPS male thread on one end and other end suitable for a slip connection with a 4" (101.6mm) I.D. male coupling. 41. Process Air Compressor – 101-J The nitrogen required for ammonia synthesis is obtained from the atmosphere and delivered to the process by a 4-stage Air Compressor 101-J. It is driven by a condensing / induction steam turbine. The air compressor is a 4 stage compressor running to provide 143,332 kg/h of process air at Section 5 – Process Operating Principles

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43.5 kg/cm2G. Atmospheric air enters the machine through Air Filter, 101-L, which filters out particulate matter contained in the air stream. Pressure differential through the filter is indicated on the DCS by PDI-4100. A high differential pressure alarm will sound in the control room if the condition should exist. The flow proceeds through the machine and moisture contained in the air is condensed, separated, and removed by intercoolers 101-JC1/101-JC2/101-JC3 located on the outlets of the first three compressor stages, respectively. These cooling water intercoolers cool the air stream by exchanging heat with cooling water. Each intercooler has a moisture separator and dual traps to remove condensed water for disposal to the sewer. Each of the traps can be isolated for maintenance and both traps can be bypassed. The cooling water exit each intercooler has a local temperature indication to allow monitoring. • TW/TG-1683 exit 101-JC1 • TW/TG-1684 exit 101-JC2 • TW/TG-7207 exit 101-JC3 The compressor is locally instrumented so that the pressure and temperature of the suction and discharge air at each stage of the machine can be observed locally and / or in the DCS as indicated below: • • • • • • •

1st stage discharge, 2nd stage suction, 2nd stage discharge, 3rd stage suction, 3rd stage discharge, 4th stage suction, 4th stage discharge,

PI-1094 and TI-6148 A/B/C on DCS and PG-2385/ TW/TG-2389 local TI-1131 and PI-1163 on DCS and PG-2386 / TW/TG-2390 local PI-1165 and TI-6150 A/B/C on DCS and PG-2387 / TW/TG-2391 local TI-1132 and PI-1164 on DCS and PG-2388 / TW/TG-2392 local PI-1096 and TI-6149 A/B/C on DCS and PG-2389 / TW/TG-2393 local TI-6155 and PT-6148 on DCS and PG-2392 / TW/TG-2394 local PT-6151 A/B/C and TT-6150 on DCS and PG-2390/ TW/TG-2395 local

All 101-J suction DCS temperature indications have a high alarm associated with them The air compressor is driven by a condensing / induction turbine, 101-JT. Medium pressure steam is supplied to the turbine through a manual isolation valve. Line MS5101-3” is provided to vent the supply steam to a silencer SP-154 until the line is dry, hot and ready to start the turbine. The steam flow is monitored by FI-1116 on the DCS. Pressure and temperature of the inlet steam is shown locally by PG-1852 and on DCS by TI-1752, respectively. Low pressure steam can be inducted into the turbine, as it is available. An isolation valve with a warm up bypass has been provided. The low pressure steam flow is indicated on the DCS by FI-1259. Pressure and temperature are shown by PG-3123 (local) and TI-3123 (DCS) Section 5 – Process Operating Principles 1

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respectively. Exhaust from 101-JT is sent to 101-JTC, Surface Condenser. DCS TI-3101 with a high alarm, and PI-6144 A/B/C with a high alarm, indicate temperature and pressure on this exhaust line. Local instruments present are TW/TG-3102A and PG-3102. Gland steam leak from 101-JT is sent to 101-JTC through TC5010-8”. 101-J discharge pressure of 43.5 kg/cm2G is indicated on the DCS by PI-6152 and locally on PG-2390. The discharge temperature, 165.4°C, is monitored in the DCS by TI-6150, which has a high alarm provided. PI-6152 and TI-6150 are used to pressure and temperature compensate FIC-1004 which is the anti-surge controller for 101-J and controls FV-1004 venting to atmosphere. Function block FN-1003 is used to pressure and temperature compensate the process air flow using TT-1276 and PT-1050. PIC-1050 controls the speed set point to SIC-1001 at 101-JT governor. The compressor shutdown logic and anti-surge systems are described in a later section of the manual. 2 The speed of the machine is controlled by speed controller SIC-1001 with a DCS speed input

from SIC-1001A. Speed, load and anti-surge will be computer controlled since the interaction of these components is critical. The FIC-1004 control room mounted anti-surge control receives signals from: • Discharge pressure transmitter, PT-6152 • Temperature transmitter, TT-6150 th • Temperature transmitter, TT-6155 on 4 stage suction th • 4 stage suction pressure transmitter, PT-6148 • Temperature transmitter, TT-6180 on 1st stage suction • 1st stage suction pressure transmitter, PT-6171 • Discharge flow transmitter, FT-1004 also shown on the DCS on FI-1004 • Anti-surge valve FV-1004 position indication, ZT-1004 • Flow transmitter FT-1000 on passivation air line to urea • Plant air flow transmitter FT-1040 The controller is pressure and temperature compensated using PT-6152 and TT-6150, respectively, and will indicate and control the machine to avoid surging based on internally programmed surge curves. FIC-1004 will mirror and open control valve FV-1004 to an atmospheric silencer, SP-151, to pass the required air flow to keep the compressor out of a surge condition. This valve is a tight shut off class (TSO) that fails open when instrument air is lost . Process air flow also needs to be controlled to provide the correct amount of nitrogen for the Section 5 – Process Operating Principles

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hydrogen to nitrogen ratio in the synthesis loop along with all of the other parameters. FIC-1003 control room mounted controller, which through FN-1003 receives signals from: • Discharge pressure transmitter, PT-1050 • T emperature transmitter, TT-1276 • Discharge flow transmitter, FT-1003 Instrument and plant air required for operating the unit is supplied from the 4th stage suction through line A1017-4”. A non-return valve prevents backflow of air to the compressor from the offsites location of the instrument air driers. PG-1618 is the local pressure indication. The flow of air to the plant and instrument air system is measured by FE-1040. Line A2200-4” takes off from A1016, taking passivation air to urea plant. Flow is indicated at FT-1000. There are two s o u r c e s of air from the 101-J discharge line for use to air blow lines during pre- commissioning: 1. A1009-6” to the cold feed preheat coil with removable spool piece between the isolation valves 2. A1002-4” to the Reformer mixed feed coil with removable spool piece between the isolation valves Process Safety Precaution Failure to remove these spool pieces and blind these lines could lead to air accidentally being injected into reduced catalyst in the primary reformer, and the desulfurizer section leading to rapid oxidation of the catalyst and associated extreme temperatures. This could cause extensive damage to the tubes / vessels as well as the catalyst. The air injection could also create and explosive mixture 42. Secondary Reformer / Waste Heat Exchangers The inlet and outlet design gas compositions (dry basis) at the End of Run are as follows:

H2 N2 Ar CO CO2 CH4

Inlet 53.49% 0.78% 0.00% 5.40% 12.89% 27.44%

Outlet 48.18% 29.22% 0.35% 11.98% 8.67% 1.59%

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C2H6 C3H8 C4H10 C5H12 S

Nil Nil Nil Nil <0.1 ppmv

Nil Nil Nil Nil <0.1 ppmv

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Secondary Reformer, 103-D, is water jacketed, refractory lined, pressure vessel containing the nickel catalyst required for the secondary reforming reaction. Pressure drop for air/steam inlet is 0.45 kg/cm2 and for catalyst bed is 0.51 kg/cm2. The catalyst retainer or bed support located in the bottom of the vessel is a specially fabricated, dome shaped, honeycomb arrangement of high alumina firebrick. Above the dome, the catalyst rests on 25 mm diameter low silica alumina balls which themselves are supported by 50 mm diameter alumina balls that are setting on the dome. The inlet plenum or neck of the vessel contains an internal tube to guide the airflow into the mixing and combustion zone above the catalyst bed. The partially reformed gas stream from 101-B enters the 103-D plenum horizontally at a temperature of about 732°C as indicated in the DCS on TIC-1314. High and low temperature alarms are provided with TIC-1314 to check on the Primary Reformer exit conditions. TIC-1314 sends remote set point to PIC-1002, the fuel gas pressure controller for 101-B arch burners, for controlling the Primary Reformer exit temperature. The normal air flow of 143,763 kg/h is controlled by FIC-1003 controller, which receives a signal from the process air flow meter FT-1003. Controller FFIC-1003 in conjunction with FIC-1003 will provide the desired air flow to the process. The compressor speed can be adjusted to maintain a preset valve at SIC-1003. To add to the overall control, a signal from FFIC-1003, air / gas ratio calculator is sent to FIC-1003. See Section 7 in this manual for a complete description of the controls scheme. Process air from the 101-J compressor is preheated to 327.7 °C in the 101-B convection section cold air preheater coil as shown in the DCS on TIC-1044. The cold coil has a 8” bypass line with a butterfly valve TV-1312, which is controlled by TIC-1312. The bypass can be used to control the coil outlet temperature to the hot coil and thus the hot coil outlet temperature. There is also a DCS temperature indicator directly out of the coil TI-1325 with a high temperature alarm. A BFW injection point, SP-DH-211, has been added between the cold and hot coils for additional temperature control. A BFW injection from the 104-J/JA boiler feed water pumps is controlled by TIC-1044 monitoring the cold process air coil outlet temperature. The process air flow requires time to mix with the BFW to give a vapour phase mixture so no liquid water is present and a 24 meter long piping loop for sensing at TIC-1044 between the two process air coils has been added to accomplish this. A 3” piping boot is located just downstream of the BFW injection point to remove any liquid water that may be present. Any water if present is trapped to the sewer. The trap has an upstream strainer to protect it from debris and can be isolated and bypassed if necessary. TV-1044 valves fails closed if there is no instrument air or control signal and has isolation valves and a bypass. There is also an upstream isolation valve, strainer and non-return valve.

Section 5 – Process Operating Principles

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The air temperature exit hot air preheat coil contained in 101-B convection section is 497°C as indicated on TIC-1312 in the DCS which also has a high and low alarm. A medium pressure steam injection point has been provided upstream of the cold process air coil to allow steam into the coil and 103-D during low air flow conditions to prevent the overheating of the air coils. FIC-1044 steam flow to the 103-D and has high and low flow alarm. The control valve, FV-1044, comes with a bypass for manual operation, isolation valves and fails open on loss of instrument air. MP steam is directed to the process airl ine upstream of the cold air preheat coil through a non-return valve. FIC-1044 is activated by I-101 / I-101J. The bypass line FI-1045 will be set for the normal steam flow rate of 2,272 kg/h. FV-1044 valve will trip open to a preset output on FIC-1044 expected to be 35,000 kg/h. However, FV-1044 is designed to pass 60,000 kg/h should the BFW be unavailable for any reason. The preheated air stream, at a temperature of 497°C enters 103-D through a non-return valve to the internal velocity tube in the plenum. The gas and air meet and mix at the plenum outlet above the catalyst bed. Since the temperature of both streams is above the auto-ignition temperature of components, ignition occurs. The combustion is stoichiometric, consuming all of the oxygen contained in the air and leaving the nitrogen required for ammonia synthesis. The temperature of the combusted gas will be about 1,350°C. The flow continues downward 3 through a layer of holed, hexagonal shaped, high temperature tiles which cover the 34 m catalyst bed for secondary reforming and exits the vessel bottom at a temperature of 897°C as indicated on TI-1334 in the DCS. Two bed thermocouples measure the bed temperature at different levels on TI-1052 and TI-1053 in the DCS. Both bed temperature indicators have associated high alarms. The 103-D also has eight metal temperature indicators, four near the top and four at the bottom, to measure the vessel wall temperatures, TI-1333A through 1333H. These are sent to the DCS. All TI-1333 points have a high alarm. 103-D is provided with a differential pressure indicator, PDI-1103 in the DCS which has an associated high alarm. The 103-D effluent passes to the Secondary Reformer Waste Heat Boiler, 101-C. The 101-C is a horizontal single pass shell and tube type exchanger. The exchanger shell is refractory lined internally and water jacketed externally. Inlet temperature to 101-C is indicated on DCS at TI1334 with a high alarm. The process gas, flowing through the shell side, transfers heat to boiler water contained in the tube side and generates high pressure steam. 45.4% clean (or 28.9% fouled) of the partially cooled gas then passes through to the HP Steam Superheater, 102-C. The temperature to the 102-C is indicated on TI-1335 in the DCS, this temperature will be Section 5 – Process Operating Principles

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444ºC (clean). TIC-1004 measures the HP steam temperature at the outlet of 102-C and actuates a control valve in the 101-C. TIC-1004 is used to control the Steam Temperature exit 102-C tubes. These valves fail in last position upon instrument air failure and go open on signal loss. The valves will have an adjustable limit stop provided to maintain a minimum flow should the valve ever go fully closed. The 102-C is a vertical, single pass shell and tube exchanger directly connected to 101-C. The shell is refractory lined internally. Process gas flowing through the shell side gives up heat to superheat HP steam flowing through the tubes. This superheater provides only part of the steam superheat requirements, with the remaining portion fulfilled by the HP superheater coils in the 101-B reformer convection section. 102-C has two outlet nozzles. One, a partial bypass of the exchanger, allows the process gas to flow across the lower portion of the tubes while the other outlet nozzle directs the gas across all of the remaining portion of the tubes. The design basis has 12.4% (clean with 18.1% fouled) of the inlet flow going through the top part of the exchanger and exiting the top outlet with 33% (clean and 10.8% fouled) of the flow going through the lower part of the exchanger and exiting through the bypass. This bypass is provided for flexibility in controlling the temperature of the process gas entering HTS Converter 104-D1 and the superheat temperature of the HP steam. The process system from the inlet of 101-B to the outlet of 102-C is protected from overpressure by safety relief valves PRV-101C1 and 101C2, set to relieve at 42,8 and 44.9 kg/cm2G respectively, located at the shell side outlet of the 102-C exchanger. These relieve to the hot vent system. A local PG-1610 and a DCS indication PI-1103 with a high alarm is provided for process gas exit 103-D. PDI-1335 with a high alarm indicates the differential pressure across 101-C and 102-C. The gas stream flowing to 104-D1 is instrumented for controlling the temperature in the DCS with TIC-1010, which is supplied with a high and a low temperature alarm. Pressure inlet the 104-D1 is DCS monitored on PI-1335. 104-D1 inlet gas is continuously analyzed by the on-stream mass spectrometer AE-1030 for methane and shown in the DCS on AI-1030 A solenoid valve, XY-1030, will close the gas sample to the mass spectrometer upon a reformer process gas trip to avoid filling the analyzer with water. HS-1030 is provided to reset XY-1030. There is a manual sample point from 102-C also provided. 2 Control of the jacket water system for the 107-D & 103-D, will be discussed later in this manual. 43. High And Low Temperature Shift Converters

Section 5 – Process Operating Principles

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The inlet and outlet design gas compositions for the high temperature shift at the End of Run conditions are as follows: Inlet H2 N2 CH4 Ar CO CO2 HTS Pressure Drop

= = = = = = =

Outlet

48.18% 52.15% 29.22% 26.99% 1.59% 1.47% 0.35% 0.32% 11.98% 3.41% 8.67% 15.66% 0.2 kg/cm2

The High Temperature Shift, HTS, Converter 104-D1 and the Low Temperature Shift, LTS, Converter 104-D2 contain the catalysts required for shifting carbon monoxide, CO, to carbon dioxide, CO2. Iron / copper promoted catalyst is contained in the HTS and copper / zinc catalyst in the LTS. The process stream from 102-C at 371°C enters the top of HTS, 104-D1, through an internal gas distributor, flows down through the catalyst bed and exits at the vessel bottom. The reaction in the HTS 104-D1 is exothermic and the process stream leaves the vessel at a temperature of about 431°C. At the Start of Run catalyst conditions, the HTS catalyst may operate as low as 360°C or within the limitations of 101-C and 102-C as directed by the catalyst vendor. The HTS 104-D1 is instrumented for monitoring catalyst temperatures at various points in the bed and exiting the vessel as indicated on TI-1341A/B through TI-1344A/B. TI-1345 indicates the gas temperature exit the HTS and has a high alarm. Pressure differential across the bed as shown on PDI-1110A, with a high differential pressure alarm in the DCS. The local inlet pressure can be seen on PG-1611 and the outlet pressure can be read on PG-1612. PI-1335 displays the inlet and pressure on DCS. A manual double block and bleed drain line to a disengaging pipe has been added to the outlet line. 104-D1 outlet gas is continuously analyzed by the on-stream IR spectrometer AT-1011 for Carbon Monoxyde content and shown on AI-1011 in DCS. A solenoid valve, XY-1311, will close the gas sample to the mass spectrometer upon a reformer process gas trip to avoid filling the analyzer with water. HS-1311 is provided to reset XY-1311. There is also a manual sample point provided. 2

Section 5 – Process Operating Principles

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Process Gas exiting 104-D1 is cooled to 205°C by flowing in series through the shell sides of the HTS Effluent Steam Generator and Boiler Feedwater Preheater, 103-C1 and 103-C2. In the 103-Cs, heat in the process stream is given up to boiler feedwater flowing through the exchanger tubes towards the 141-D, high pressure steam drum. These exchangers convert about 25% of the boiler feedwater to steam before exiting. A DCS vaporization rate calculation approximation block, UI-1001, has been added with a high alarm to alert the operators of excess steaming rates. UI-1001 gets inputs from the following points: • • • • • • • • •

TI-1345 TIC-1011 PIC-1032 FI-1045 FIC-1072 TIC-1557 FN-1001 FN-1002A FIC-1003

exit 104-D1 exit inlet 104-D2 inlet 104-D2 steam to air coil BFW flow BFW Flow process gas flow process steam flow process air flow

103-C2 has a shellside drain for use during start-up. The drain line has double block valves to bleed any condensate formed on a few of the exchanger tubes and send it to disengaging pipe on to drain. PIC-1032 indicates the pressure of the process gas outlet of 103-C2 in the DCS while PG1691 can be seen locally for this pressure. DCS TI-1610 indicates the temperature of the gas stream exit 103-C1. TIC-1011 is a DCS temperature indicator with a high and low alarm on the 103-C2 gas outlet line. A manual sample loop has been put on the 104-D2A/B inlet line for manual samples. A start-up vent, PIC-1032 is provided just upstream of the LTS and vents to the hot vent system. The valve fails closed of loss of instrument air or control signal and is a tight shut off valve. There is an upstream and downstream isolation valve also provided. A handjack is also provided. Boiler feedwater to the 103-Cs is split into two paths. A boiler feedwater bypass, containing TV-1011B control valve, is provided bypassing the BFW to the inlet of 103-C1. The second path is through TV-1011A directing it to 103-C2 which joins the bypass flow going to 103-C1. The sensing point for TIC-1011 is located at the process inlet to the LTS, 104-D2 and has both high and low temperature alarms to warn of temperature deviations. These provisions give temperature control flexibility of the gas stream entering the LTS. TIC-1011 split ranges the two valves such that as one valve goes closed the other one goes Section 5 – Process Operating Principles

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open an equal amount. TV-1011A will be set up to always remain open a minimum of 10% to avoid steaming or vapor pockets that could carry over from 103-C2 into 103-C1 and cause hammering or tube failure in the 103-C1 exchanger. TV-1011A fails open and TV-1011B fails closed on loss of instrument air or control signal and both have handjacks for manual operation. TI-1601 and TI-1611 display BFW temperature on DCS exit 103-C2 and inlet 103-C1 respectively. BFW flow to 103-C1/C2 passes through FV-1072A/B located upstream TV-1011A and before the bypass line with TV-1011B takes off. FV-1072A/B work in split controlled by FIC-1072 with FV-1072B operating in range of 0-10% and FV-1072A in range of 10-100%. FIC-1072 is part of 3-Element level control strategy for 141-D. Both FV-1072A/B fail open on loss of instrument air or loss of control signal and are provided with hand jacks for manual operation. FSL-1106, taken from FT-1106, located upstream FV-1072 generates a signal for Auto-start of 104-JA. Between the shell side outlet of the 103-Cs and inlet to the 104-D2A/B is a manifold containing motor operated, isolation valves MOV-1008, inlet to the 104-D2A/B, and MOV-1009 which bypasses the 104-D2A/B. Normally, MOV-1008 is open and MOV-1009 is closed and the process flow is through the LTS. During start-up and emergencies, the LTS must be isolated. MOV-1009 is opened and MOV1008 closed bypassing the LTS. The two MOVs are interlocked ensuring that MOV-1009 opens before MOV-1008 closes so that forward flow of the process gas is not stopped. Both valves are inching and can be positioned as required for flow using DCS hand switch HIC-1008 for MOV-1008 and HIC-1009 for MOV-1009. MOV-1008 has a 1" double block and bleed pressuring up bypass valves and each MOV has a handjack to manually operate the valve during power or motor failures. MOV-1008 is blindable downstream for LTS reduction MOV-1009 also has a DCS operated control valve HIC-1021 in its bypass line. This valve can be used during start-up for slowly pressuring up the downstream equipment and during normal operation with new catalyst to bypass a small amount of gas around the LTS so that the methanator reaction temperatures can be maintained. HV-1021 valve has a hand jack and fails closed on loss of control signal or instrument air and has upstream and downstream isolation valves. Valve positions are indicated in the DCS by ZLO/ZLC-1008 for MOV-1008 and ZLO/ZLC-1009 for MOV-1009. PIC-1032 monitored, PV-1032 takes off as a line to hot vent system from this manifold area as well.

Section 5 – Process Operating Principles

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The inlet and outlet design gas compositions for the low temperature shift at End of Run Conditions are as follows: Inlet = 52.15% H2 N2 = 26.99% CH4 = 1.47% Ar = 0.32% CO = 3.41% CO2 = 15.66% LTS Pressure Drop =

Outlet 53.58% 26.18% 1.43% 0.31% 0.31% 18.19% 0.41 kg/cm2

The LTS flow enters the vessels at 205°C and continues down through the catalyst bed passing through the same types of grates, screens, and support media as described for the HTS. The LTS reaction is exothermic and the process stream leaving the vessel is at a temperature of approximately 229°C and can be monitored in DCS on TI-1613 / 1351. At the Start of Run catalyst conditions, the LTS catalyst may operate as low as 200°C or as directed by the catalyst vendor. CAUTION Although the LTS catalyst inlet temperature will be lowered to achieve the best equilibrium after a new charge of catalyst has been installed, care must be taken to not let the inlet temperature go less than 15°C above the dew point of process gas to avoid condensation of steam in the gas and damage the catalyst. An isolation valve, MOV-1007 is provided in the outlet piping with a 1" bypass line for repressuring the vessel. The main line is blindable for LTS reduction whereas the bypass line has double block and bleed arrangement. DCS mounted handswitch HIC-1007 can be used to inch the valve open or closed. DCS valve position indicator ZSO/ZSC-1007 shows if the valve is open or closed and the MOV has a handjack for manual operation when power is not available. N1002-1.5” and N1112-1.5” nitrogen connections tie in to the 104-D2B outlet just downstream to the 173-C take off line and to the 104-D2A outlet. The vessel is instrumented for monitoring temperatures in the catalyst bed using DCS TI-1346 A/B through TI-1349A/B for 104-D2A and TI-2446A/B through TI-2449A/B for 104-D2B. Each of the temperature indicators has a high temperature alarm. Vessel differential pressure is measured by PDI-1037A and PDI-1037B for 104-D2A/B respectively, with a high differential pressure alarm in the DCS. A pressure indicator, PG-1613 can be used to locally check the inlet pressure of the vessel and PG-1614 for the outlet. Section 5 – Process Operating Principles

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As the LTS catalyst becomes poisoned and inactive over its lifetime, a temperature profile will move down through the catalyst bed. Manual samples can be taken with the unit online from either the 104-D2A/B outlet sample points or the 104-D2A inlet sample point. The outlet gas stream from 104-D2 is continuously analyzed by the on-stream IR spectrometer AT-1031 for the carbon monoxide and shown on AI-1031 in DCS. There are two source streams for this analyzer: 1. Directly exit 104-D2B 2. Downstream of the MOV-1009 bypass tie-in AE-1031 can be used to sample the LTS outlet directly or take a sample from the line to 131-C by adjusting the 3-way valve in the sample lines to select the desired sample. Solenoid 2 valve XY-1331 is provided for isolation of AT-1031 in case of I-101 “Primary Reformer Process trip” so as to avoid damage due to ingress of condensing steam. XY-1331 is reset using HS-1331 There is a grab sample point and cooler provided from the line to the IR spectrophotometer.

5.1.1.

LTS Reduction Piping

Reduction of the LTS is accomplished using hydrogen rich gas from 142-D1/D2 mixed in a nitrogen carrier gas using 175-C medium pressure steam heated exchanger for temperature control and a circulator, 173-J, for closed loop circulation. The flow path for the reduction is as follows: • Nitrogen is used as the carrier gas and has two permanent connections through a double block and bleed isolation system with a non-return valve in between. One tie in is on line PG1174-14” before the 173-D and the other to 173-J. The hydrogen source, as described below, ties in just upstream of the 175-C. Upstream of 175-C is the reduction gas inlet isolation double block and bleed valve system with an upstream figure ‘8’ blind. • The carrier gas and hydrogen flows through the LTS with the temperature, pressure and IR spectrometer analyzer available as mentioned previously. The gas exiting is directed to the 173-C through line SG1019-14 ”. This line also can be isolated and has a figure ‘8’ blind. • The gas is cooled in 173-C against cooling water and the temperature is DCS indicated on TI-2301 which has a high alarm. The flow is then directed to 173-D where water that was condensed will be knocked out. 173-D has a local sight glass LG-1901 and a DCS level

Section 5 – Process Operating Principles

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indication on LI-1301 which has a high alarm and high-high alarm that shuts down 173-J. The drum has an inlet sparger and a demister pad on the gas outlet line. Water can be manually drained to a local disengaging pipe through a double block and bleed piping arrangement to the drain system. The final drain valve is a globe type for control. There is a manual vent on the exit of 173-D for depressuring. 173-D exit will direct the gas to the 173-J circulator. This motor-driven circulator provides the circulation for the LTS reduction. The circulator has a discharge non-return valve with an upstream figure ‘8’ blind and local pressure gauges PG-1680. There is also a thermowell on the line TW-1303. The circulator has a suction strainer to prevent trash from entering the machine and a local pressure gauge PI-1738 downstream of the strainer. DCS indication is also provided for the suction pressure at PI-1302 which assosiated with a low alarm. The circulator cooling is done against cooling water and there are two piped nitrogen sources one on the suction line before 173-D and one on the casing. Both nitrogen lines have double block and bleed valving with a non-return valve in between as well. The blower is protected from low flow damage by DCS kick-back flow controller FIC-1301 which comes with a high alarm and low alarm. There is a DCS temperature TI-1303 on discharge of 173-J. The discharge pressure is measured with PI-1301 with the signal going to FN-1301 for pressure and temperature compensation. FT-1301 indicates the flow exit the 173-J and also sends signal to FN-1301 to control kickback FV-1301. FV-1301 fails open on loss of instrument air or control signal. There is a downstream non-return valve to prevent backflowing. DCS XL-1301 indicates running status of 173-J. The gas flows from here through 175-C where it is heated, as required, against medium pressure steam. The steam flow is manually controlled using a globe valve in the steam inlet line. There is also an inlet gate type isolation valve with a downstream figure '8’ blind for positive isolation. The condensate formed is trapped to the 101-U Deaerator. The outlet trap can be fully isolated and bypassed and comes with an inlet strainer. The temperature of the gas exit 175-C can be seen locally on TW/TG-1604 or in the DCS on TI-1306 which has a high and low temperature alarm. The circulating gas returns to the LTS inlet isolation from this point to complete the circuit. FI-1104 shows the flow at this point in the DCS and will alarm if the flow goes low. Hydrogen for the reduction of the LTS is supplied from 142-D1/D2 in line PG1073-2”. The flow from 142-D2 passes through non-return and isolation valves before tying into the line. The reduction hydrogen flow is manually adjusted with an inlet needle valve using rotameter flow indications FI-1602, low range flow, or FI-1603, high range flow. Both rotameters have outlet isolation valves and the hydrogen flows through a non-return valve and isolation valve with a figure ‘8’ blind before tying into the circulation gas line. PG-1616, a local pressure gauge, indicates the hydrogen supply pressure. Catalyst reduction will be covered in a later section in this manual.

The LTS outlet flow can be directed to three locations. One line, V1007, can be manually opened to vent the effluent to the front end vent. It has a globe valve for control and a figure ’8’ blind for positive isolation. Line SG1019-14”, can be manually used to put reduction gas to the closed Section 5 – Process Operating Principles

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loop system as described above. Both of these lines are isolated by an additional upstream valve from the LTS outlet line. Line PG1012-30” directs the process gas to the 131-C exchanger which is the normal flow path. Double block and bleed drain lines have also been added to the outlet line with one immediately at the exit of the LTS and the second one located between MOV1007 and MOV-1009 tie-in point. Both drains line tie into disengaging pipes for safety and condensate pumped to cooling tower.

5.1.2.

LTS Effluent Heat Recovery

The effluent stream from the LTS is cooled to 70°C by flowing in series through three exchangers and a gas separator 142-D2, before entering the CO2 absorber, 121-D. The three horizontally mounted exchangers are as follows • 131-C LTS Effluent / BFW preheater : This exchanger cools down the LTS effluent process o gas to 167 C with BFW on tube side. 131-C has a provision of spectacle blinds at both inlet and outlet tube side nozzles. Process gas exiting 131-C is monitored of temperature on DCS at TIC-1420 (with a high alarm) whereas TI-1557 controls the BFW temperature exiting the tube side. TIC-1420 acts on TV-1420 which is installed on 8” bypass line and closes on instrument air failure or loss of control signal and is also provided with a hand jack for manual operation. BFW temperatue is locally inidicated at TW/TG-1836. • 105-C CO2 stripper reboiler. This exchanger cools the process stream flowing through the exchanger tubes to 136°C by giving up heat to the OASE solution on the shell side. This exchanger is the main reboiler for the CO2 Stripper, 122-D2. This exchanger has a gas-side bypass line with a manual butterfly valve, HIC-1421. DCS TIC-1420 which has a high alarm indicates the inlet temperature. DCS TI-1421, which has a high temperature alarm, indicates 105-C process gas exit temperature. • 106-C LTS Effluent / LP BFW Exchanger: This exchanger cools the process stream flowing through the exchanger tubes to 70°C, indicated on TI-1352, by passing heat to a demineralized water stream through the exchanger 109-C. The control valve bypasses demineralized water around 109-C to control the gas temperature exit 106-C. TI-1352 is provided with high and low alarms.

Section 5 – Process Operating Principles

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The condensate formed in cooling the process gas stream is disengaged in the Raw Gas Separator, 142-D1. The vessel contains an inlet deflection nozzle, demisting pad covering the outlet gas nozzle, and a vortex breaker covering the liquid outlet nozzle. The 142-D1 exit line is instrumented for observing pressure on PG-1692 local gauge. The level is controlled using LIC-1003 controller and level glass LG-1603. LIC-1003 has high and low level alarms in the DCS association with it. The high level alarm will automatically start the 121-J / JA spare pump through LSH-1003 when a high level is detected and if the pump local Hand- Off- Auto (HOA) switch is in the auto position. Condensate is withdrawn from 142-D1 and pumped to the Process Condensate Stripper, 130-D, by process condensate pumps 121-J/JA. Low-low level alarm LALL-1205 with I-142D1 is provided in the DCS to avoid the possibility of process gas blowing into the OSBL header. DCS transmitter failure alarm XA-1057 will sound if LT-1205 transmitters fail. Upon activation, LALL-1205 will immediately close the control valves LV-1003A (by tripping solenoid valves LY-1003A) and LV-1003B. Upon a low level trip LV-1003A must be reset by using HS-1003 that resets I-142D1 before valves can be put in normal operation. Branching from the 142-D1 outlet gas line is start-up vent line PG1065-10”. The process venting is DCS controlled on the PV-1040 valve and goes to the hot vent header. PV-1040 has an upstream isolation valve for positive isolation and is controlled through PIC-1040. The valve has a handjack and fails closed on control signal or instrument air loss.

5.1.3.

Process Condensate

Process condensate from the Raw Gas Separator 142-D1 is recovered and reused in the ammonia plant. Process condensate can contain up to 1,000 mg / m3w ammonia, 4,000 mg / m3w carbon dioxide and 1,000 mg / m3w methanol and traces of amines. Before its export to the OSBL the condensate is stripped by counter current contact with medium pressure steam in the Process Condensate Stripper, 130-D. Recovered condensate will have an ammonia content of about 10 mg / m3 by weight, 10 mg / m3 carbon dioxide and methanol content approximately 50 mg / m3. The process condensate, totaling 83,664 kg/h, is pumped by 121-J or JA pumps. LIC-1003 at the bottom of 142-D1, controls level valve LV-1003A to the 188-C's exchangers. LV-1003A and its split range counterpart, LV-1003B, both fail closed without instrument air or a control signal. Should the pumps trip or LV-1003A close for any reason, LV-1003B will open and send the condensate to OSBL. LIC-1003 has high and low level alarms on the DCS. There is a local grab sample point with sample cooler on the suction line to 121-Js. Associated with I-130D, LVSection 5 – Process Operating Principles

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1003A trip closed if the level goes low in 142-D1 as signaled by LALL-1205. LV-1003A has a solenoid LY-1003A, and it also has a reset switch HS-1003. Each of the motor driven 121-J pumps is furnished with suction and discharge isolation valves as well as a suction strainer, suction and discharge pressure gauges and automatic minimum flow valves. PG-1697 and PG-1658 indicate the suction and discharge pressures for 121-J, respectively with PG-1698 and PG-1659 for 121-JA. DCS run indicators are provided for each pump with XL-1020 on 121-J and XL-1021 on 121-JA. There are also automatic minimum flow control and non-return, ARC, valves for each 121-J. The minimum flow lines return to 142-D1. They can be isolated using gate isolation valves and have non-return valves for backflow prevention. The standby 121-J pump will be automatically be started if a high level occurs in 142-D1 on LSH-1003 action from LIC-1003. The 70°C raw condensate is preheated in the Condensate Stripper Feed / Effluent Exchangers, 188-C1 / C2 / C3 tube sides, then distributed to the top of the 130-D process Condensate Stripper through a distributor. The temperature of the inlet condensate is 243°C as measured on TI-1649 in the DCS. Flow to the 188-Cs tubes is measured and indicated in the DCS on FI-1062 which has a high and a low flow alarm incorporated. The Process Condensate Stripper, 130-D, contains two beds with a liquid distribution tray over each bed. Each bed is comprised of stainless steel rings sitting on a bottom stainless steel gas injection plate. The rings are held down with stainless steel hold down grates. The tower top contains a demister pad to disengage liquid droplets from the medium steam flow as it leaves the tower to flow to the 101-B feed system. A vortex breaker is installed at the liquid outlet of 130-D. The level is controlled in the bottom of the tower by DCS LIC-1025 which is controlling the liquid on outlet the shell side of the 174-Cs cooling water exchangers after it passes through the188C's exchangers. LV-1025 valve fails closed when instrument air or the control signal is removed, and it comes with isolation valves and a bypass line for maintenance and manual operation. The level controller has high and low level alarms to warn the operators of those conditions. Level glasses, LG-1625A/B is also provided. The 130-D will also be used for setting up flow through 131-C start up by flowing through line BW2202-3” to the tower then sending water to the offsites polisher for reclaiming. The line has an angle valve for control and gate valve for isolation. The line is installed with PRV-130D set at 51.6 kg/cm2(G). A second SIS transmitter has been added LT-1029A/B/C to prevent a blow through of medium pressure steam to the exchangers due to a low-low level in the tower. A low-low level will alarm in

Section 5 – Process Operating Principles

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the DCS on LALL-1029 and will trip LV-1025 through solenoid LY-1025. LT-1029 A/B/C is a 2 out of 3 voting system for initiating the trip. LT-1029 also generate a high high level alarm at LAHH1029 and level is indicated at LI-1029A/B/C. Transmitter failure alarm is provided at XA1029A/B/C. The 81291 kg/h, of stripped condensate, at 259°C, as indicated on the DCS TI-1405, leaves the tower and, after passing through the 188-Cs feed / effluent exchangers, is cooled to 81°C. Condensate is further cooled to 39°C in the Stripped Condensate Cooler, 174-C, against cooling water before being sent to the offsites. The cooling water temperature exit 174-C has a local TW/TG-1651 and the condensate temperature is monitored on DCS TI-1652 with a high temperature alarm incorporated and the flow on DCS FI-1063. 174-C is protected from overpressure by PRV-174C on the exit process line and set at 9 kg/cm²g. A controls scheme for accurate steam flow to the process has been developed for the stripper. The condensate flow into the tower on FI-1062 has the condensate flow exiting the tower on FI-1063 sent to DCS function block FY-1062 and the result is indicated on DCS FDI1062A. Conductivity exit the system is also measured using DCS AIN-1017 and a high conductivity alarm will warn of a breakthrough condition. A local sample point is provided for grab sample analysis. There is a three-way valve and a non-return valve with bleed arrangement to condensate tank. There is an additional line WW1033-6” that is going to waste water header. The medium pressure steam flow of approximately 25099.2 kg/h through the stripper is controlled by DCS FIC-1019 which alarms if the flow goes high or if the flow goes too low. FV-1019 valve is designed to fail closed if instrument air or control signal is lost and is provided with a handjack. The flow is measured on the inlet to the column after passing through a non-return valve but the control valve is on the outlet holding the medium pressure steam header as a backpressure. Saturated vapor and stripped gases exit the top to join the process steam to the primary reformer. PG-1657 is a local pressure indicator that can be used to monitor the 130D bottom pressure. A high and high-high alarm on differential pressure indicator DCS PDI-1069, sounds if that condition develops. The stripper can be fully isolated manually and blinded for vessel entry while the plant is still on-line. The inlet steam manual isolation valve is provided with a 2" bypass to warm and pressure up the system. A non-return valve is also in the inlet line.

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There is a manual vent on 130-D with double block valves with the downstream valve being a globe valve for depressuring.

44. Synthesis Gas Purification 5.1.4.

Carbon Dioxide Removal

The inlet and outlet design gas compositions for the absorber are as follows:

H2 N2 CH4 Ar CO CO2

= = = = = =

Inlet

Outlet

53.61% 26.19% 1.43% 0.31% 0.31% 18.15%

65.41% 32.03% 1.74% 0.38% 0.38% 0.05%

Carbon dioxide, CO2, removal is accomplished by contacting the raw synthesis gas stream with an activated solution of OASE (monodiethanolamine) nominally at 40% by weight. The CO2 in the gas stream is chemically absorbed in the solution. Upon regeneration of the liquid stream, the carbon dioxide is released by depressurization and steam stripping. The treatment is known as the OASE-3 System and is licensed by BASF. The major components of the OASE system are the: • 121-D - CO2 Absorber, • 163-D - HP Flash Column • 122-D1 - LP Flash Column • 122-D2 - CO2 Stripper • 110-C - CO2 LP Flash overhead condenser • 153-D - LP Flash Overhead KO drum • Pumping facilities for circulating the solution Internally the CO2 Absorber 121-D contains five beds of metallic packing. The four gas contacting beds consist of bottom gas injection plate-type bottom support which the rings rest directly on. Each bed also has a top hold down grate. Located above each bed is a liquid distribution trough. There are liquid inlet spargers located above beds #1 and #3. The tower process feed gas inlet sparger is located beneath the fourth bed. The fifth bed is located in the bottom of the tower in the rich liquid storage area. It serves to help disengage entrained synthesis gases from the solution. The bottom liquid outlet nozzle comes equipped with a vortex Section 5 – Process Operating Principles

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breaker. The tower top is fitted with a water wash system containing three wash trays. Condensate from 110-Js is used to wash any entrained OASE from the process gas stream before it passes through the demister pad. This water wash also serves as the make-up water to the system to maintain the system water balance and solution strength. There are three valve trays in the top wash section of the tower. Valves trays are designed to let the gas flow up through tray opens and the “non-return” valves that cover those opens but the valves will close so that water can not run back through the holes under no / low gas flow conditions. The wash water then flows across the trays with a level being maintained due to an overflow weir at the end of the tray the overflows the weir down to the lower tray. The last tray overflows to a liquid distributor and the wash water flows down and mixes with the circulating solution. DCS pressure differential indicator, PDI-1042B, with high pressure differential alarm is provided to indicate foaming or liquid hold up in the tower. A local pressure indicator, PG-1617, will read the process inlet pressure to the tower. In addition the inlet pressure is seen in the DCS on PDT-1042B and the outlet pressure on PDT-1042A. These readings are sent to PDI-1042BB and subtracted to get the ∆P. Sample points for manually sampling of the process gas are provided between beds one and two, two and three and also between beds three and four. The process system is protected from over pressure by safety relief valve PRV-121D1 which is set to relieve at 41 kg/cm²g to the front end vent system and PRV-121D2 which is set to relieve at 43.05 kg/cm2G to the hot vent header. The CO2 Stripping, is made up of two separate sections: 1. Low Pressure, LP Flash Column – 122-D1 – which is physically at the top of the tower with 163-D HP Flash Column located beneath 2. Stripping Section – 122-D2 – which is physically a separate vessel.

122-D1 contains one bed of packing material, steel rings sitting on a bottom gas injection platetype bottom support which these rings rest directly upon. The bed also has a top hold down grate. Immediately above the bed is a liquid distributor. Below the bed is a liquid drawoff nozzle in the head with a vortex breaker. Located above the top bed is the flash gallery and a wash section with distribution valve trays. The tower top contains a high density demisting pad to remove liquid droplets from the gas stream as it exits the tower. A manual sample point is provided on the exit line and above the liquid distributor.

Section 5 – Process Operating Principles

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The tower top is fitted with water wash system containing three wash trays. Condensate from 110-Js is used to wash any entrained OASE from the process gas stream before it passes through the demister pad. This water wash also serves as the make-up water to the system to maintain the system water balance and solution strength. The column is protected from overpressure by relief valves PRV-153D which relieves at 3.5 kg/cm²G and is located on the outlet of the 153-D. Underpressure protection is by vacuum relief valve VRV-122D1which relieves at -0.250 kg/cm²G, is located on the 122-D1 vapor outlet line. Pressure differential indicator, PDI-1043, and associated high differential pressure alarm is also provided measuring the pressure drop across the upper section of 122-D1. Pressure differential indicator, PDI-1064 is provided measuring the pressure drop across the 122-D2 The 122-D2 lower section pressure can be seen on local pressure indicator PG-1061. 122-D2 contains two beds of metallic packing. Each bed’s steel rings which are held in place by hold down grates. Each bed also consists of bottom gas injection plate-type bottom support which the rings rest directly upon. Immediately above the beds are liquid distributors. Below the bottom bed is a liquid drawoff nozzle in the head with a vortex breaker. A similar liquid drawoff arrangement is located in the bottom storage area of the vessel as well. Located above the top bed is the flash gallery. There are also three manual sample provided – one on the outlet vapor line from 153-D, second below the flash gallery of 122-D2 and third on the vapor outlet line from 122-D2 to 122-D1. 5.1.5.

Process Flows / CO2 Product

Raw synthesis gas at 70°C enters the 121-D, Absorber, bottom after passing through a nonreturn valve, a seal loop, the motor operated MOV-1005 main inlet isolation valve with 2" pressuring bypass with a double block and bleed. MOV-1005 has a hand jack for operation during power failure. The valve is operated from the DCS on HS-1005 hand switch and the valve position is shown on DCS ZLO/ZLC-1005. There is a Nitrogen line N1003 tied-in downstream of MOV-1005 for purging and pressuring the absorber for circulating. The Nitrogen line is isolated by a double block and bleed system with a non-return valve and figure ‘8’ blind in between. The downstream isolation valve is a globe-type. The process gas flows through the inlet gas sparger, and flows up through the packed beds #4 and #3 in that order. The gas is contacted by regenerated, semi-lean solution flowing down through the beds. In this initial contact, the bulk of the carbon dioxide in the gas is absorbed by the liquid. The gas flow continues upward through the top beds #2 and #1 in that order and is contacted by regenerated lean solution flowing downward. In this secondary contact, most of the remaining CO2 is absorbed.

Section 5 – Process Operating Principles

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The gas flow continues through three water wash trays where small amounts of OASE solution are washed from the gas. Condensate from 153-D is pumped to the wash trays by 110-J / JA with flow being controlled by FIC-1018 on the DCS at 3500 kg/h. FIC-1018 has high and low alarms. FV-1018 will fail open if there is a loss of instrument air and is equipped with isolation valves and a bypass. The gas flow continues upward leaving the vessel through a demisting pad at a temperature of 50°C, as indicated on DCS TI-1353, and enters the CO2 Absorber Overhead Knockout Drum, 142-D2. Before the gas stream enters the 142-D2 vessel, additional condensate from 153-D, pumped by 110-J / JA is added. The condensate flow is manually controlled by a RO and the flow is measured locally on FI-8004. FI-8004 can be isolated for maintenance with a double block and bleed system and has two non-return valves on the outlet to prevent a backflow of gases. This condensate addition will assist in washing solution particles out of the gas stream. 142-D2 contains an inlet impingement nozzle, a demister pad covering the vapor outlet nozzle, and a vortex breaker covering the liquid outlet nozzle. The purpose of the drum is to disengage OASE solution and condensate that is entrained or may have carried over with the vapor stream during foaming problems. Liquid is withdrawn from the drum by automatic level control LIC-1005, which has high and low level alarms incorporated. The level control valve LV-1005 fails closed on loss of instrument air and has upstream and downstream isolation valves. A bypass line around the valve with two isolation valves in it has also been provided. The vessel also contains LG-1632, level gauge. Process gas from 142-D2 flows on to the methanator. A 2” branch line PG1073 is provided to supply hydrogen rich gas for the reduction process of 104-D2. The gas stream flowing from 142-D2 is continuously analyzed by the on-stream IR analyser AE1023 for CO2 and shown in the DCS as AI-1023 with a high alarm. A manual sample point has also been provided for grab sampling. After separation from the OASE solution in the top section of the 122-D1, the CO2 product vapor at 77°C is directed to the 110-C, cooling water exchanger where it is cooled to 38°C. The CO2 goes through the 153-D, CO2 LP Flash Reflux Drum where condensate is separated from the gas stream. 153-D has an inlet flow sparger, an outlet demister pad and a vortex breaker for the liquid outlet line. A local level glass, LG-1640, shows the level. 6366 kg/h condensate from the drum 153-D is pumped back using 110-J/JA under flow control of FIC-1016 to 122-D1. LIC-1040 controls the 153-D level and its output goes to a DCS selector switch, HS-1040. The selector switch output can go to either FIC-1013 to control FV-1013, demineralized water make up, or to flow controller FIC-1016 as remote set points controlling the

Section 5 – Process Operating Principles

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condensate flow to 122-D1 from the discharge of 110-J/JA, CO2 Stripper Reflux Pumps by controlling FV-1016. FV-1016 fails close on loss of instrument air or control signal and has a double bleed and block arrangement around it, and it also has a bypass equipped with a globe valve. A drain line, PC-1023-1.5”, to the OASE sewer on the suction to the 110-J / JA pumps can be used for water balance control in an emergency. FV-1013 fails close on loss of instrument air or control signal and has a double bleed and block arrangement around it, and it also has a bypass equipped with a globe valve. The 110-J/JA are motor-driven pumps each having a suction strainer to prevent debris from entering and damaging the pumps. Each pump has a minimum flow line that flows through a non-return valve, a restriction orifice and a car sealed open (CSO) isolation valve. Each pump has suction and discharge isolation valves and a non-return valve. The minimum flow returns to 153-D. Also included are suction and discharge pressure gauges, PG-1702 and PG-1662, respectively, for 110-J and PG-1703 and PG-1663, respectively, for 110-JA. These pumps are automatically stopped if there is a low-low level in 153-D as indicated on DCS LI-1044 and alarmed on LALL-1044. Each pump also has DCS running indication on XL-1015 for 110-J and XL-1016 for 110-JA. Reflux water is circulated by the CO2 Stripper Reflux Pumps 110-J/JA to the 122-D1 CO2 Stripper wash section. Prior to entering 122-D1, a portion of the condensate, about 32% of the total flow or 3,500 kg/h, is directed to 121-D to serve as wash water for the washing section at the top of the tower. The water flow is controlled by DCS FIC-1018 with high and low flow alarms incorporated. The water flows through two non-return valves before entering 121-D to prevent the backflow of process gases. Another stream from the 110-J / JA pump discharge is used for the emergency OASE pumps seal flushing to all OASE pumps. This water will be automatically opened if the pressure on the 108-Js, lean OASE pumps, common seal flushing line, which is the normal source for all of the pump’s seal flushing, becomes too low. DCS PI-1117 indicates the pressure on the seal flushing line and alarms on PALL-1117 when the pressure is too low. This trips solenoid XY-1117 opening valve XV-1117 allowing water from the 110-Js to the seal flushes through a non-return valve and isolation valve. XV-1117 will fail open on loss of instrument air, has a handjack for manual control and has a DCS position indication on ZLO-1117 and ZLC-1117. The solenoid valve has to be manually reset to stop the flushing water source with HS-1117. The major portion, approximately 58.0%, of the 110-J / JA flow which is 6366 kg/h, will be returned to the top of 122-D1, in the wash section below the demister. This flow is controlled by DCS FIC-1016 which may have a remote setpoint from the 153-D DCS level control LIC-1040 which has a low level alarm included. The normal Section 5 – Process Operating Principles

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operating mode expected is for FIC-1016 to be a stand-alone controller with LIC-1040 selected as a remote setpoint for FIC-1013 condensate make-up. FV-1016 fails closed on loss of instrument air. The valve is also furnished with a bypass and isolation valve for manual operation. FV-1013 fails closed on loss of instrument air and has isolation valves and a bypass line. A demineralized water line DM1012-1.5” is tied into the discharge kickback line of 110-J / JA, line PC1041-2" upstream of 153-D after passing through a non-return valve and is normally used to control water make-up to the OASE system. The make-up flow is controlled using a DCS controlled valve FIC-1013. It is expected that the OASE system will have a deficiency of water under normal operating conditions and that a make-up flow of approximately 100 kg/h will be required to maintain the water balance. This amount will vary depending on a number of factors including water losses and the pump seal flush arrangement as to whether it is using condensate or OASE solution. The released or desorbed carbon dioxide leaves the 122-D1 at a temperature of 77 °C as shown in the DCS on TI-1006 and pressure of 2.05 kg/cm²G, respectively before being cooled in 110-C to 38°C as shown in the DCS on TI-1406 with a high alarm. DCS Vent PIC-1104 controls the 122-Ds pressure through control valve, PV-1104A/B with a split signal of 0-30% for PV-1104A and 30-100% for PV-1104B. PIC-1104 has both high and low pressure alarms. A local pressure gauge, PG-1660, can be used to verify the pressure. The vent valves both fail open if control air or signal is lost. There is also a handjack provided with each valve. The CO2 is vented to the atmosphere through silencer SP-155. The CO2 flow to the vent is DCS indicated on FI-1023 and totalized on FQI-1023. These flows are pressure and temperature compensated in DCS function block FN-1023 using DCS TI-1406 for temperature which also has a high alarm and DCS PIC-1104 for pressure. AI-1103 analyses the H2 content in the CO2 outlet stream from 153-D. There is a grab sample point upstream of vent valves.

5.1.6.

Solution Flow

After contacting the raw synthesis gas in the 121-D beds, the liquid is nearly saturated or ‘rich’ with carbon dioxide and collects in the tower bottom. The rich liquid, at 85°C, as shown on TI1354, is controlled by LIC-1004 control system acting upon LV-1004A / B valve which bypass the hydraulic turbine and are split ranged, LV-1004A operates from 0-20% and LV-1004B operates from 20-100%. LV-1004A / B can handle 100% of the normal design flow whenever the 107-JAHT is out of service. The valves fail closed on loss of instrument air supply. They can be fully isolated as a pair for maintenance and each has a handjack as well. LIC-1004 comes with both high and low level alarms. Section 5 – Process Operating Principles

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The tower bottom is instrumented with level gauges, LG-1604A/B and LG-1605A/B for local level observation. Level transmitter LT-1204 A/B/C indicates in the DCS on LI-1204 A/B/C with high and low alarms and will also alarm on DCS LALL-1204 and trip 121-D, should a low-low level occur through LSLL-1204 which institutes 2 out of 3 voting system. DCS XA-1056A/B/C will alarm for any of the three transmitter failures. The solenoid valves XY-1052A to XV-1052A must be reset in the DCS using handswitches HS-1052 and HS-1010 to reestablish their respective valve operation. The 121-D outlet line has a manual sample point for gathering rich solution samples and a double blocked drain with a globe valve for control to the sump for use during start-up and shutdown conditions. The normal 3870.1 ton/h flow of ‘rich’ solution is through the 107-JAHT, hydraulic turbine is automatically controlled by LV-1004A and / or LV-1004B which bypass the turbine and manually setting a constant flow through the hydraulic turbine with DCS HIC-1004, HV-1004 fails closed on loss of instrument air supply. The hydraulic turbine also has inlet and outlet isolation valves. Inlet isolation valve has a double block and bleed bypass to fill and pressurize the turbine. The hydraulic turbine is equipped with an overspeed trip. The trip, SSH-1207A/B/C, activates the safety shutdown through the PLC and sounds alarm SAHH-1207A in the DCS. HV-1004 will trip closed along with all trips related to trip activation block I-107JAHT if the 107-JAHT overspeed trips. The suction line to the hydraulic turbine incorporates a strainer to stop any tower debris from entering and damaging the turbine. The solution from 121-D is partially regenerated by expanding to a lower pressure as the flow nears the inlet to 163-D. The line size is smaller at the outlet of the hydraulic turbine to maximize pressure recovery in the turbine. The line then increases in size to 24", to accommodate solution flashing to maintain a stable flow regime. The line size at the inlet to 163-D further increases to 30”. A local pressure gauge, PG-1726, is located on this line just downstream of the hydraulic turbine and also PI-1093 which indicates on DCS. The solution mixes with the solution letdown from 142-D2 then enters the 163-D, HP Flash Column above the bed. The rich OASE solution inlet comes into the flash gallery at the top of the vessel where approximately 4.9 ton/h of CO2 and process gasses are flashed out of the solution and continue to 101-B as fuel. The OASE is level controlled with LV-1046 getting a signal from LIC-1046 which has a low and a high alarm. This flow is returned to 122-D1 for stripping. LG-1046 is provided for local indication and DCS indication LI-1048 which has highhigh alarm with a trip of I-163D that will close XV-1227. DCS indication TI-1418 is also located on

Section 5 – Process Operating Principles

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the exit line. There is a local sample point on the gas exit line and the exit OASE line for a grab samples. The gases continue on to the 163-D HP Flash Gas CO2 Scrubber. Internally the scrubber contains a bed of metallic packing. The gas contacting bed consists of bottom gas injection platetype bottom support which the rings rest directly on. The bed also has a top hold down grate. Located above the bed is a liquid distribution trough. The liquid inlet sparger is located above the bed. The bottom liquid outlet nozzle comes equipped with a vortex breaker. The tower top is fitted with a water wash system containing three wash trays. Condensate from 110-Js is used to wash any entrained OASE from the process gas stream before it passes through the demister pad. This flow is controlled with FIC-1030/FT-1030 to FV-1030. This water wash also serves as the make-up water to the system to maintain the system water balance and solution strength. FV-1030 fails close on loss of instrument air or control signal and has a double block and bleed arrangement. FV-1030 also has a bypass with a globe valve. There are three trays in the top wash section of the tower. The wash water flows across the trays washing the OASE from the synthesis gasses. The last tray flows to a liquid distributor and the wash water flows down and mixes with the circulating solution. From 163-D the flow continues via PV-1039B to flow to fuel and 1039A vent to hot vent header controls the pressure to fuel gas at 7.30 kg/cm²a..The pressure control of system uses PT1039/PIC-1039 which sends signal to both PV-1039BB and 1039A. PV-1039B operates from 050% and 1039A from 50-100%. There is a local pressure indicator PG-1649 located between PV1039B and 1039A for monitoring pressure. The 4703 kg/h(dry basis) gas flow is DCS indicated on FI-1163. There is a manual sample point for grab sampling the gas stream. There is a permanently connected nitrogen purge line to the gas line exit 163-D for purging during start-up and shutdown and to supply the necessary backpressure for liquid flows until flashed gases are available. This is a typical station with a double block and bleed valve arrangement with a non-return valve in between. The gases continue on to 101-B as fuel under pressure control by the DCS controller PIC-1039, which has a DCS high and low pressure alarm. The backpressure is controlled at 7.30 kg/cm²a. PV-1039B and 1039A are failed closed valves that has isolation valves and a bypass lines. PV-1039A is also a tight shutoff valve. Both valves have upstream and downstream isolation valves and a globe valve equipped bypass line. The 163-D mildly flashed rich OASE solution at 85°C (measured at TI-1418 on DCS) at a rate of 3866.3 ton/h. under level controller LIC-1046 is directed to the 122-D1 CO2 Stripper LP Section flash gallery. LV-1046 is located minimum distance to the 122-D1 and will fail to the open position

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if instrument air or control signal is lost and is equipped with a handjack for manual operation. Anti-foaming chemicals from 109-L is added to this line downstream of the LV-1046 valve from the OASE Antifoam Injection System through non-return and isolation valves. The major portion of the CO2 is flashed from the solution due to pressure reduction as it is letdown across LV-1046 and then enters the 122-D1 low pressure stripper section. The solution flows down through the packed bed where it is contacted by warm up-flowing vapors from 122D2 causing additional stripping to take place. There is a grab sample point above the bed in the tower for use in troubleshooting the system. The solution collects in the bottom of the vessel which serves as the suction drum for the 107-Js and for the 117-Js pumps. 122-D1 has level glass, LG-1641A/B/C in the bottom section for local level indication. There are also three level transmitters. LT-1045A/B/C has an associated low low level alarm LALL-1045 in the DCS and low-low level switch LSLL-1045 which will lead to I-107J upon a low-low level as well as sound DCS alarm LALL-1045. LI-1041 is also included and has both a high and low level alarm to the DCS. The solution from 122-D1 exits the vessel at 78.3°C as indicated on TI-1409 in the DCS. The total design flow is 3797.9 Ton/h and it is divided into two streams: 1. 685.2 ton /h to the 117-Js 2. 3112.7 ton /h to the 107-Js The flow through the 117-Js is controlled by DCS controller FIC-1017 with a low flow alarm attached sets the flow rate of the semi-lean OASE to the 122-D2 CO2 Stripper Stripping Section, FIC-1017 receives the level in 122-D2 from LIC-1042. FV-1017 fails open upon air / control signal loss and has a handjack for manual operation. This flow continues on through 112-C/CA Lean / Semi-lean exchanger where the semi-lean flow is heated to 99°C as DCS indicated on TI1668 and locally on TW/TG-1685. The semi-lean flow inlet the exchanger passes through an inline inlet strainer (SP-STR-112C1) to prevent fouling of the plate and frame exchanger the strainer also has PDG-1062 that locally indicates the pressure drop across the strainer. The exchanger can be isolated and bypassing the exchanger using line MEA1078-18” is provided. The flow continues on to the upper section flash gallery of the 122-D2. The solution from 117-Js going to 122-D2, flows down through the packed bed where it is met by counter-flowing vapors that strip the remaining CO2 out of the solution stream. The solution from the top section of 122-D2 is then directed through the 105-C, CO2 Stripper Reboiler. The lean solution is partially vaporized in the 105-C by the exchange of heat from the LTS effluent stream and then is returned in two separate streams to the 122-D2 separation area in the tower bottom. The liquid drops out as it enters the tower and vapors flash up through the tower to aid in stripping the solution cascading down through the bed.

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The reboiled solution is level controlled in the bottom section of 122-D2 by DCS LIC-1042 with high and low level alarms. LT-1042 sends a remote setpoint to DCS FIC-1017 which controls the flow of lean OASE solution into the upper section of the 122-D2 CO2 stripper . The bottom section of 122-D2 has a level glasses LG-1642A/B for local level indication. There is also a separate SIS level transmitter LT-1043 A/B/C with two low level alarms, one being LI-1043A/B/C in the DCS , and a low-low level alarm LALL-1043 from switch LSLL-1043. LSLL-1043 trips the 108-J / JA if a low-low level exists by utilizing a 2 out of 3 voting system and sounds a DCS alarm on LALL-1043. The temperature of the solution outlet the 122-D2 is monitored in the DCS on TI-1407. Transmitter failure is indicated at XA-1043 A/B/C. The second flow stream of the 117-Js is manually controller through a set of mechanical filters in 104-L using an inlet globe valve. The make-up flow from the storage area 111-J pump ties into this line as well. The flow passes through a non-return valve and is measured in the DCS on FI1113A and locally on FI-1113B before going on to the 122-D1 entering below the packed bed. 104-L pressure drop is shown in the DCS on PDG-1118. The filter can be isolated and drained for on-line maintenance. The two motor driven 117-J pumps are provided with suction and discharge isolation valves as well as with suction strainers to remove damaging trash from the OASE stream prior to entering the pump. These suction strainers have PDG-1667/1668 indicating differential pressure across them locally. Both pumps also have a warm up line in the discharge line. This line uses a manually operated globe valve to direct flow from the common discharge header around the discharge non-return valves in reverse flow to the pump suction to provide warm solution flow to have the pump near operating temperature should a rapid start be required. Each pump has a local discharge pressure gauge, PG-1665 for J and PG-1666 for JA, a local suction pressure gauge PG-1667 for J and PG-1668 for JA and DCS running indicators XL-1017 for J and XL1018 for JA. Both motors have local Start – Stop Hand switches HS-1047/1048. A manual grab sample cooler has been provided on the 117-Js common suction line. A local, manual antifoam shot pot has been installed for the quick injection of anti-foam into the pump suctions and on to the 122-D2 stripper, if required. There is also anti-foam injection from 109-L to the suction of pumps. A seal flush is also required for each pump. The flush media can be either OASE solution, demineralized water, or LP Flash Overhead KO Drum condensate. OASE solution will normally be used but can be switched to the other media. Seal flush water supply line has a gate valve and a non-return valve. The second and main flow of semi-lean solution is through the 107-J pumps and on to the center

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section of the 121-D absorber. Normally, the 107-JB, driven by the hydraulic turbine, 107-JBT, is in service with one of the two other pumps. 107-JA/JC are hydraulic turbine driven and motor driven respectively. Each pump has a suction strainer to remove damaging trash from the OASE stream prior to entering the pump. Each pump has a suction and discharge pressure gauge, PG-1707 and PG1619, respectively for JA, PG-1708 and PG-1620, respectively, for JB and PG-1709 and PG1621, respectively, for JC. A seal flush is also required for each pump as well as the hydraulic turbine. The flush media can be either OASE solution, LP Flash Overhead KO Drum condensate or demineralized water during start-up. OASE solution will normally be used but can be switched to either of the other media. 107-JC motors have DCS running indications on XL-1019C. Approximately 3112.7 ton/ hr, of the total flow then enters the 121-D between the second and third beds at 78°C. This solution will remove 99% of the CO2 in the process gas stream. This flow is controlled from the DCS by FIC-1005 which has both high and low flow alarms. Low flow alarm FSL-1005 will auto-start the spare 107-JC pump on low. FV-1005 valve fails open on loss of control signal or instrument air and comes with a handjack also to be provided with a mechanical stop for minimum flow rate recommended by the pump vendor. The flow into the absorber is through a pair of dissimilar non-return valves to prevent a backflow of gas to the pumps. SIS FSLL-1205 from the separate FT-1205 A/B/C transmitter will activate on low-low semi-lean flow and trip the 106-D methanator after a 20 second time delay if flow is not restored and will alarm on FALL-1205 in the DCS. FSLL-1205 institutes a 2 out of 3 voting system FI1205A/B/C flow is indicated in the DCS. XA-1054A.B/C transmitter failure alarm will sound in the DCS if that condition occurs. XA-1054A/B/C has DCS alarm indicating transmitter failure of A/B/C. The solution from 122-D2 lower section passes through the other side of the 112-C/CA Lean/semi-lean solution exchanger giving up its heat to the solution from 117-Js going to 122-D2. An inlet strainer is provided in the solution line to protect the plate and frame exchange from fouling with a local PDG-1061 indicating the pressure drop across the strainer. The flow exits the exchanger at 88°C as seen on local TW/TG-1669 and passes through the 109-C plate and frame exchanger. Here it is cooled to 74°C (TW/TG-1675) against demineralized water. The demineralized water flow is indicated by FI-1056 with local exit DM water temp indicator TW/TG-1670. The flow exits

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and passes through the 108-C/CA plate and frame exchanger where it is cooled to 50ºC (TIC1672) by cooling water. There is a local PDG-1063/6011 which indicates pressure drop across the strainer in the cooling water inlet line. There is a bypass line MEA2210-16” that bypasses both 112-C/CA, 109-C and 108-C/CA. Downstream of the 108-C/CA DCS temperature TI-1672 is there. There is local TW/TG-1671 on the cooling water exit. A grab sample point has been installed exit the 108-C/CA. Numerous drain points are provided to the OASE drain system. Antifoam can be injected to the lean solution stream upstream of the 108-J pumps in the common suction line. The line CF1001-1.5” from 109-L is furnished with isolation, non-return, and drain valves there is also a shot pot injection provided. Normally, one 108-J is in service with the other pump in standby ready for autostart if required.108-J is a turbine driven pump and 108-JA is motor driven. Suction strainers to remove damaging trash from the OASE stream prior to entering the pump are provided as well as a warm up line in the discharge line. PDG-1264/1265, indicate the pressure drop across these strainers. Each pump has a suction and discharge pressure gauge, PG-1693 and PG-1671, respectively, for J, and PG-1694 and PG-1672, respectively, for JA. Just downstream of the 108-J pumps, line MEA1064-1½” takes off through isolation and non-return valves to supply OASE for seal flushing to the 111-J, 117-Js, 107-Js and 107-JAHT as described before. There is also a deinventorying line MEA1001-3”, with a double block and bleed with a globe valve to the 114-F OASE storage tank. There is a DCS pressure indication on the common 108-Js discharge line PI-1116 with a low-low alarm on PI-1116. PI-1116 will autostart 108-JA. DCS indication TI-1331 with a high alarm shows discharge temperature. The remaining 632.9 ton/ hr, of flow from the 108-J / JA lean solution pumps then enters the 121D above the first bed at 50°C. This solution will remove 1% of the CO2 in the process gas stream. This flow is controlled from the DCS by FIC-1014 which has both high and low flow alarms. FV-1014 valve fails open on loss of instrument air or control signal and comes with a handjack. The flow into the absorber is through a pair of dissimilar non-return valves to prevent a backflow of gas to the pumps. FSLL-1214 from the separate SIS FT-1214 A/B/C transmitters will activate on low lean flow and trip the 106-D methanator after a 5 second time delay if flow is not restored and will alarm on FALL-1214 in the DCS. The flow is DCS indicated on FI-1214A/B/C. XA-1055 transmitter failure alarm will sound in the DCS if 1214 A/B/C fails.

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OASE Auxiliary Equipment

Auxiliary equipment associated with the OASE System is as follows: • 114-F - OASE Solution Storage Tank • 111-J - OASE Transfer Pump • 115-F - OASE Solution Sump • 115-J - OASE Sump Pump • 110-L - OASE Solution Mixer • 115-L - OASE Sump Filter • 109-L - OASE Antifoam Injection System OASE Solution Storage Tank, 114-F, is an atmospheric tank. A DCS temperature indicator, TI-1659 shows the temperature of the solution in the tank. The tank is designed to hold a minimum of 115% of the designed OASE solution quantity. There is a local level indicator, LG-1800 as well as a DCS level indicator LI-1047 with a high level alarm to indicate the level in the tank. Provision has been made to blanket and purge the atmosphere above the stored solution level with nitrogen to prevent the build up of hydrogen in the tank and to keep air from entering the tank creating a potential for an explosion. Purge is accomplished pressure control valves, PCV-1676, in the nitrogen supply line. PCV-1676 is installed downstream of FI-1120. Local rotameter, FIT-1120 indicates on DCS at FI-1120, showing the nitrogen flow and has a high and a low alarm. The nitrogen line can be isolated upstream and has a non-return valve to prevent backflow. The overflow line and the inlet for the recycle / main system draining have been provided with dip legs that remain below the OASE solution level to prevent air from entering the tank. The overflow line also has a siphon break so that accidental siphoning of the solution to the sewer is prevented. The tank 3" drain can be drained to the 115-F sump or to external drums or tanks. Three sources of solution or water to the 114-F are: 1. OASE Solution Make-up System 2. 108-Js discharge pump out line 3. Demineralized water 114-F is protected from overpressure by vacuum / relief valve PRV-114F set at 90.0 mm/ -25mm H2O (G). OASE solution is pumped out of 114-F using 111-J OASE Transfer Pump. 111-J is motor driven and equipped with a suction strainer for debris removal, PG-1669 suction pressure gauge, PG-1670, discharge pressure gauge and a sample point on the suction line for grab sampling. The pump has both suction and discharge isolation valves and a discharge non-return Section 5 – Process Operating Principles

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valve. A DCS running indication XL-1011 has also been provided. The solution can be transferred to the following points: • Recycled directly back to 114-F for mixing through line MEA1127-3” with isolation and nonreturn valves • To 117-Js discharge line inlet to 104-L mechanical filter to inventory the system The OASE Solution Sump 115-F is below the ground level and is used for mixing solution components for injection into the system and to collect the drips, spillage, blowdowns, etc. that enter the dedicated OASE sewer system for transfer or disposal. The sump contains: flow control • OASE motor driven Solution Mixer 110-L with DCS run indication XL-1001. • Motor-driven pump, 115-J The tank is used for preparing the solution; therefore, a demineralized water supply is also provided. Accumulated solution is analyzed for strength and then either: sent to the storage tank through the 115-L filter; mixed with additional concentrated OASE to increase the strength then sent to storage; or recycled back to the sump. 115-J, pumps solution through the 115-L OASE Sump Filter, which is provided to mechanically filter out particles. The pump has a local discharge pressure indicator, PG-1308, and the flow can be manually recycled directly back to the sump, if desired, through a globe valve. The pump has discharge isolation and non-return valves as well as a grab sample point. The pump is protected from running dry by DCS level indicator LI-1119A with a high and low level alarm which will stop the pump when initiated. 115-J has a DCS running indication XL-1012. 115-L can be isolated and bypassed while the system is in service and drained for cartridge repair. DCS differential pressure indication PDG-1115. The solution circulation line MEA1127-3” has a non-return valve upstream of the filter inlet. The filter outlet line MEA1270-4” to 114-F has a non-return valve also. OASE Antifoam Injection System, 109-L, is a skid mounted system comprised of an antifoam injection tank with level glass LG-1809, motor driven mixer and two antifoam injection pumps. Both pumps will be able to pump to the three injection locations mentioned previously. Each of the injection pumps can be isolated for maintenance. There are individual suction strainers for sediment removal. Discharge pressure gauges, PG-1822 and PG-1823 are provided. Internal pump relief valves protect the system from overpressure. Each pump has a DCS running indicator XL-1126 for 109-L-J and XL-1127 for 109-L-JA. LI-1091 is provided to shutdown pumps on low level.

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The antifoam inhibitor is usually diluted with lean amine solution and periodically or continuously injected into the lean and / or rich OASE solution streams as needed.

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Methanator (Carbon Oxides Removal)

The inlet and outlet design gas compositions for the methanator are as follows:

H2 N2 CH4 Ar CO

= = = = =

Inlet 65.41% 32.03% 1.74% 0.38% 0.38%

Outlet 64.94% 32.47% 2.20% 0.39% ≤ 5 ppmv total Co plus CO2

CO2 =

0.05%

Pressure drop = 0.25 kg/cm2 The process gas is heated to 316°C before entering the 106-D, Methanator. This gas exchanges heat with the methanator outlet gas stream in the 114-C, Methanator Feed / Effluent Exchanger. The gas stream leaves the 114-C’s tubes at 310°C as indicated on the local temperature indicators TI-1616. The process gas then enters the 172-C, Methanator Heater, where high pressure saturated steam is used to raise the temperature to the 316°C needed to ensure full methanation of CO and CO2 to methane, CH4 and water. The inlet temperature to the 106-D is controlled from the DCS by TIC-1012 with both high and low alarms or from TIC-1392 exit the methanator which has a high alarm. There is a manual by-pass with butterfly valve TV-1012A and local temperature indicator TW/TG-1833 on the exit of 172-C before the manual by-pass tie-in. Two valves are controlled by split range application. They open TV-1012A in the line that bypasses the 114-C’s tubes and the 172-C Methanator Heater exchanger to cool the inlet temperature and open TV-1012B control valve in the HP steam line to the 172-C to warm the inlet temperature. TV-1012A is fully open at 100% and closed at 50% while TV-1012B is fully closed at 50% and minimum mechanical stop at 5 % open. TV-1012A valve fails closed and TV-1012B valve fails open if instrument air or controlling signals are lost. A handjack is incorporated for manual operation on both valves. The condensate formed in 172-C is let down by DCS indication LIC-1010 which gets it signal from LT-1010 level transmitter on 172-C and operates LV-1010. There is also a sightglass LG-1610 for local indication. LIC-1010 has a high and low level alarm The condensate is directed to 101-U Deaerator to recover flash steam and condensate.

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The inlet line to the methanator contains motor operated isolation valve MOV-1011 and isolation valve XV-1211. These are located upstream of 114-C’s tube inlet and upstream of bypass line PG1028-12” tie-in. XV-1211 is a fail closed valve if the instrument air is taken away from the valve and is a tight shutoff valve. The solenoid XY-1211 in the air supply to XV-1211 trips the valve due to either bypassing of 104-D2 LTS, low-low OASE solution flow or high-high 106-D bed temperatures and must be DCS reset using handswitch HS-1211 for the valve to reopen. ZLO / ZLC-1211 indicate valve position of XV-1211 on DCS. MOV-1011 is an inching valve using DCS configured hand switch HS-1011 for control and position indicator ZLO / ZLC-1011 also on the DCS. The valve also comes with a handjack for manual operation during power outages or motor failures and a 1½” normally closed, double block and bleed type pressuring bypass line is also provided. WARNING The two 1½” pressuring valves MUST be closed and the bleed valve opened after use to prevent bypassing of gas containing high concentrations of CO or CO2 during a shutdown. XV-1211 is not to be considered a tight shutoff valve and is used to quickly shut off the bulk of the flow until the MOV-1011 can securely isolate the vessel. The MOV-1011 and XV-1211 are a part of the methanator automatic shutdown logic. Emergency shutdown switch HS-1253 is provided in the control room. Pressure controller PIC-1005, operates PV-1005 located in vent line V2203 upstream of MOV-1011, serves to maintain the process system pressure at 37.44 kg/cm²a, if the methanator shutdown logic is activated, by venting gases to the hot vent silencer. PV-1005 is a tight shutoff class that fails closed when there is no instrument air or control signal available and a handjack has been provided to operate the valve manually. There is also an upstream isolation valve. Local PG-1622 indicates the pressure at this point. 106-D contains the nickel catalyst required for reacting carbon oxides with hydrogen to form methane and water. The reaction is exothermic and highly active and the exit temperature, based on design conditions, is expected to be 344°C. Therefore, the temperature profile across the catalyst bed is continuously monitored by DCS TI-1357 and TI-1362 at various levels. All of the temperature points contain high temperature alarms. Pressure drop across the vessel is DCS indicated on PDI-1072A with a high alarm. Four levels of high, high temperature switches, TSHH-1200 through 1203, will activate the methanator shutdown logics and initiates alarms in the DCS on TAHH-1200 through 1203 when the temperature reaches the trip point on 2oo3 of the transmitter group. In order to prevent Section 5 – Process Operating Principles

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nuisance trips, the thermocouples are designed to give very low temperature readings if they burn out or fail. All of the temperature points contain high temperature alarms. These high temperatures will be alarmed in the DCS on TI-1200A/B/C through TI-1203A/B/C. Transmitter failures will be alarmed on DCS on XA-1200, XA-7813, XA-1202 and XA-1203 A/B/Cs. An emergency nitrogen line, N1007-2”, with a double block, bleed with figure ‘8’ blind, and non-return valve between the blocks to prevent flowing process gas into the nitrogen system, has been tied in to the outlet line of 106-D in case the catalyst temperatures become extremely high due to a breakthrough of CO or CO2. The pressure shell is designed for 457°C at 40.3 kg/cm²g.

WARNING If the bed temperatures exceed this value, the 106-D must be immediately depressured. This can be accomplished by opening the 3" vent line inlet the vessel, V1011-3”. A flow of purging and cooling nitrogen can then be put through the vessel using the emergency line and vented to a safe location away from the operator. Both the nitrogen line and the vent line have a globe valve for better control of the gas flow / pressure. The methanator effluent, at a temperature of 344°C, is cooled to 4°C by flowing in series through the shell side of exchanger 114-C’s, shell side of 115-C, Methanator Effluent Cooler, and then the tube side of 130-Cs, Methanator Effluent Chiller, before entering the Methanator Effluent Separator, 144-D. PG-1623 is a local pressure indicator on the 106-D outlet line. The methanator effluent gives up heat to the methanator inlet gas stream in 114-C’s and to the cooling water loop in 115-C. DCS temperature indicator, TI-1615 indicates the 114-C’s shell outlet temperature of 84°C. Local TW/TG-1617 indicates the cooling water temperature exit the 115-C. The gas at this point is continuously DCS monitored on AE-1003 as follows: • AI-1003A for CO • AI-1003B for CO2 AI-1003A/B each have a high alarm. A sample point is also provided for taking grab samples. In 115-C, the gas is cooled to 38°C as shown on DCS TI-1618. Upstream of 130-C the scrubbed purge gas outlet of the 124-D HP Ammonia Absorber merges after passing through a non-return valve and isolation valve. The process gas flow then continues on through 130-C’s Methanator Effluent Chiller where it is Section 5 – Process Operating Principles

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cooled against ammonia from 149-D to 4°C as indicated in the DCS on TI-1363. TI-1363 has a high and low temperature alarm to warn the operators against potential freezing of the exchanger tubes. 97% of the water vapor in the gas stream is condensed and separated in the 144-D before entering the molecular sieves. Liquid Ammonia level in 130-C1 from the 149-D is indicated, maintained, and alarmed for both high and low conditions by LIC-1009. whereas LIC-1118 maintains level in 130-C2. LV-1009/LV1118 are fail closed valves if instrument air or control signal fails. Both have isolation valves and a bypass so it can be manually operated if necessary. Level glass, LG-1117 is also provided. 130-C2 shell side may need to be drained (blown) down periodically to remove any water build up from the system. Water can accumulate from the minute quantities that come back with the ammonia recovery system ammonia to the refrigeration system. The water joins with the ammonia and is directed through the refrigeration system. Ammonia containing minute quantities of water from 149-D is sent to 130-C2 via 130-C1, where the ammonia is flashed off leaving part of the water behind to change the ammonia concentration in the reboiler. After a period of time, water accumulation can affect (increase) the temperature to 144-D causing more water loading to the 109-Ds. A line NHL1132-2” going to 120-CF1 has been provided for this. This line has a double block and bleed isolation system as well as an additional upstream isolation valve. Care must be used during the draining to avoid ammonia release to the atmosphere and for the safety of personnel. DCS pressure controller, PIC-1114, with both high and low alarms, is provided to maintain the backpressure necessary to obtain the 4°C on the exiting process gas stream. The ammonia vapors will normally return from 130-C2 through PIC-1114 to 120-CF3 and the valve fails, on loss of instrument air / control signal, to the closed position but comes equipped with a handjack for manual operation. There is a local pressure indicators PG-1627 for 130-C2 to give the backpressure on the shell. Downstream of PV-1114 there is a take off for ammonia to 107-L injection system.

Section 5 – Process Operating Principles

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The inlet for the 144-D design gas compositions are as follows:

H2 N2 CH4 Ar NH3 CO

= = = = = =

Inlet 64.94% 32.47% 2.20% 0.39% 0.000% ≤ 5 ppmv

CO2 =

The Methanator Effluent Separator, 144-D, contains an inlet sparger, an outlet vortex breaker on the liquid side, and a demisting pad for the vapor outlet. The water formed during methanation and condensed in cooling by the exchanger train is disengaged in the drum and withdrawn by motor-driven 122-J and JA pumps. DCS level controller LIC-1008 with high and low alarms goes to 142-D1 through FI-1109 after passing through non-return and isolation valves. Line PC-10101" goes to 142-D2 through FI-8004 but is taken off upstream of FV-1018 and comes off of 110-Js. 122-J or JA will pump up to the 1545 kg/h of recovered condensate under the control of LIC-1008 to the 142-D1. The pump has suction and discharge isolation valves and a discharge line non-return valve. The minimum flow requirements of the pump are handled by a manual line back to the 144-D. The minimum flow line contains a non-return valve, restriction orifice and car-sealed open (CSO) isolation valve. 122-J has a local PG-1724 downstream of the suction strainer and a discharge PG-1625. 122-JA has a local PG-2002 downstream of the suction strainer and a discharge PG2003. There is a DCS pump running indication on XL-1022 and XL-2002. A manual grab sample point is provided on the exit line of 144-D. LIC-1008 has both high and low level alarms and LV-1008, which has isolation valves and a bypass for manual operation, will fail closed on loss of instrument air supply. There is a 1.5" drain line with a gate valve for isolation that can be used to lower the drum level should the pump fail or in an emergency and send it to sewer, if needed. 144-D is instrumented with a level glass, LG-1608, a separate DCS level indicator LI-1208 with high-high and low level alarms and LSH-1208, a high level switch. The process system pressure of 36.0 kg/cm²a at 144-D is DCS monitored on PIC-1084 with a local pressure gauge PG-1624. The system at 144-D is protected from overpressure by safety relief valve PRV-144D. This is set to open at 38.3 kg/cm²g relieving to the cold vent system. PV1084 which also vents to the cold vent system fails closed on loss of control signal or instrument Section 5 – Process Operating Principles

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air and has a handjack. It can be isolated upstream. PV-1084 is a tight shut off valve. The gas stream flowing from 144-D is continuously analyzed by the on-stream mass spectrometer AT-1002 for the following gases: • AI-1002 - H2/N2 • AI-1002A - Methane • AI-1002B - Hydrogen • AI-1002C - Nitrogen • AI-1002D - Argon A manual grab sample point is also provided.

5.1.9.

Molecular Sieves

After separation in 144-D, the fresh make-up synthesis gas passes through one of two Molecular Sieve Driers, 109-DA / DB. These driers remove the moisture and carbon dioxide from the gas stream to below 1 mg/m3v for CO2 and less than 0.1 mg/m3v for water by adsorption on Zeolite beads. Water has a greater affinity for the Zeolite than CO2 and will be adsorbed in preference over CO2. If CO2 has already been adsorbed on a specific site on a bead and water passes by that bead, the water will force the CO2 off to find another site. This means that CO2 will break through the beds first and stresses the importance of good methanator operation. There are two filters, 154-LA and LB to trap any Zeolite beads and dust that may pass through the supports. Each filter has a DCS monitored differential pressure indicator with a high alarm. PDG-1086 and PDG-1085 for 154-LA and 154-LB, respectively. Downstream pressure is locally indicated by PG-1087 for 154-LA and upstream pressure at PG-1089 for 154-LB. The two 109-Ds are in a parallel arrangement, such that each has a 24-hour on stream time while the other is being regenerated for approximately 23 hours or in standby for 1 hour. All steps in the operation of the Molecular Sieves are controlled by a PLC, KIC-1001. The operators cannot intervene in the programming except to stop (delay) the program in a given step and to start or stop the PLC using control room mounted hand switch HS-1014. A trip of the Methanator 106-D will also stop the program timer and closes the inlet MOV valves to the molecular sieves, MOV-1017 and MOV-1018. There is a common trouble alarm in the DCS, KA-1001, to indicate PLC system problems.

Section 5 – Process Operating Principles

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Molecular Sieve valving is as follows: • All valves are tight shutoff class and have handjacks except HV-1022, HV-1023 and PV1008, which are not tight shutoff class but have handjacks. • All pneumatic valves fail closed on instrument air loss except PV-1008 and HV-1022 which fail open • Inlet and outlet motor operated isolation valves, MOV-1017 and MOV-1018, for DA and DB respectively, on the inlets and MOV-1015 and MOV-1016 respectively on the outlets. • depressuring valves, PV-1047 for 109-DA and PV-1048 for 109-DB • regeneration inlet gas valves, XV-1160 on DA and XV-1161 on DB • regeneration outlet gas valves, XV-1164 on DA and XV-1165 on DB • repressuring valves, PV-1049A and PV-1049B • regeneration flow forcing valves, HV-1022 and HV-1023 • The Orbit Brand valves and others similar have specific directions for which to seal against higher pressure to avoid leakage and these must be properly installed in order to have a tight sealing system All of the valves on the units have either open and closed or just closed limit switches reporting to the PLC as follows:

MOV-1017 MOV-1018 MOV-1015 MOV-1016 XV-1160 XV-1161 XV-1164 XV-1165 HV-1022 HV-1023 PV-1047 PV-1048 PV-1049A PV-1049B

Open

Closed

ZSO-1017 ZSO-1018 ZSO-1015 ZSO-1016 ZSO-1160 ZSO-1161 ZSO-1164 ZSO-1165

ZSC-1017 ZSC -1018 ZSC -1015 ZSC-1016 ZSC-1160 ZSC -1161 ZSC -1164 ZSC -1165 ZSC -1022 ZSC -1023 PZSC -1047 PZSC -1048 PZSC -1049A PZSC -1049B

None None None

PV-1047, PV-1048, PV-1049A and PV-1049B have single isolation valves, while all other valves in the system do not have isolation valves. The normal regeneration sequence will divert approximately 21277.5 kg/h, of purifier waste gas from 132-C Purifier Feed / Effluent Exchanger through the Molecular Sieve Regeneration Section 5 – Process Operating Principles

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Heater, 183-C, and heat it to 245°C by exchanging against medium pressure steam. This flow is controlled in the DCS on FIC-1046. FIC-1046 receives a ramped remote setpoint from KIC-1001. FV-1046 is a tight shutoff class valve that fails closed on loss of control signal or instrument air and is handjack equipped for manual operation. FSLL-1046 low-low flow will stop PLC sequence timer. A nitrogen line N1254-2” has been permanently tied-in to the waste gas inlet line to 183-C. The nitrogen line is isolated by a double block and bleed system with a nonreturn valve in between and a figure ‘8’ blind. TI-1041 also monitors the temperature of the regeneration gas in the DCS and has a high and low alarm. There is a second source of regeneration gas should the Purifier not be in service. It comes from the common outlet line of 109-Ds through line SG1414-8” and that line ties-in upstream of FE1075. Dry synthesis gas will be provided through a double block and bleed valving system for use as the regeneration medium and controlled in a similar fashion as described for the Purifier waste gas. The 183-C bypass line is used for deriming the purifier and has a globe valve for control of this flow. This temperature will be controlled by DCS TIC-1040 with a high alarm adjusting the TV1040 which brings hot gas flow through the 183-C shell. TV-1040 valve fails closed if instrument air supply or the control signal is lost and is furnished with a handjack for manual operation. A manual grab sample point is provided on line SG1412-14”. There is a removable spool piece in the derime line SG1049-3” for positive isolation. Heat for the regeneration of the molecular sieves is supplied from medium pressure steam taken to the tube side of 183-C. The 183-C tubes side can be fully isolated by a valve upstream of the exchanger and downstream of LV-1050 condensate level control. The pressure can be seen locally on PG-1727. The condensate is let down to the 101-U deaerator for reclaiming through LV-1050 which has upstream and downstream isolation valves and by-pass with globe valve. DCS indicator LIC-1050 has a high and low level alarm. LG-1650 is provided for local indication. The steam side remains in service at all times even if regeneration gases are not flowing. As the regeneration gas passes through the 109-Ds, temperature indicators TI-1663 for 109-DA and TI-1664 for 109-DB will indicate in the DCS the regeneration inlet gas temperature. TI-1834 for 109-DA and TI-1835 indicate the regeneration gas exit. DCS TI-1043 is provided in the exit common header downstream of vessels. Vessel pressure indication is done by pressure transmitters PT-1047B on 109-DA outlet and PT1048B on 109-DB outlet both reporting to the KIC control PLC. Local gauges PG-1710 on 109DA and PG-1711 on 109-DB can be used for pressure indication. DCS pressure indication is also available on PI-1047A for DA and PI-1048A on DB. These are also the pressures that go to the KIC-1001 for controlling pressurization and depressurization. There are DCS pressure

Section 5 – Process Operating Principles

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indications on 109-DA inlet on PI-1047B and on 109-DB inlet on PI-1048B. Each vessel also has a DCS pressure drop indication with PDI-1047 on 109-DA and PDI-1048 on 109-DB. These receive signals from the previously mentioned inlet and outlet pressure transmitters and calculate a pressure drop. After use as regeneration gas, the waste gas is sent to the 101-B fuel gas system. It is passed through the 144-L Waste Gas Filter to remove any Zeolite particles that may be entrained in the gas stream. 144-L can be isolated and bypassed for on-line maintenance. DCS PDG-1732 with a high alarm indicates the filter differential pressure. Local PG-1730 shows the filter outlet pressure. After leaving the 109-Ds, at 4°C, the stream is continuously analyzed for water by AE-1014 and DCS indicated on AI-1014 with a high alarm. A DCS common trouble alarm XA-1046 will sound upon analyzer failure. The stream is also analyzed for CO2 by AE-1020 and DCS indicated on AI-1020 which has a high alarm. The synthesis converter catalyst design is based on 3 mg /m3v maximum oxygen compound content. A local grab sample point is provided on both.

5.1.10.

Purification

The purifier design gas compositions are as follows:

H2 N2 CH4 Ar NH3

Inlet 64.94% 32.47% 2.20% 0.39% 0.000%

Outlet 74.84% 24.96% 0.00% 0.19% none

Waste 6.25% 76.95% 15.23% 1.56% none

The process gas from the molecular sieves continues on to the purifier where all of the methane, about 50% of the argon is removed from the gas stream and about 24% of the nitrogen is removed by liquefying the gases in the purifier then adjusting the amount of nitrogen that is regasified in the synthesis stream to achieve a 3 to 1 H2 to N2 ratio. The purifier can be isolated both inlet and outlet and can be bypassed using line SG1065-14” which is contains double block and bleed valving. The inlet and outlet isolation valves have pressuring bypass lines – 1½” on the both side . The inlet isolation valve is MOV-1051, the outlet is MOV-1053 and the by-pass is MOV-1052. MOV-1052 has a double block 1.5” by-pass for pressuring. HS-1051, HIC-7815, and HS-1053 is provided to open and close MOVs. Each valve also has a handjack for manual operation. Just downstream of the inlet isolation valve is a Section 5 – Process Operating Principles

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manual double block and bleed vent to the NH3 vent system. Local PG-1635 can be used to see the pressure while using this vent. There is also a removable spool piece on the inlet piping to 132-C. The inlet strainer pressure drop is monitored for high differential pressure and DCS indicated on PDI-1099 with a high alarm. Temperatures are shown on DCS TI-1430 at 4°C temperature to the 132-C, TI-1431 exit 132-C at -129.0 °C. The gas flow continues through the 131-JX expander turbine to cool the gas by energy removal to get the refrigeration required to liquefy the gases. The energy of the expanding gases is turned into electrical power in 131-JG generator From 131-JX, TI-1432 shows the gas temperature to the 132-C Purifier Feed / Effluent Exchanger at -131.3 °C. The flow is split into two paths entering 132-C where the gas is cooled to -172.6 °C as indicated in the DCS on TI-1438. The process feed gas is cooled by the purifier effluent process and waste gases. The gas flow to the expander turbine goes through an inlet trip valve XV-1172, a strainer and a hand control valve HV-1111. HV-1111 is controlled by LIC-1034A in the bottom of the 137-D Purifier Rectifier. The inlet strainer pressure drop is monitored for high differential pressure and DCS indicated on PDI-6100. Prior to the inlet trip valve is a bypass line around the expander turbine with PDV-1022 control valve. DCS PDIC-1022 with a low and high alarm measures the pressure drop from the turbine inlet to the outlet, including the inlet strainer and valves listed above, and if the differential pressure becomes too great it will open PDV-1022 bypassing the turbine. PDV-1022 fails open on instrument air / control signal failure and has a handjack for manual operation. XV-6100 and HV-1111 both fail closed on loss of instrument air and XV-6100 has a local valve position indication switch going to the DCS control panel at ZLO/ZLC-6100. 131-J is provided with two casing drain lines – one with a manual gate valve and another having DCS HIC-1303 The local control panel has a number of indicators and safety instrumentation included – many which are mirrored on the DCS. The 131-JX will have a speed transmitter ST-1132 both local and in the PLC. The trip circuit will trip solenoid XY-6100 closing the inlet valve to 131-JX if power generation is too high and trip the expander turbine as stated before. Also supplied are: • HS-1213A/B - Local panel shutdown switch • HS-1012 A/B - Local stop switch • HS-1013A/B - local start switch • HS-1113A/B - local reset switch • XL-1210B - Common Shutdown system • XA-1210A - Common Trouble Alarm • SSHH-1131A/B/C - Local high-high speed alarm The gas flow at –134.1°C as indicated in the DCS on TI-1432 flows from 131-JX back to the 132C Purifier Feed / Effluent Exchanger. The temperature outlet of the 132-C will be –172.6 °C as Section 5 – Process Operating Principles

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indicated in the DCS on TI-1438 and flows to the bottom of the 137-D Purifier Rectifier. The liquefied methane, argon and nitrogen are separated here with the remaining gases flowing up the rectifier column’s 20 wash trays. The temperature of the column is DCS indicated on TI-1433. The rectifier pressure drop from the bottoms to the process gas outlet line is indicated in the DCS on PDI-1879 which has a high alarm. Local PG-1885 shows the rectifier process gas outlet pressure. The gas flow continues up through the center pipe of the 134-C Purifier Rectifier Condenser and is then redirected down through the tubes where additional liquefication takes place against the liquid from the rectifier bottoms. The process gas temperature exiting the 137-D is –178.6 °C as shown in the DCS on TI-1437. The liquid level in the rectifier bottoms is controlled by DCS LIC-1034 which has both high and low level alarms. This controller opens or closes the gas inlet valve to 131-JX expander turbine to add or remove refrigeration by expansion. LI-1034B indicates the level on DCS with high and low alarms. If the level increases, the valve is closed to reduce the amount condensed and viceversa. The –172.8 °C temperature of the liquid from the rectifier bottoms is DCS recorded on TI1434. There is a manual double blocked drain line from the 137-D bottoms to a flash pipe that can be used to drain the system for maintenance. WARNING This liquid nitrogen mixture has a temperature of -173°C which can cause severe and immediate injury if it touches any part of the body. Extreme care MUST be used when draining this system to avoid injury. This drain should NOT be used in case of a high-high level just to get the level back to normal. In addition, nitrogen and argon are heavier than air and will tend to flow downwards from the vent line displacing the air at ground level and has the potential to cause asphyxiation. The amount of liquid from the rectifier bottom to the shell side of the 134-C exchanger is DCS controlled by AIC-1029. AIC-1029 (I/P) goes to AV-1029 valve. AIC-1029 has a remote setpoint and receives input from AN-1029 which in turn calculates hydrogen to nitrogen ratio as analysed at AI-1029 B/C, Hydrogen and Nitrogen mass spec analyzers. A trip of the Methanator 106-D will activate solenoid AY-1029A and trip AV-1029 closed to retain the 137-D bottoms levels for as long as possible. Control room mounted handswitch HS-1214 must be used to reset the solenoid. AV-1029 valve has isolation valves and a bypass line with an HCV-1062 for manual control. The valve station is located external to the 137-L purifier cold box. A manual sample point is provided upstream of AE-1029 . The temperature of the liquid entering the 134-C is –185.6 °C as indicated in the DCS on TI1435. The temperature waste gas entering the 134-C exchanger is shown on DCS TI-1433 and Section 5 – Process Operating Principles

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exiting the 134-C exchanger shell is –181.0 °C as shown on TI-1445 also in the DCS. Both the process and the waste gases from 137-D enter different passes of the 132-C to exchange heat with the inlet process gas as described before. Each stream pass has DCS temperature indication as follows: • Process gas inlet– TI-1437 • Process gas outlet—TI-1439 A-D • Waste gas inlet – TI-1445 / 1446 • Waste gas outlet – TI-1440 A-D The stream from 134-C enters 132-C. Flow continues through 132-C which also has DCS temperature indications as follows: • Process gas – TI-1441 A-D, TI-1444 common line • Waste gas – TI-1442 A-D, TI-1443 common line From time to time, system upsets or even normal longer term operation can lead to the Purifier exchangers becoming fouled with solidified water, ammonia, and carbon dioxide. In order to gasify and remove these impurities, the exchangers must be heated and purged with a dry gas – a method called deriming. Heated nitrogen is supplied for this procedure. The nitrogen from line N1254-2” is heated in 183-C against medium pressure steam and is directed to the Purifier through line SG1049-3”. TIC-1040, as described previously, controls the temperature to the Purifier. A removable spool is provided in this line for positive isolation during normal operation. The deriming flow can be directed through isolation valves to the following points as required: • 132-C outlet line to 137-D • 137-D outlet line to 132-C • 132-C outlet line to 131-JX • 131-JX outlet line to 132-C The synthesis process gas combined stream outlet 132-C is directed to the 103-J Synthesis Gas Compressor. There is a grab sample point just exiting the 132-C and a manual grab sample point is also provided at a point which is located downstream of the purifier bypass line SG1411-18”. The gas stream is continuously analyzed by the on-stream mass spectrometer AT-1000 for the following gases: • AI-1029 A - Methane • AI-1029 B - Hydrogen • AI-1029 C - Nitrogen • AI-1029 D - Argon 2 The line pressure of 31.5 kg/cm²g can be seen locally on PG-1636 and the combined temperature of +1.8°C is shown on the DCS at TI-1444. The system is protected from an Section 5 – Process Operating Principles

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overpressure condition by PRV-132C1 relieving at 38.3 kg/cm²g to the NH3 vent. This PRV has a double block and bleed bypass line with a globe valve for controlled depressuring of the purifier after isolation. NH3 vent will go through NH3 flare unit. The waste gas exits the 132-C at +1.8°C as shown on the DCS indication TI-1443 and is directed to the molecular sieves regeneration system or to the fuel gas system through an isolation valve and a non-return valve. Local PG-1725 indicates pressure. There is a grab sample point provided on this line as well. The line and associated equipment are protected from overpressure by PRV132C2 set at 9.0 kg/cm²g relieving to the NH3 vent as well. This PRV also has the same bypass as described for PRV-132C1. The system is also protected from underpressure by PRV-137L1 which is set to relieve at -0.004 kg/cm²g. 2 The waste gas backpressure at 1.64 kg/cm²g is controlled by DCS PIC-1008 with a high alarm.

The pressure can be seen locally on PG-1766. PV-1008 fails open on loss of instrument air or control signal and has a handjack for manual operation. The 42555.0 kg/h waste gas flow as seen in the DCS on FI-1075, and which has a low alarm incorporated, is directed to three places: 1. 183-C - for molecular sieve regeneration 2. 109-D - for cooling down 3. 101-B - waste gas to fuel system Regeneration heating flow:

109-DA 109-DB

Gas in

Gas out

HV-1022 position

HV-1023 position

XV-1160 XV-1161

XV-1164 XV-1165

open open

closed closed

Gas in

Gas out

HV-1022 position

HV-1023 position

XV-1164 XV-1165

PV-1047 PV-1048

mostly closed mostly closed

open open

Regeneration cooling flow:

109-DA 109-DB

Section 5 – Process Operating Principles

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No Regeneration flows:

109-DA 109-DB

5.1.11.

Gas in

Gas out

HV-1022 position

HV-1023 position

N/A N/A

N/A N/A

open open

closed closed

137-L Purifier Cold Box

The purifier is one insulated box referred to as the cold box. The box will contain the 132-C, 131-JX, 137-D and 134-C. The boxes are well insulated between the equipment and the box walls and this insulation must be kept free of moisture to prevent freezing within the insulation and loss of heat. To assure this a continuous nitrogen purge of the box is provided. The nitrogen is supplied from the main plant header after being letdown through local pressure controller PCV-1185 to the header at the boxes. PCV-1185 has an upstream isolation valve and a local pressure indicator PG-1880 shows the header pressure. The nitrogen to the box containing the rectifier is manually controlled through three rotameter FI1175, FI-1176 and FI-1178. Each rotameter has an inlet needle valve for flow control and FI-1175 has an outlet gate valve for isolation. There is also a downstream local pressure gauge on these lines –PG-1876 for FI-1176 and PG-1025 for FI-1178 and PG-1875 for FI-1175. Each box is protected from both over and under pressure (vacuum) as below: • •

Exchanger box by PRV-137L-1 for overpressure and underpressure. The PRV-137L-1 setpoint is -0.004 kg/cm²g. Rectifier box by PRV-137L-3 through PRV-137L-10 for overpressure. The set points for these relief valves range between 0.005 to 0.015 kg/cm2G.

Section 5 – Process Operating Principles

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45. Ammonia Synthesis 5.1.12.

103-J Synthesis Gas Compressor

The inlet and outlet design gas compositions for the 103-J are as follows:

H2 N2 Ratio CH4 Ar NH3

2

Inlet

Outlet

74.84% 24.96% 3.00 0.00% 0.19% 0.00%

70.97% 23.74% 3.00 0.00% 3.47% 1.79%

The purifier exit gas flows to the synthesis gas compressor to first stage suction of 103-J. DCS PIC-1006 acts upon the valve rack of the MP steam extraction portion of the steam turbine driving 103-J compressor. In so doing, the suction pressure is maintained by allowing more or less steam flow to pass through the machine as the speed increases or decreases. PIC-1004 vents excess pressure to the cold vent system and has a high alarm associated with it. The normal operating pressure at this point is expected to be 32.5 kg/cm²a. PV-1004 is a tight shutoff valve with a handjack for manual operation and fails closed on loss of instrument air pressure with an upstream isolation valve. PG-1638 indicates the suction pressure locally. There is an isolation valve with a blinding station in the line to the 103-J first case. There is a blindable isolation valve with a single block bypass line to the 103-J first case.

2

The suction line to 103-J is protected from over pressure by PRV-103JS relieving to the ammonia cold vent system at 38.3 kg/cm²g. The 103-J is a double case, centrifugal compressor that consists of a makeup gas compression section and a separate synthesis gas recycle wheel for loop circulation. These gases are mixed internally, then compressed to 157.9 kg/cm²a at 72 °C before going to the synthesis loop. The recycle gas enters the compressor at 150.1 kg/cm²a and 33°C.

2

103-J incorporates all of the instrumentation to safely operate the machine. The suction has a local pressure gauge, PG-1639 as well as a temperature indication, TW/TG-1622 locally and TI-1368 in the DCS which has a high alarm. There is a suction strainer to keep any trash from entering and damaging the machine with PDI-6371 on DCS with high alarm. There is also a second suction pressure in the DCS on PI-1006.

Section 5 – Process Operating Principles

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The first stage discharge has two temperature indications, TW/TG-1623, locally and TI-1364 with a high alarm in the DCS. The discharge pressure is shown locally on PG-1640 in the DCS on PI-1077 There is a control room mounted flow measurement, FIC-1007, on the suction line which is pressure and temperature compensated using PI-1006/PT-1006 and TI-1368/TT-1368 from the machine suction, respectively, and PI-1077A/PT-1077 and TI-1364/TT-1364, respectively, on the discharge that serves as a part of the surge protection system. It also indicates flow on the DCS on FI-1007. FV-1007 is a tight shutoff class valve that fails open on loss of instrument air. There is a valve position indication in the DCS on FZLC/FZLO-1007. FV-1007 will fully open on a 103-J trip. The first stage discharge at 83.2 kg/cm²a passes through the shell side of 116-C Synthesis Gas Compressor intercooler shell where the temperature of compression is reduced from 111.6 °C to 38°C in exchange with cooling water. DCS TW/TG-1638 indicates the cooling water temperature exit the 116-C. Synthesis gas passes through a non-return valve then through XV-1103 which is a hydraulically assisted tight shutoff (TSO), non-return valve then is directed to the 103-J second stage suction. XV-1103 will trip shut on a 103-J trip through XY-1103 solenoid. ZLO/ZLC-1103 indicates position of valve on DCS. There is a control room mounted flow measurement, FIC-1008, on the suction line which is pressure and temperature compensated using PI-1082A/PT-1082 and TI-1365A/TT-1365 from the second stage suction, respectively, and PI-1044/PT-1044 and TI-1322A/TT-1322 on the suction of the third stage that serves as a part of the surge protection system. It also indicates flow on the DCS on FI-1008. FV-1008 is a tight shutoff class valve that fails open on loss of instrument air, it will also trip open on a 103-J trip. DCS FZLO/FZLC-1008 indicates position of valve. DCS TI-1365 and PI-1082 indicate temperature and pressure with high alarms. The second stage suction temperature is indicated locally on TW/TG-1625 and in the DCS on TI1365 with a high alarm. PG-1628 locally shows the suction pressure as well as PI-1082 on the 2 DCS. At the second stage suction, a strainer is provided to keep trash and foreign objects out of the machine. PDI-6372 on DCS with a high alarm indicates the pressure drop across the strainer. The make-up gas from the second stage is internally discharged to the recycle gas section of the compressor. The recycle gas suction has similar instrumentation with PG-1629 showing suction pressure locally as well as TW/TG-1624 for temperature and has a strainer to protect the last compressor wheel. Additionally, there is a DCS temperature indication, TI-1366 with a low alarm

Section 5 – Process Operating Principles

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and suction pressure on PI-1083. The 103-J discharge has a variety of pressure, temperature and flow instrumentation. Local TW/TG-1626 shows the discharge temperature while the pressure is read on PG-1630. The DCS also has pressure indication, PI-1045 and temperature indication, TI-1367 with a high alarm. Flow is measured on FIC-1059 in the control room, and indicated in the DCS on FI-1059, which serves as a part of the recycle anti-surge protection scheme. It is pressure and temperature compensated by PI-1083/PT-1083 and TI-1366/TT-1366 on the suction side and PI1045/PT-1045 along with TI-1367/TT-1367 on the discharge. Control valve FV-1059 fails open on loss of instrument air and is a tight shutoff class of valve. There is a DCS valve position indication attached on FZLO/FZLC-1059. The valve is provided with a figure ‘8’ blind for compressor isolation. At the third stage suction, a strainer is provided to keep trash and foreign objects out of the machine. PDI-6373 on DCS with a high alarm indicates the pressure drop across the strainer The 103-J recycle gas flow is cooled in the 124-C1/C2 Ammonia Converter Effluent Cooler from the compressor discharge line. This cooler protects the 103-J over a range of operating and start-up conditions by cooling the kickback gas flow to 38°C as indicated on DCS TI-1633 against cooling water. The 103-J is protected against overpressure by PRV-103J, a pilot operated relief valve, set at 2 170 kg/cm²g and relieving to the NH3 flare header. A double block and bleed bypass line around the PRV has been added to aid in depressuring and purging. The second block valve is a globe for control. The synthesis gas compressor is driven by a high pressure steam turbine, 103-JT. The inlet steam is monitored locally for pressure by PG-7520 and PI-1755 on DCS with a low alarm, and temperature on DCS TI-1754 with both high and low alarms. The steam flows through a block valve and a double block warm-up bypass line. This flow is DCS monitored on FI-1123 which is pressure and temperature corrected using PI-1755 and TI-1754. A manual double block vent line for warm up has also been provided to a common vent silencer SP-154. The steam temperature is locally indicated on TW/TG-1701. The steam flow then flows through trip valve XV-6303 and XV-6304 which trip shut on a 103-J trip. 103-JT is an extraction / condensing type turbine. The HP steam enters the turbine at 123.1 kg/cm²(G) and 510°C, at a normal flow of 275,970 kg/h. Of this flow, 252,000 kg/h is extracted to the MP steam system, at 46.9 kg/cm²(G) to help satisfy MP steam users. The remaining 15313 kg/h goes through SV-6305 the condensing end of the turbine to develop the balance

Section 5 – Process Operating Principles

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of power required. The 103-JT speed will be controlled by control room mounted PIC-1006 compressor suction pressure as described earlier. The 103-JT governor will fail to minimum on loss of signal from PIC-1006. Speed indication will be on DCS SIC-1003A speed controller in the control room. There will also be hand switches HS-3211A, locally, and HS-3211B, in the control room, for manually shutting the machine down with a DCS alarm when activated on HA-3211B and XA-3211A. A common trouble alarm,. A common shutdown alarm, XA-3211B, will sound locally as well as a common trip alarm on UA-1204 in the control room. It should be noted that a trip on the process air, process gas or feed gas compressor will automatically trip the 103-JT. Medium pressure steam is extracted from 103-JT to the medium pressure steam header. All steam that passes through the high pressure end of the 103-JT is extracted and the condensing portion of the turbine governor valves open to take the MP steam required for the power needed before the steam is directed to the extraction line. The extraction steam passes through a non-return valve and a block valve which is equipped with a 0.75" double block and bleed warm-up and pressuring bypass line. PG-3282 & TW/TG-1702 can be seen locally to check the extraction pressure and temperature. TI-1753 in the DCS to see the temperature. PT-3283 transmitter provides input to 103-J governor. Pressure and temperature corrected extraction flow is also shown in the DCS on FI-1124 which uses PT-1754/PI-1754 and TI-1753/TT-1753 for compensation in function block FN-1124 . PI-1754 also indicates on DCS with a low alarm. The extraction line from 103-JT is protected from overpressure by PRV-103JT. This valve relieves to the atmosphere at 51.6 kg/cm²g. The condensing steam exhaust from 103-JT is designed for 80.2 mmHga, is directed to the surface condenser 103-JTC to recover condensate. PG-1847 is the local pressure indicator for 103-JT. The temperature is indicated in the DCS on TI-1756 which has a high alarm and locally on TW/TG-1703. There is a pressure transmitters PT-6340A/B/C located on exhaust line. The exhaust is protected from overpressure by atmospheric relief valve PRV-103JTC relieving to the atmosphere at 1.1 kg/cm²g. Sealing water from the 123-Js is used to provide a positive vacuum seal. Synthesis gas leaving the 103-J passes first through a non-return valve then through synthesis loop isolation valve HV-1101. This valve is a control type using HIC-1101 in the DCS and has a normally closed 2" bypass double block and bleed bypass attached to the valve for pressure equalization. HV-1101 comes with a handjack for manual operation and is a tight shutoff class valve that fails

Section 5 – Process Operating Principles 1

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last if instrument air is lost and closed on loss of control signal. Limit switches ZSO-1101 and ZSC-1101 indicate the valve position in the DCS on ZLC/ZLO-1101. Solenoid valve HY-1101 will trip on trip of 103-J closing the valve and it must be relatched in the DCS on handswitch HS-1101 before HIC-1101 can be operated. The gas stream following gases: • AI-1013A • AI-1013B • AI-1013C • AI-1013D • AI-1013E -

is continuously analyzed by the on-stream mass spectrometer AT-1000 for the Methane Hydrogen Nitrogen Argon Ammonia

A manual grab sample point is also provided at this point. AI-1013 H2 / N2 ratio indicator receivs its inputs from this point. The gas is preheated from 65.7°C to 176°C, in the Ammonia Converter Feed / Effluent Exchangers, 121-C, tube side before going to the ammonia converter. There is also a DCS manually controlled bypass line around the 121-C’s tubes for temperature control. HIC-1034 operates a fail last valve HV-1034 if instrument air is lost but fails closed if the control signal fails. There is a handjack for manual control of the valve locally.

5.1.13.

Synthesis Gas Conversion To Ammonia

The inlet and outlet design gas compositions for the 105-D are as follows:

H2 N2 CH4 Ar NH3

Inlet

Outlet

70.97% 23.74% 0.03% 3.47% 1.79%

56.59% 18.96% 0.03% 4.11% 20.31%

The ammonia synthesis reaction is equilibrium governed and proceeds with a significant exothermic temperature rise across the catalyst. The reaction step is as follows: 3H2 + N2

⇔ 2NH3 + heat Section 5 – Process Operating Principles

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The synthesis gas leaves the 121-C tube side at 176°C, as indicated in the DCS on TI-1372 and flows to the: • A1 : 105-D annulus to 122-C1 through HV-1044 • C : 105-D cold shot to Bed #1 through HV-1025 • A2 : 122-C2 Bed #3 temperature control through HV-1046 • 102-B Start -Up Heater through HCV-1047 SG1426-10”, a bypass line around 121-C is present, and has a HV-1034 installed. HIC 1034 helps control the temperature of the exit Syngas from the tube side of 121-C. HV-1034 has a handjack and fails last close on loss of instrument air or control signal. The flow to the converter annual space is measured using FI-1105 to the DCS and controlled manually from the DCS using HIC-1044 which operates HV-1044. FI-1105 is pressure and temperature compensated using DCS PI-1088, pressure inlet to 105-D, and TI-1373 through DCS function block FN-1105. HV-1044 has a portion of the disc cut out to allow a flow of 69,000 kg/h to pass through at a differential pressure of 0.5 kg/cm²g to protect the 121-C tube to shell for high differential pressure and cool the converter shell. If the HV-1044 valve is inadvertently closed too far, the 121-C is protected. HIC-1046 is a DCS manual control for the gas to the 122-C2 which controls the temperature of the inlet to bed #3A. The flow is DCS indicated on FI-1110. This flow is also temperature and pressure corrected with the same instruments as for FI-1105 through function block FN-1110. Both HV-1044 and HV-1046 fail open on loss of instrument air or control signal and have handjacks for manual operation. DCS PDI-1054 indicates the pressure drop across the entire 105-D and has a high alarm to warn of that condition. PDI-1052 also in the DCS and also with high alarm indicates the pressure drop across 122-C2 and the converter beds. Local pressure indicators are also provided as follows: • PG-1633 inlet to 105-D downstream of HV-1044 • PG-1631 inlet to 105-D downstream of HV-1046 • PG-1632 outlet of 105-D to the 123-Cs The cold shot flow to the first bed of the converter is controlled by HIC-1025 from the DCS. HV-1025 fails closed on instrument air or control signal loss and has a handjack. This flow is DCS indicated on FI-1100. This flow is also temperature and pressure corrected with the same instruments as for FI-1105 through function block FN-1100. Section 5 – Process Operating Principles

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Another path for the gas from the 121-C tube outlet is through the Start-Up Heater 102-B through a high performance butterfly valve HCV-1047. Downstream of HCV-1047 a bleed line with double block valves is provided for nitrogen purging. This heater is used for supplying the heat needed for reducing the catalyst and to bring the catalyst up to reaction temperatures after a shutdown. Flow to the Start-Up Heater is indicated in the DCS by FI-1257A and locally on FI-1257B uncorrected. This flow is also temperature and pressure corrected with the same instruments as for FI-1105. If the flow drops too low, there is a danger of overheating some of the heater coils and low-low flow alarm FALL-1257 will sound in the DCS and trips the fuel to the start-up heater. Transmitter failure is indicated on DCS at XA-1257. The heater outlet temperature can be seen in the DCS on TI-1047 with a high alarm and on TI-1396 which has a high-high alarm that will trip the fuel gas to the heater burners. There is also a DCS temperature indication on the heater stack, TI-1397 which also has a high temperature alarm. Two local points are used for heater draft indication, indicating on PG1634, ‘Point 1634A’ on the heater radiant section, and ‘Point 1634B’ on the stack. The heater inlet synthesis gas can be isolated using HCV-1047 when the heater is not in service. Fuel gas controls will be discussed later in this manual. The flow from 102-B is directed to the cold shot line. The converter consists of a pressure shell and a removable catalyst basket with four catalyst beds. Each of the catalyst beds 1, 2, 3A and 3B contain a conventional promoted iron magnetite catalyst. The converter basket is sized to fit within the shell leaving an annular space between the shell and the basket to allow for a flow of gas to keep the shell cool. The gas flow normally enters the converter shell through nozzle ‘A1’ flowing around the catalyst basket externally absorbing some of the radiant heat and cooling the shell at the same time. The temperature after passing through the annulus is shown on TG-1382. All converter related temperatures should be considered as DCS indications unless indicated otherwise and will not be listed as DCS in each case. The flow enters the ‘tube’ side of the internal heat exchanger, 122-C1, which exchanges heat from the bed #1 outlet gas to the gas entering bed #1. Gas flows to the top of bed #1 and flows radially through the bed. The gas exits the bed at the bottom and is directed through a channel to the ‘shell’ side of the 122-C1 exchanger. A cold shot, cool gas that has not come through the annular space of the converter shell but is injected directly, is introduced and mixes with the gas entering bed #1 prior to entering the 122-C1 ‘shell’. The cold shot is DCS controlled on HIC-1025 as described before.

Section 5 – Process Operating Principles

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The gas flows through bed #1. The bed #1 temperatures can be monitored on TI-1380 and 1381 on the bed inlet with TI-1383 and 1384 with high alarms on the bed outlet. These temperature points, as well as those listed in the remaining beds, are oriented inlet and outlet the bed. The bed #2 temperatures can be monitored on TI-1378 and TI-1379 on the inlet with TI-1385 and TI-1386 with high alarms on the outlet. The temperature of the gas exiting the tube side of 122-C2 is indicated on TI-1377 and the temperature exiting the tube side of 122-C1 is shown on TI-1391. The bed temperatures for the third bed, #3A, can be monitored on TI-1375 and TI-1376 inlet with TI-1387 and TI-1388 outlet with high alarms. The bed temperatures for the fourth bed, #3B, can be monitored on TI-1389 and TI-1390 outlet with high alarms. The bed 3A outlet temperatures are the bed #3B inlets. The pressure shell of the 105-D has 25 metal temperature elements, MTEs-1395A through 1395Z (there is no TI-1395-O), that show the temperature of various places on the converter shell, bottom head and nozzle skin temperatures. All of the MTEs are shown in the DCS. The heat of reaction from the ammonia synthesis is recovered by the high pressure steam system in the Ammonia Converter Effluent / Steam Generator, 123-C1, and Ammonia Converter BFW Preheater 123-C2. All temperature adjustment at the 123-Cs will be done by adjusting the BFW flow through and around 123-C2. TI-1630 shows the gas temperature exiting 123-C1 with TI-1371 indicated the gas exiting 123-C2. Both of these indicators are shown on the DCS. The gas exits the 105-D at 446°C, indicated on DCS TI-1374, and is cooled in 123-C1, Ammonia Converter Effluent Exchanger and is further cooled to 197°C in 123-C2 indicated by DCS TI-1371 inlet to 121-C shell sides. This is controlled by the HIC-1032 gas inlet valve to the tube side of 123-C2 The gas gives up heat to the boiler feedwater in the exchangers preheating the water and producing HP steam. The vaporization rate in 123-C1/C2 is about 20.7%. The gas leaving the converter contains approximately 20.31% ammonia. It is important that this 20.7 % vaporization rate not be greatly exceeded or exceeded for a long period of time and to help avoid this from occurring, a DCS vaporization rate calculation approximation block, UI-1002, has been added with a high alarm to alter the operators of excess steaming rates. UI-1002 gets inputs from the following points: • TI-1371 exit 123-C2 • PI-1045 exit 103-J high pressure case • PI-1036 141-D Steam Drum pressure • PDI-1052 105-D differential pressure Section 5 – Process Operating Principles

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• • • •

FIC-1020 TI-1374 FI-1105 FI-1100

• FI-1110 • FI-1257A

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BFW flow to the 123-Cs 105-D gas exit temperature 105-D inlet gas flow through UY-1002 105-D cold shot gas flow through UY-1002 rd 105-D 3 bed cold shot gas flow through UY-1002 102-B gas flow through UY-1002

The gas from the converter is further cooled to 89°C outlet the 121-C shell sides. DCS temperature indicator TI-1369 monitors the exit temperature. There is a grab sample station located on 121-C shell outlet for analysis if required. The gas stream here is continuously analyzed by the on-stream mass spectrometer AT-1000 for the following gases: • AI-1022A - Methane • AI-1022B - Hydrogen • AI-1022C - Nitrogen • AI-1022D - Argon • AI-1022E - Ammonia The ‘hot’ loop can be isolated and the flow controlled by DCS HIC-1033 valve located on the synthesis gas exit 121-C shell going to 124-C1/C2. HV-1033 will fail last on loss of instrument air, open on control signal loss and is provided with a handjack for manual operation. It also has a 2” bypass line with a double block and bleed arrangement. Solenoid HY-1033 will have to be manually reset with HS-1033 to allow control of HV-1033 following any trip of 103-J which will force HV-1033 closed. Limit switches ZSO-1033 and ZSC-1033 indicate the valve position in the DCS on ZLO/ZLC-1033. Downstream of HV-1033 a tie in NHL1147-1.5” line is used for catalyst reduction coming from 120-J. The temperature is lowered to 38°C exit the 124-C1/C2, Ammonia Converter Effluent Cooler, against cooling water before entering the 120-C Ammonia Unitized Chiller. There is also a DCS temperature indication located here for monitoring, TI-1633. On the cooling water to 124-C1/C2 TW/TG-1632 indicates the outlet water temperature locally. The synthesis gas is further cooled and condensed in the Ammonia Unitized Chiller, 120-C. This specially designed tube within a tube exchanger provides cooling of the converter effluent through interchange of heat with synthesis gas returning from the Ammonia Separator, 146-D, and boiling ammonia liquid at four different temperatures (14.6°C, -4.5°C, -18.5°C, and -33.3°C). By its unitized design, it essentially replaces five separate exchangers. Mechanically, the 120-C consists of multiple sets of concentric tubes (inner tubes inside of outer Section 5 – Process Operating Principles

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tubes) which run through the boiling ammonia compartments. Synthesis gas recycle vapors returning from the downstream Ammonia Separator, 146-D, pass through the center tubes counter-currently to the converter effluent as it flows through the annular space between tubes. Thus, the converter effluent is being cooled from the larger outside tube by boiling ammonia and from the inside tube by cold recycle vapor from the 146-D. The condensed gas exit temperature of the unitized chiller is -17.8°C, as shown on TI-1080 in the DCS with a high temperature alarm with the liquid ammonia product disengaged from the synthesis gas in 146-D immediately downstream of the exchanger. The inlet and outlet design gas compositions for the 146-D are as follows:

H2 N2 CH4 Ar NH3

Inlet

Outlet

56.59% 18.96% 0.03% 4.11% 20.31%

69.16% 23.16% 0.04% 5.01% 2.63%

The 146-D is a horizontal vessel and comes with a large demister pad for the outlet nozzle for removal of ammonia droplets in the gas stream, an inlet distributor, and a vortex breaker in the ammonia liquid outlet. The ammonia liquid level in 146-D is controlled by DCS LIC-1013 to letdown to the 147-D, Ammonia Letdown Drum. This has a low and high level alarm and local indication and control, LIC-1013. The valve LV-1013 is a tight shutoff class that fails closed if air or signal is lost to prevent a high-pressure gas blow through. It also comes with double upstream and single downstream isolation valves, has an inlet strainer and a bypass for manual operation and maintenance. The bypass line is equipped with a restriction orifice, RO-1000, to limit gas blow through should loss of level occur and both upstream and downstream globe valves for control with a gate type upstream isolation valve as well. LV-1013 and RO-1000 are very tightly designed and sized for only a 20% additional capacity above normal design for blow-through protection of 147-D. Level indication LI-1218A/B/C, which have high-high level alarm and low-low level alarm is shown in the DCS along with associated LSHH-1218 trip sounding LAHH-1218B in the control room and LAHH-1218B in the DCS is provided as a separate high-high level warning device. XA1218 A/B/C will sound in the DCS if LT-1218 fails. Maximum liquid level in 146-D will activate LSHH-1218 and the 103-J trip logic at that set point. The trip logic institutes a 2 out of 3 voting from LT-1218 A/B/C.

Section 5 – Process Operating Principles

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There is also a local pressure indicator on 146-D PG-1653. Most of the recycle vapor from the Ammonia Separator, containing nearly 2.63% dry mole of ammonia, is reheated in the Unitized Chiller to 33 °C as monitored on the DCS on TI-1366 and as described previously. To maintain the 3.47% inerts level in the ammonia converter feed gas, 1.54%, 3,524 kg/h, of the gas exiting 146-D is removed from the synthesis loop to purge it of mostly argon gases and a very little bit of methane which are contained in the fresh make-up gas from the 144-D and concentrated in the loop as ammonia is synthesized. This gas stream is routed through the 124D, HP Ammonia Absorber, where essentially all of the ammonia gas is scrubbed out, then is normally sent to the 130-C1 upstream piping for recycling. Part or all of this gas can be directed to the 101-B secondary or purge gas to fuel gas system. This flow of purge gas is controlled by FIC-1024. It has high and low flow alarms associated with it and the control valve FV-1024 will fail closed on instrument air or control signal loss. The valve has double upstream and single downstream isolation valves and a double block bypass for manual operation. FV-1024 will be tripped close on a trip of 103-J, process gas or process air through action of solenoid valve FY-1024. The solenoid will have to be DCS reset with handswitch HS-1814 to have valve control again. More details on the purge flow will be detailed later in the manual. The synthesis gas flow passes through the synthesis loop recycle manual isolation valve. This valve is equipped with a figure ‘8’ blind for positive isolation of the loop and compressor for maintenance. WARNING This valve must be oriented so that the gate can not fail and isolate the compressor antisurge flows to the high case. It must be LOCKED OPEN (LO) any time the compressor is not to be opened for maintenance. A start-up vent line, SG1042-6”, comes off of the line exiting 120-C just before the synthesis loop recycle isolation valve. The vent is manually DCS controlled on HIC-1019 and goes to the NH3 vent system. The valve HV-1019 is a tight shutoff class with a handjack and fails closed on loss of instrument air supply or control signal and comes with a handjack. It is isolated with double upstream isolation valves. Liquid ammonia from 146-D is letdown and flashed into the Ammonia Letdown Drum, 147-D. This vessel contains no demister pads but has a deflection plate on the inlet nozzle from 146-D. The liquid outlet contains a vortex breaker.

Section 5 – Process Operating Principles

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The flashed vapor, primarily dissolved synthesis gas, is mixed with the refrigeration system purge gas and is normally sent to the LP Ammonia Absorber, 123-D. The 147-D purge gas flow is expected to normally be 358 kg/h. and is measured in the DCS on FI-1021. A local grab sample point has also been provided. DCS pressure controller PIC-1108 controls and monitors the vessel pressure at 19.0 kg/cm²a. PV-1108 fails closed on instrument air loss and has isolation valves and a bypass for maintenance and manual operation. It also has a local indicator PG-1654. A second DCS pressure indicator PIC-1108 with a high-high and low alarm is also monitoring the 147-D pressure. 147-D DCS level controller LIC-1011 output serves as a set point signal to HS-1070. HS-1070, selector switch, will select the signal from LIC-1011 for control of LV-1012 A or LV1016, controlling the liquid ammonia to 120-CF1 or 120-CF4. Each LIC has an incorporated high level alarm and a low level alarm. The two steams from 147-D to 120-CF1 and CF4 flash drums use DCS controllers LV-1012 A and LV-1016. This will allow the operator to send some ammonia directly to the cold flash drum for export to storage during times when the refrigeration load doesn’t require as much ammonia. LV-1012A fails open on loss of instrument air to prevent over pressuring the drum with liquid and LV-1016 fails closed on loss of instrument air. Both have isolation valves and bypass valves for manual operation. Level glass, LG-1612, can be viewed locally to verify the vessel level. The outlet ammonia stream temperature is indicated in the DCS on TI-1403 The liquid ammonia product from 147-D is split into three streams leading to the ammonia refrigeration system: • 120-CF1 and 120-CF4 • Ammonia Refrigerant Receiver, 149-D. The stream is manually controlled to the 149-D as a reflux for the purge gas scrubbing section. This flow is adjusted from the DCS on HIC-1026 to maintain the desired 149-D overhead temperature of -17°C as shown in the DCS on TI-1404 which has high and low alarm. HV-1026 fails closed on instrument air loss and has a hand jack for manual operation. It can also be isolated for repairs. The stream is flow controlled to the 149-D storage section with LV-1012B. 147-D is protected from overpressure by relief valve PRV-147-D1 and PRV-147-D2 set to open at 22.5 kg/cm²g and 24.7 kg/cm2G. The relief valve discharges into a stand pipe arrangement to allow any liquid to separate prior to entering the NH3 vent system. Section 5 – Process Operating Principles

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The stand pipe also accumulates discharge from thermal relief valves PRV-NH1034A/B on the cold ammonia product line to storage, PRV-120-J, drain line from 149-D, common drain line from 120-CF1,2,3,4 and drain line from 147-D. Cold ammonia from ammonia storage can be inventoried into the refrigeration system through lines NHL1156-3” to 149-D which has a double block and bleed with non return valve and NHL1052-3” to 120-CF1 which has a double block and bleed isolation system. 5.1.14.

Ammonia Refrigeration System

A four stage ammonia refrigeration system provides refrigeration and purification for ammonia condensation in the synthesis loop and synthesis gas compressor inter stage gas chilling. The refrigeration system consists of a three case centrifugal compressor with a cooling water intercooler 128-C, Refrigerant Condenser, 127-C, Refrigerant Receiver, 149-D, and evaporators, 120-CF1 through 120-CF4. Provision is made for contact chilling and venting of any inert gases dissolved in the liquid ammonia from the synthesis loop. The first case of Refrigerant Compressor, 105-J, contains primary and secondary suctions, and a single discharge. Normally, vapors from First Stage Refrigerant Flash Drum, 120-CF1, at -33.3°C and 1.03 kg/cm²a, enter the first stage suction through an inlet strainer to protect the compressor from trash and debris. NHV1402-10” joins upstream the suction strainer carrying boil off Ammonia from OSBL through a blindable battery limit isolation valve followed by a nonreturn valves. The vapor flow from OSBL is DCS indicated at FI-7006. The flow from 120-CF1 is indicated in the control room on FIC-1012 which is temperature compensated by TT-1018 and pressure compensated by PT-1086 on the suction and PT-1060 and TT-1017 on the second stage suction. FIC-1012 is part of the compressor surge protection system and the flow is also shown in the DCS on FI-1012. PI-1086 is also shown in the DCS. Local temperature and pressure indication are shown by TW/TG-1673 and PG-1737, respectively. The vapors are compressed and discharged to the second stage compressor wheels which are integrated in a common case. Vapors from 120-CF2 provide additional suction to the second stage compressor at -18.5°C and 2.07 kg/cm²a as indicated by TW/TG-1073 locally and PI-1060 in the DCS. This gas also flows through a strainer prior to entering the machine. PG-1731 provides a local pressure indication at the second stage suction. The discharge of the second stage is shown locally by TW/TG-1642 and PG-1644. DCS indication is shown by TI-1033 and PI-1091. Discharge flow is indicated by FI-1011 on the DCS and controlled by FIC-1011 in the control room.

Section 5 – Process Operating Principles

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This value is pressure and temperature compensated by PT-1091 and TT-1033, respectively, on the discharge and PI-1060 and TT-1017 on the suction side. There is a DCS indication for TI-1017. FIC-1011 is part of the 105-J surge protection system. The second stage discharge provides the gas for the 105-J dry gas seals. Refrigerant gas at 61 0C , indicated by local TW/TG-1639, and is joined by the vapors from 120CF3. The vapor from 120-CF3 is expected to be -2.2°C and 3.69 kg/cm²a. The combined gas flow temperature to the 105-J third stage passes through a strainer and is indicated on the DCS by TI-1016 with a high alarm and locally by TW/TG-1641 with the pressure shown on the DCS by PI-1066 and locally by PG-1643. The discharge pressure of the third stage is shown locally by PG-1642 with local temperature indication by TW/TG-1637. These conditions are expected to be 79.5°C and 7.68 kg/cm²a. The third stage discharge flow is indicated on the DCS by FI-1010 and controlled in the control room on FIC-1010 with temperature and pressure compensation by TI-1110 shown as TI-1110 in the DCS and DCS shown PI-1097 on the discharge side with PI-1066 and TI-1016 on the suction side. FIC-1010 is part of the 105-J surge protection system. This discharge flow goes to the shell side of 128-C. 128-C is a conventional type shell and tube exchanger where the heat of compression is given up to the cooling water system. The cooling water exit temperature is shown locally by TW/TG-1634. The vapor flow leaves 128-C at 38°C, as shown locally by TW/TG-1635, and is joined with 17°C and 7.35 kg/cm²a vapors from 120-CF4. The combined streams enter the suction of the fourth stage also through an inlet strainer and temperature and pressure shown locally by TW/TG-1636 and PG-1701. DCS indication of the pressure is by PI-1049 with the temperature shown on TI-6195 which also has a high alarm This stream is compressed and discharged to the shell side of Refrigeration Condenser, 127-C, at 99°C and 16.7 kg/cm²a as shown locally by TW/TG-1640 and PG-1641 where it is joined by vapors from 125-D that are controlled by PIC-1034(with a high alarm) and temperature TIC1414(with high and low alarms). 105-J discharge flow is shown on the DCS by FI-1009 and is controlled on FIC-1009 in the control room. This signal has been compensated for temperature and pressure by TT-1408 and PT-1085 with corresponding temperature and pressure indications on the DCS on the discharge side with PI-1049 and TI-1015 on the suction side. TI-1408 has a high alarm incorporated. FIC-1009 is part of the 105-J surge protection system. The vapor flow through the compressor sections is monitored by the compressor anti-surge flow controllers FIC-1012, FIC-1011, FIC-1010 and FIC-1009 which are shown both in the control room and in the DCS. These controllers are all compensated for head and density using the following:

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Suction Temperature

Discharge Temperature

Suction Pressure

Discharge Pressure

TT-1018 TT-1017 TT-1016 TT-1015

TT-1017 TT-1033 TT-1110 TT-1408

PT-1086 PT-1060 PT-1066 PT-1049

PT-1060 PT-1091 PT-1097 PT-1085

All of the indications above are mirrored in the DCS. The flow is shown compensated. The control valves for the controllers are located from the 105-J discharge line to an under liquid level sparger in each flash drum. Each of the anti-surge valves are designed to fail open on loss of instrument air or control signal, and comes with a handjack for manual operation. FZL1012, 1011, 1010 and 1009 indicate valve position on DCS. The anti-surge system serves to maintain the compressor in a stable operating condition by taking gas from the compressor discharge to the respective flash drums

2

105-J and the downstream equipment are protected from overpressure by relief valve PRV-105J set to open at 18 kg/cm²g to the NH3 flare header. Additional over pressure protection is provided by PRVs on each of the refrigerant flash drums. These are PRV-120CF1, PRV-120CF2, PRV-120CF3 and PRV-120CF4, all set to relieve to the NH3 flare header at 15.8 kg/cm²g. A non-return valve on the 105-J final discharge prevents a vapor reverse flow to the compressor. 105-J dry gas seal gas is taken just upstream of the non-return valve to the seal gas skid and booster unit. The 127-C condenser is also a conventional shell and tube exchanger where the final heat of compression is given up to the cooling water system. The condensed ammonia in the shell flows to the warm section of the Refrigerant Receiver, 149-D, at a temperature of 38°C as DCS indicated on TW/TG-1401. Non-condensables entering 127-C are continuously vented into the storage section of 149-D through line V1031-3”. The pressure can be monitored locally using PG-1647. 127-C has cooling water on the tube side with local temperature indicators TW/TG-1645 on the exit. 149-D has a raised liquid outlet nozzle with vortex breaker. This will allow any oils that may have entered with the ammonia stream to settle to the bottom of the vessel and not be carried out with the ammonia liquid. The liquid leaves the 149-D and goes to 113-Js, 130-C1, 120-CF-4 and 120-J ammonia Section 5 – Process Operating Principles

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injection pump. DCS TIC-1428 indicates the temperature out of 149-D. Also incorporated within 149-D is an ammonia gas stripping section in a packed column on the receiver. This packed section has carbon steel rings which are supported on a gas injection plate. The top of the rings are held in place by a hold down grating. There is removable section on top of the stripping column for ring replacement An upper liquid distributor distributes the liquid from the 147-D as it enters from the sparger and a demister pad for the inerts exiting the section. This section washes ammonia from the purge gas going to 123-D. 113-J / JA motor driven pumps take suction from the 149-D to provide the pressure required for Ammonia to 125-D. Each pump has suction and discharge isolation valves with suction strainers to prevent trash and debris from entering the pump. The pumps each have a discharge manual block valve. DCS running indication is also provided on XL-2001A for 113-J and XL-2001B for 113-JA. Each pump also has a local suction and discharge pressure indicator, PG-2001A and PG2001-B for 113-J and PG-2001C and PG-2001D for 113-JA. DCS indication XL-2001 A/B indicate running status of pumps. The minimum flow lines have automatic recirculation valves, a nonreturn valve to prevent backflow into the standby pump and they can be isolated for maintenance. The minimum flow lines from each pump combine to a common line. Each pump discharge also has a non-return valve with a gate valve equipped warmup line followed by a common sampling point. Each pump also has drain lines and strainer drain lines that go to the ammonia vent header for maintenance and start-up purposes. They all tie into a common line with isolation valves and non return valve to the header. Each pump has vent lines that return to 149-D. The discharge flow from the 113-Js to 125-D is monitored in the DCS on FI-1060 which has a low alarm. The discharge line from 113-J/JA takes the warm ammonia product to the urea plant. The flow is measured by a coriolis flow meter FE-1071 indicated at FI-1071. FE-1071 has an upstream strainer and a 8” bypass with a double block and bleed arrangement. The 149-D level controller LIC-1015C provides the low level override signal controling LV-1015B on this warm product discharge line. LV-1015B has a double block and bleed arrangement around it and also has a globe valve equipped bypass. TI-1607 indicates the temperature 38°C at DCS. The warm ammonia product line has an isolation valve. DCS LIC-1015B controls the level in the 149-D and comes with both high and low level alarm to indicate those conditions. LIC-1015 helps maintain the 149-D level by sending ammonia to 120-CF4 through LV-1021. LV-1021 fails closed if instrument air or control signal is lost. It comes

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with isolation valves and a bypass line. Both of these valves will trip shut on a 105-J trip and must be reset with HS-1015. LIC-1015B provides the 149-D cold ammonia level signal to HN-1024F and LIC-1021A provides the 120-CF4 level signal to the same. HN-1024F via LN-1021 acts on LV-1021 controling the flow to 120-CF4 from 149-D. Ammonia is also sent to 130-C1 through line NH2201-3”. There is a take off to the 120-J ammonia injection pump used to send ammonia to 124-C1/C2 during 105-D reduction if needed and also to 101-B for use during start up if needed. The 120-J has local suction and discharge indications, PG-1664 on the suction and PG-1681 on the discharge. DCS indication XL-1023 indicates running status of pump. The flow passes through a non return valve and isolation valve before it splits going to 124-C1/C2 and 101-B The 124-C1/C2 line has a single isolation valve and the 101-B has double isolation valves before it passes through FI-1260, it then passes through a non return valve and isolation valve that has a figure “8” blind on the upstream side for positive isolation. The 120-J is overpressure protected with PRV-120-J set at 170 kg/cm²g. The ammonia is also used through line NH1025-1.5” to the 125-D Ammonia Distillation Column as reflux from the 113-Js. Level glass, LG-1615, can be seen locally to confirm the vessel 149-D level. Purge vapor, saturated with ammonia from 149-D, flows through the contact chiller section of the receiver where it is intimately contacted with down flowing ammonia, controlled by HIC-1026, from 147-D through an inlet spray nozzle, and is chilled to -14.0°C, as indicated on TI-1404 in the DCS with high and low alarm. The expected purge flow rate is 60 kg / hr. The non-condensables are released under control of pressure controller PIC-1109 with associated high pressure alarm and monitored by a local pressure indicator PI-1648, where they ultimately flow to the 101-B secondary fuel gas system after passing through the ammonia recovery system 123-D. A local grab sample point is provided for sampling the stream as required. DCS indication FI-1057 with a high alarm indicates the vapor flow to 123-D. PIC-1109 controller setpoint is set through an internal DCS function block TN-1428. TN-1428 takes the input of the ammonia temperature exiting 127-C as indicated on TW/TT-1401 and from PT-1109, converts it to an ammonia vapor pressure equivalent then adds 50 kPa for a setpoint. This allows the setpoint to be lower when the cooling water temperatures are cooler and saves energy on the 105-J. PIC-1109 sends this signal to PV-1109 which controls the pressure to 123-D.

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All of the flash drums of the unitized exchanger, 120-C, serve as the 105-J compressor suction drums and as the liquid head drum for each level of refrigeration. The four drums are horizontal vessels joined together in one shell with internal heads and also contains seals around the full length heat exchanger in the lower area of the 120-C unitized exchanger. Each chamber contains a demister pad covering the vapor outlet nozzle and a vortex breaker at the liquid outlet nozzle. A liquid ammonia level is maintained in each chamber supplying the refrigerant for its evaporators. Each drum can be manually vented to the NH3 vent system and can also be manually drained to a common line for liquid disposal by 124-Js. Liquid in each drum provides refrigeration to the associated chiller section of the unitized exchanger. The third stage also receives vapors from 130-C through 120-CF3. Listed below is the instrumentation on the flash drums: 120-CF4: LT-1214 A/B/C – LAHH-1214B high-high level alarm in local panel; remote trip to LY1021 and 105-J trip after a 5 second time delay. LG-1621A indicates local level verification. LIC-1021B with high level alarm and low alarm - liquid let down to 120CF3 in case of Cold Ammonia production. LIC -1021B feeds forward the 120CF4 level signal and LIC-1022A feeds backward the 120-CF3 level signal to a HN1024A which via LN-1022 opens or closes the LV-1022 accordingly. TI-1398 with high and low alarms – liquid let down to 120-CF3 temperature. PG-1699 – Local indication on drum vapor outlet. LI-1214A/B/C indicates on DCS as well. 120-CF3: LT-1215 A/B/C – LAHH-1215B high-high level alarm in local panel with a 105-J trip after a 5 second time delay. LG-1622A – Local level verification. LIC-1022B with high level alarm and low alarm - liquid let down to 120-CF2 for Cold Ammonia production. LIC -1022B feeds forward the 120-CF3 level signal and LIC1023A feeds backward the 120-CF2 level signal to a HN-1024B which via LN1023 opens or closes the LV-1023 accordingly. TI-1399 with high and low alarms – liquid let down to 120-CF2 temperature. PG-1652 – Local indication on drum vapor outlet. 120-CF2: LT-1216 A/B/C – LAHH-1216B high-high level alarm in local panel with a 105-J trip after a 5 second time delay. LG-1623A – Local level verification. LIC-1023B with high level alarm and low alarm - liquid let down to 120-CF1 for Cold Ammonia production. LIC -1023B feeds forward the 120-CF2 level signal and LIC1024A feeds backward the 120-CF1 level signal to a HN-1024C which via LN1024 opens or closes the LV-1024 accordingly. TI-1400 with high and low alarms – liquid let down to 120-CF1 temperature. PG-1637 – Local indication on drum vapor outlet. 120-CF1: LT-1217 A/B/C – LAHH-1217B high-high level alarm in local panel with a 105-J trip after a 5 second time delay. LG-1624A – Local level verification. LIC-1024B with Section 5 – Process Operating Principles

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high level alarm and low alarm - discharge of 124-J / JA to storage. LIC -1024B feeds forward the 120-CF1 level signal and LIC-1015A feeds backward the 147-D level signal to a HN-1024D which via LN-1015A opens or closes the LV-1015A accordingly. TI-1419 with a high alarm – liquid to 124-J / JA suction. PIC1009/SIC-1005 to 105-JT governor to control the speed and therefore pressure in 120-CF1. There is also a local PG-1706 indicating CF-1 pressure. LAHH-1215 through 1217 will trip the 105-J compressor train after a 5 second time delay if high-high level occurs in the associated flash drum, to prevent liquid carryover into the machine. There is a 2 out of 3 voting system for tripping the 105-J. LAHH-1214 will trip 105-J after a 5 second time delay. Any additional liquid that is required in 120-CF4 is letdown from the 147-D as described before. Also, 120-CF4 serves as the holding drum for liquid ammonia during the ammonia converter catalyst reduction. This ammonia is used through manually controlled globe valves going to all of the other three flash drum anti-surge gas inlet lines to provide cooling of the recycle gas flow to avoid overheating of the compressor stages. Normally, this is done with the gas flowing through bottom spargers that are below the normal liquid level but during converter reduction, no liquid levels are maintained so that freezing of water formed during the reduction process in the tubes is avoided. This line can be isolated when not in use. Liquid from each flash drum is flashed into the next lower flash drum. The level in each drum is controlled to maintain the proper level in that drum. Isolation valves and a bypass are provided on each level control valve. The valves will fail closed when there is an instrument air loss. Liquid in the first stage drum provides refrigeration directly to the first stage chiller section of the unitized exchanger and acts as the suction for 124-J / JA. The first stage drum uses the control room mounted DCS and is monitored on PIC-1009 controller with high and low pressure alarms and local PG-1706 for pressure indication. PIC-1009 (through SIC-1005) serves to control the speed of 105-J by opening or closing the turbine governor valve. Each flash drum is protected from overpressure by PRV-120CF1, 2, 3 and 4, with each set to relieve at 15.8 kg/cm²g to the NH3 flare system. 120-CF1,2, 3 and 4 flash drums can be manually vented to the ammonia header through a globe-type valve for control. All drums can be drained to 124-J/JA for shutdown maintenance to OSBL or through line OW2100-2” to NH3 flare header. The line has a common isolation valve and isolation valves from each drum’s liquid outlet line. The 105-J compressor is being driven by the 105-JT extraction type turbine. The HP steam enters the turbine at 123.1 kg/cm²(G) and 510°C, and extracted to the MP steam system at 46.9 kg/cm²(G) and 384.8°C. The turbine can be isolated from the steam systems. Section 5 – Process Operating Principles

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The high pressure steam flow to the turbine is DCS indicated on FI-1125 which is pressure and temperature corrected using PI-3120 and TI-1125 through function block FN-1125. Local pressure indication is on PG-3181. DCS temperature indication provided by TI-1125 and has a control room temperature also shown on TI-1125 with high and low alarms and with the local temperature shown on TW/TG-1706. An inlet block valve with a 1” bypass line provided with a double block and bleed is installed at the turbine for positive isolation. There is also a double blocked warm up vent line to the vent silencer SP-154. After passing through the block valve steam passes through XV-6503, XV-6504 and SV-6505 and all are activated on a 105-J trip. 105-JT is designed to exhaust medium pressure steam to the header. The extraction line temperature is DCS indicated on TI-3121 and pressure on PG-1862 which is locally indicated. The exhaust steam line has ablock valve with a 0.75” double block and bleed warm-up line around the isolation valve. The extraction temperature is locally indicated on TW/TG-1707. Steam leakage to LP steam header has DCS FI-1126 and TI-1815 for indicating flow and temperature to LP header. The extraction line is protected from over pressuring by one relief valves PRV-105JT which relieves to the atmosphere at 51.6 kg/cm²g. The 105-JT speed is controlled by PIC-1009, 120-CF1 pressure. The 105-JT governor will fail to minimum on loss of signal from PIC-1009. Speed control will be in the DCS on SIC-1005A which also sends a signal to control room mounted SIC-1005. Hand switch HS-3111A, on local panel, will manually shut the unit down. Common trouble alarm UA-1203 will alarm locally and in the control room on activation of any of the 105-JT alarms. A common shutdown alarm, XA-3103, will sound on the control room panel. There is hand switch HS-3111B in the control room for manually shutting the machine down. Control room alarm HA-3111B and DCS alarm XA-3111B will alarm if these switches are operated. A machine common trip signal is sent on XS-3103. Ammonia from 120-CF1 goes to the 124-Js Ammonia Product Pumps for transferring to storage. The 124-J and JA are motor driven pumps which are fully isolatable and have suction strainers to prevent trash entering the pump. Each pump has a suction pressure indicator, PG-1689 for 124JA and PG-1688 for 124-J, and discharge pressure indicator, PG-1656 for 124-JA and PG1655 for 124-J. SP-ARV-124 J/JA maintains the minimum flow requirement for 124-Js. The line is provided with a non return valve and a gate type isolation valve. There are also drains from the casings to the ammonia vent flare with a non-return valve in the common line to prevent the vent gasses from back flowing to the pumps. Both 124-Js have DCS running indicators with XL-1025 to 124-JA and XL-1024 to 124-J.

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The ammonia to storage is controlled by LV-1015A. The ammonia flow to the storage tanks is measured using FI-1061. The flow indicator has high and low flow alarms and a totalizer, FQI-1061. This flow meter is a Coriolis type for accuracy and has inlet and outlet isolation valves and an inlet strainer for protection from debris in the line. The meter can be bypassed for servicing, if required, through a double-blocked line. The ammonia to storage temperature can be seen in the DCS on TI-1422. Ammonia is directed to storage through line NH1034-6” which has a battery limit isolation valve and drains for line clearing during outages. The line is protected from thermal overpressure by PRV-NH1034A and PRV-NH1034B relieving to the NH3 vent flare through a stand pipe arrangement to allow any liquid to drop out. PRV-NH1034A is downstream of LV-1015A and PRV-NH1034B is installed upstream of LV-1015A. Both valves are set to relieve at 30 kg/cm²g. Condensate from 103-JTC is injected into the line to storage to help prevent stress corrosion, caused by the cold temperature ammonia, in the piping and storage tanks. Condensate is pumped by 123-J / JA through LV-1018. DCS LIC-1018 controls the flow by acting on LV-1018 which is measured by FE-1038, indicated at FI-1038 with a low alarm. LV-1018 will fail in the closed position if instrument air is lost and has a hand jack for manual operating. The valve can be isolated for maintenance, if required and also has a globe valve equipped bypass line. Ammonia from storage to the system can be imported through two lines. NHL1156-3” directs ammonia to 149-D after passing through a double block and bleed with a non-return valve in between.

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46. Ammonia Purge Gas Recovery System 5.1.15.

Purge Gas Ammonia Recovery

Low pressure purge gas from 149-D and 147-D join together to enter 123-D. Purge gas from 149-D flows through line NHV1026-2” and a non-return valve Flow from 147-D is through line NHV1040-2” and a non-return valve. Line NHV1023-2” acts as a bypass of 123-D with a globe valve for control for start up and maintenance work on the vessel. The vessel differential pressure is indicated in the DCS by PDI-1056 which is equipped with a high differential pressure alarm. 123-D inlet pressure can be monitored on DCS by PI-1056B. Scrubbed gas exit 123-D with an ammonia concentration of < 200 ppm can be directed to the 2 101-B fuel gas system or the NH3 flare header. PIC-1038, in the DCS, controls the pressure

on 123-D with a split range action on PV-1038A gas to the 101-B fuel gas system through a non-return valve, or PV-1038B, gas to vent. The flow to the 101-B fuel gas system is shown on FI-1036 in the DCS. Local PG-1070 shows the overhead pressure. PV-1038A fails closed on loss of instrument air, PV-1038B fails closed on loss of instrument air and is a tight shutoff valve. 123-D and gas inlet piping are protected from over pressure by PRV-123D set to relieve to the NH3 vent system at 17.5 kg/cm²g. A grab sample point has been provided on the overhead line. 123-D is provided with LG-1628 for local verification of the level and LIC-1028, a DCS available control with high and low level alarms. LIC-1028 controls the stroke of 160-J and 160-JA LP Scrubber Bottom Pumps. Water, used to scrub the ammonia from the gas, is supplied from 125-D after being cooled to 46°C in 161-C. Water flow is indicated on and controlled from the DCS by FIC-1039 at 963 kg/h which has a high and low flow alarm. FV-1039 will fail closed on loss of instrument air and is provided with isolation valves and a bypass for manual operation. The water enters the tower through a non-return valve and distribution nozzle above the top bed of packing rings and flows counter current to the rising gas. 123-D is provided with a demister pad at the gas outlet nozzle to remove any droplets of liquid that might be in the gas stream. There are four beds of stainless steel packing rings. Each packing bed is supported on a gas injection plate and maintained in place by a bed limiter grate on the top of the bed. Each packing bed has an unloading connection for the removal of the packing rings. There are flanges in the vessel above each bed to allow the removal of a portion of the vessel to facilitate the replacement of the rings. A liquid distributor is provided between

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each bed to ensure an even flow through the following packing bed. A vortex breaker is installed on the liquid outlet nozzle. The tower can be isolated in and out including a removable spool in the water inlet line and there is a depressuring line with a block valve and a globe valve to the ammonia vent header. The liquid from 123-D provides suction for motor-operated, positive displacement pumps 160-J and 160-JA. A grab sample point is provided on the suction line for checking the stripping action of the tower. The ammonia concentration is expected to be 7 to 8 weight %.The suction temperature is indicated on the DCS by TI-1417. Each pump can be isolated for maintenance if required and is provided with a suction strainer and local suction and discharge pressure indicators. For 160-J PG-1733 is on the suction and PG-1734 on the discharge. 160-JA has PG-1735 on the suction and PG-1736 on the discharge. Run status indicators are provided in the DCS by XL-1034 for 160-J and XL1035 for 160-JA. PRV-160J and PRV-160JA provide over pressure protection of the discharge piping by relieving to grade at 24,5 kg/cm²g. The discharge from the pumps flows to mix with the water effluent from 124-D to return to 125-D through 161-C through a non-return valve on each pump discharge. High pressure purge gas from 146-D through FIC-1024 at -22.0 °C enters the bottom section of 124-D, Purge Gas Scrubber with temperature shown in the DCS on TI-1410. A grab sample point on the gas line inlet the 124-D has been provided. The gas flows in the bottom and up through the tower. The downstream equipment is overpressure protected using PRV-124D relieving to the ammonia vent at 94.8 kg/cm²g. Scrubbing water flow is controlled to the top of the 124-D tower at 1221 kg/h by FIC-1064 which has a low flow alarm. FIC-1064 controls the flow by controlling the stroke settings on the 161-J / JA HP Scrubber Feed pumps. Stripped water coming from the 125-D bottoms outlet at 211°C, as shown on the DCS TI-1666, flows through 161-C tubes exchanging heat with the water flowing into 125-D on the shell. The water exits the tubes at about 46°C as indicated on DCS point TI-1661 to 161-Js. A grab sample point is provided on the 161-Js suction line. 161-J and JA are motor driven, positive displacement pumps equipped with suction strainers to keep trash out of the pump. Each has a suction pressure gauge for local indication, PG-1684 is on 161-J and PG-1686 is on 161-JA. Each also has a discharge pressure gauge for local indication, PG-1685 is on 161-J and PG-1687 is on 161-JA. The pumps each have suction and discharge isolation valves and discharge non-return valves. DCS running indications are provided with XL-1026 for 161-J and XL-1027 for 161-JA. The pumps are protected from developing high discharge pressures by relief valves, PRV-161J and PRV-161JA both set at a relieving pressure of 96.3 kg/cm²g. The pumps will fail to full stroke on loss of signal from

Section 5 – Process Operating Principles

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FIC-1064 through HIC-1064B and HIC-1064A Water goes on to 124-D through a removable spool piece and a non-return valve. The flow is introduced by distribution pipe and distribution tray of 124-D. This vessel contains two packed beds of stainless steel rings. Each bed is supported by a gas injection plate and the rings are held in place by a hold down grate. There is a distribution tray over each bed and the liquid outlet nozzle has a vortex breaker. The tower top also has a demister pad. The tower is instrumented for monitoring differential pressure using DCS PDI-1055 and its high alarm warns of high differential pressure. Local pressure gauge PG-1679 indicates the tower inlet pressure. A grab sample point is installed on the tower overhead to sample the purge gas stream to the distribution system which is expected to contain virtually no ammonia. 124-D pressure is controlled at 86.9 kg/cm²a with PIC-1033 sending a signal to a set of split ranged valves. PIC-1033 has an associated high pressure alarm and gets its signal from PT1033. PV-1033A opens from 0 to 50% and directs the overhead gas to the 130-C1/C2 process gas system and if the pressure continues to build, PV-1033B opens from 50 to 100% to 2 vent the excess to the NH3 flare system. The gas flow back to process is measured in the DCS on FI-1065. PV-1033A / B both fail closed on instrument air loss. PV-1033A has isolation valves and a bypass while PV-1033B is equipped with a handjack but can be isolated upstream for repairs. PV-1033B is a tight shut off class valve. PG-1677 can be seen locally for pressure exit 124-D. Additionally, there is a line from the 124-D overhead to the 101-B fuel gas system. This flow is controlled by DCS FIC-1029. FV-1029 fails closed on loss of control air, is furnished with a bypass line and isolation valves and is a tight shut off class valve. FIC-1029 is associated with the 103-J trip circuit. The vapor temperature exiting the 124-D is about 18°C. DCS Temperature Indicator TI-1412 can be used to monitor the overhead temperature. The column can be isolated and bypassed using line SG1029-3” for maintenance, if necessary. A depressuring line SG1047-1½” with a double block and bleed arrangement can be use to 2 depressure the tower to the NH3 flare system. The downstream isolation valve is a globe type for control. The inlet isolation valve has a ¾” double block and bleed pressuring bypass. The 124-D liquid level is controlled by LIC-1026. A local level glass, LG-1626, is available for visual level confirmation. LIC-1026 has high and low level alarms. LV-1026 fails closed on loss of Section 5 – Process Operating Principles

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instrument air and is furnished with isolation valves and a bypass. There is also an upstream strainer to protect the valve from plugging. The solution leaving the 124-D scrubber is about 19 to 20 wt.% ammonia at about 7°C and is monitored for temperature, in the DCS, on TI-1413. A grab sample point has been placed on the liquid outlet line.

5.1.16.

Ammonia Distillation Column

Ammonia solution from 123-D and 124-D join in line NHA1056-2” and flow to the 161-C, Ammonia Distillation Column Feed/Effluent Exchanger, shell at about 30°C. The combined solution is preheated to about 161°C, as shown on the DCS TI-1662, before entering the 125-D, Ammonia Distillation Column, between the top and second beds of the tower. 125-D contains three packed beds of stainless steel rings each resting on a gas injection plate support. Each bed has a top hold down grate for the rings and a liquid distribution tray above it. A demister pad covers the outlet gas nozzle and a vortex breaker is at the liquid outlet nozzle. Each bed is equipped with a unloading connection for removal of the packing. 125-D is provided with full body flanges to allow removal portions of the vessel to allow access for placement of packing and tower internals. The vapor outlet temperature, normally 65°C, is monitored and controlled by DCS TIC-1414. It has a high and low temperature alarm. TIC-1414 controller increases and decreases the flow of ammonia from 113-Js through TV-1414 to the tower through a non-return valve that allows ammonia to enter and act as reflux while controlling the vapor outlet temperature. TV-1414 will fail closed on instrument loss and is provided with a bypass and isolation valve to allow manual operation and for maintenance. The ammonia reflux flow of 907 kg/h is monitored on the DCS by FI-1060 as stated before. There is also a DCS TIC-1667 installed in the tower between beds two and three, which has high and low alarms. Tower pressure is controlled by PIC-1034 at 19.9 kg/cm²a with a high pressure alarm to warn of pressure deviations. The control valve PV-1034 opens to allow the ammonia vapor, at 99.5 wt. %, to go to the 127-C, Refrigeration Condenser, to be condensed and returned to the refrigeration system. The control valve will fail open if instrument air fails and can be isolated for maintenance. It has a bypass to allow manual operation. PG-1682 is a local pressure indicator on the outlet vapor line. The line to 127-C is equipped with a non-return valve to prevent backpressure into the 125-D tower from 127-C. Differential pressure on the tower is monitored on the DCS by PDI-1035, which has a high alarm. Differential pressure is expected to be 3.0 kPa. Local PG-1678 indicates the tower bottom vapor pressure. A grab sample point is located on the overhead line. The level in the tower is indicated in the DCS on LIC-1027. LIC-1027 has high and low level alarms on the DCS. Local level glass, LG-1627 provides visual level indications. Temperature Section 5 – Process Operating Principles

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of the outlet liquid is indicated by TI-1666 in the DCS and is expected to be 211°C. The Ammonia Distillation Column Reboiler, 160-C, is heated by MS steam to the shell side controlled by FIC-1027. It receives liquid on the tube side from the bottom trap out tray of 125-D and the reboiling supplies the stripping steam for the tower. The control valve FV-1027 will fail closed should instrument air fail, and there are isolation valves and a bypass line for manual operation and maintenance. FIC-1027 has high and low flow alarms. There is also a local pressure gauge on the steam line to the 160-C, PG-1683. The condensate formed in 160-C is sent to the 101-U deaerator for recovery via LIC-1049/LV-1049 with a high and low alarm, LG-1060 is provided for local indicating. The valve has a single block by-pass. Water make-up for initial fill of the system is manually supplied from the 104-J/JA BFW pumps through a needle valve, a block and bleed valve arrangement. Normally a portion of the condensate from the 160-C is fed into the 125-D as system make-up water through LV-1027 a similar valve arrangement as that indicated for the BFW. LV-1027 is controlles by LIC-1027 according to the level in the bottom section of 125-D. A non-return valve in this make-up line prevents backflow of distilled condensate from going to 101-U. The system will require 11 kg/h of make up flow to maintain the water balance. 125-D is protected from overpressure by PRV-125D set to relieve at 22.5 kg/cm²g to the NH3 vent system. There is also a NHV5003-2” manual depressuring line with double block and bleed and a globe valve for control also to the NH3 vent system located downstream of but within the isolation valve of PV-1034 so that PV-1034 can be used to control to the vent, if desired.

47. Utility Flow 5.1.17.

Boiler Feedwater System

5.1.17.1. Demineralized Water Demineralized water is supplied to the ammonia unit from the offsites demineralized water system through a figure ‘8’ blindable isolation valve. The total demineralized water flow to the 101-U is 372,043 kg/h. Demineralized water is supplied on demand of the 101-U Deaerator level controller LIC-1030 controlling LV-1030 remote setpoint. LIC-1030 has high and low level alarms. LSL-1030 will auto start the OSBL demineralized water pump. The temperature and pressure of the demineralized water supply is monitored in the DCS by TI-1559 and PI-7607 and locally by TE/TW-1559 and PG-7501 respectively. LV-1030 fails open if instrument air is lost and is furnished with isolation

Section 5 – Process Operating Principles

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valves and a bypass with a globe valve. The flow then passes through 109-C, exchanging heat with lean OASE solution. TW/TG-8200 shows the temperature of the demineralized water to 1062 C locally. TI-1352(with high and low alarms) will adjust the bypass flow to control the process gas temperature exit 106-C as described earlier in this section. The flow of demineralized water goes to the shell side of 106-C where it exchanges heat with the process gas exit 105-C. 106-C heats the demineralized water to 120°C and controls at that temperature with DCS controller, TIC-1558. TIC-1558 opens a valve bypassing the demineralized water around the 106-C to control the demineralizer water temperature. The water goes to the 101-U from 106-C. TV-1558 fails closed on loss of instrument air supply and has a handjack for manual operations. Locally, TW/TG-1359 shows the demineralized water temperature immediately out of the 106-C shell. The water flows at a temperature of 120°C just prior to entering the top section of the 101-U Deaerator. There is a conductivity analyzer, AI-1015, with a high conductivity alarm in the DCS to indicate water quality as it enters the 101-U. 5.1.17.2. Deaeration The function of the 101-U, Deaerator is to remove small amounts of dissolved gases from the feedwater before it is used for steam generation. These absorbed gases are mainly oxygen and carbon dioxide both of which are corrosive to steel. The 101-U contains a preheating section, scrubbing section, and a water storage compartment. The demineralized water stream enters the top, preheating, section of 101-U. The water flow is heated by contact with a countercurrent steam flow. The water is then intimately contacted by the steam as it falls through the top section. Most of the oxygen and carbon dioxide are stripped. The hot and partially deaerated water passes from the preheating section into the scrubbing section. LP steam flows into the storage section. The hot steam raises the water temperature to saturation and produces boiling and vigorous scrubbing by steam stripping the liquid. Almost all of the remaining gases are desorbed from the water. The heated water flows from the scrubbing section into the storage section. Steam from the storage section flows upward through vent pipes into the preheating section for contact with the water droplets. Deaerator pressure is maintained at 1.73 kg/cm²(G) by pressure controller PIC-1031. The pressure controller adjusts the amount of LP steam supplied to the vessel and has high and low pressure alarms. PV-1031 fails open on loss of instrument air, is provided with a bypass line with globe valve for manual operation and extra start-up flow demands. The 101-U pressure can be locally observed on PG-1743 in the storage section as well as PG-1728A/B in the deaeration section. An estimated 500 kg/h of stripping steam and entrained inerts are vented to the Section 5 – Process Operating Principles

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atmosphere through an exhaust head. The storage section temperature of the 101-U, which is 130°C and directly related to the pressure in 101-U, can be observed locally on TW/TG-1773 in the storage section and TW/TG1772A in the deaeration section. 101-U is instrumented with level glass LG-1630. LIC-1030 in the DCS indicates and alarms on high or low storage section level. LALL-1123 in DCS will alarm on low-low level. LIC-1031 will open valve LV-1031 to dump water to the sewer through a flash pipe to avoid flooding the vessel if the storage section level becomes higher than the setpoint and has a high alarm. LV-1031 fails closed on loss of instrument air and has a handjack for manual operation. It is also equipped with an isolation valve. The overflow line internal to the 101-U is elevated so that the vessel cannot be accidentally drained should the overflow valve fail. There is also a manual drain line from the storage section to the sewer. LI-1123A/B/C feed a signal to LSLL-1123 in the PLC which will trip 104-Js if these pumps are running and the low-low level exists on any two out of the three transmitters. XA-1123 A/B/C act as transmitter failure indicators for the trip system. The vessel is protected from overpressure by PRV-101U set at 4 kg/cm²g and PRV-101UA set at 3.8 kg/cm²g and vents to atmosphere at a safe location. An oxygen scavenger from 106-L is injected into the storage compartment through a non-return valve and an isolation valve to chemically remove any oxygen remaining in the water. Ammonia solution from 107-L is injected into the outlet line from of the deaerator to 104J/JA also through a non-return valve and an isolation valve to increase the pH of the water and inhibit the corrosion tendencies of the condensate from the surface condensers and other condensing equipment. The pH will be monitored on DCS AI-1007 which incorporates both a high and low pH alarm to warn of these conditions. A grab sample point is also provided on the 101-U water outlet line to 104-J / JA suction. Demin water 101-U inlet have normal conductivity at 0.5 micro S/cm. Oxygen contain at the Deaerator effluent (Boiler Feed Water) is less than 7ppb by weight, maximum conductivity 0.5 micro S/cm, pH 7-9. While the oxygen scavenger chemical concentration is 12.4% piperazine derived and alkanol ammonia. The 101-U receives steam condensate from 172-C Methanator start up heater, 160-C reboiler and 183-C mol sieve regeneration heater in a common line with a non-return valve and also serves as the return vessel for the minimum flow lines from the 104-J / JA, HP Boiler Feed Water Pumps. 101-U provides suction for these pumps as well.

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The oxygen scavenger injection system, 106-L, is a skid mounted system comprised of two oxygen scavenger injection pumps and a chemical mix tank. The tank has a level glass, LG-1806, and is equipped with an overflow line and a drain line to the drain system. Water supply to the tank is demineralized water. Each pump can be isolated for maintenance and each also has a suction strainer for protection and a discharge non-return valve. Discharge pressure gauges, PG-1816 and PG-1817 are provided. Overpressure protection is provided on the discharge line. DCS running indicators are also provided by XL-1120 and XL-1121. LI-1061, with a low and low-low alarm, indicates the level of 106-LF. The Ammonia Injection system, 107-L, is a skid mounted system comprised of two injection pumps and a chemical mix tank. The tank has a level glass, LG-1807, and is equipped with an overflow line and a drain line to the drain system. Water supply to the tank is demineralized water. Each pump can be isolated for maintenance and each also has a suction strainer for protection as well as a discharge non-return valve. Discharge pressure gauges PG-1818 and PG-1819 are provided. Overpressure protection is provided on discharge line. DCS running indicators are also provided by XL-1122 and XL-1123. LI-1071, with a low and low-low alarm, indicates the level of 107-LF.There is also a LSL-1071 provided to shutdown pumps on low level. HP Boiler Feedwater From the storage section of 101-U, boiler feedwater is pumped by 104-J / JA, High Pressure BFW pumps, to the 141-D Steam Drum, through 131-C to 103-C1/C2 and 123-C1/C2 exchangers. Other services supplied with boiler feedwater are the HP steam desuperheater SPDH-210 and the HP to MP steam letdown desuperheater DH-102 and DH-112. The normal high pressure Boiler Feedwater Pump, 104-J, is steam turbine driven and the standby pump, 104-JA, is motor driven. LSLL-1123 will trip 104-JA if a low-low level exists and the pump is running. 104-JT is a medium pressure / condensing turbine that exhausts to the surface condenser 102JTC. 104-JT is protected from overpressure conditions by atmospheric relief valve PRV-104JT. Demineralized water from DM Header is used to seal the PRV to prevent air ingress. Exhaust temperature can be seen locally on TW/TG-1759 and the exhaust pressure on PG-1843. The medium pressure steam flow to 104-JT is shown in the DCS on FI-1117 with the inlet steam temperature indicated locally on TW/TG-1755, on DCS at TI-8044 and the pressure on PG-1842 locally. The inlet steam isolation valve has a 1” warm up bypass line around it. Since the 104-JT exhausts from the top of the turbine it is possible to build up a level of condensate in the bottom of the turbine that could cause internal damage to the blades. A system has been installed to prevent this build up by installing a 1" drain pipe to collect the condensate in a pumping trap. The system then uses a low pressure steam ejector, SP-104JT, to remove the Section 5 – Process Operating Principles

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condensate from the pipe through a non-return valve and direct it to the 102-JTC surface condenser. The LS steam to the ejector has an upstream strainer to prevent plugging and a globe valve to control the steam flow. The ejector can be isolated at the turbine, upstream, and downstream for repairs. HP BFW pumps, 104-J and 104-JA are provided with automatic minimum flow (ARV) valves, SPARV-104J and SP-ARV-104JA in the discharge lines that recycle water back to the 101-U during low flow conditions. Each pump has a suction strainer for debris removal, a local suction pressure gauge, PG-1748 for 104-J and PG-1749 for 104-JA, a local discharge pressure gauge, PG-1763 for 104-J and PG-1764 for 104-JA, and a pump warm up bypass line around the minimum flow check valves. These warm up lines are to ensure that the pump is always at operating temperatures in case a rapid start is required and have restriction orifices, SP-RO-6402 in 104-J and SP-RO-6452 in 104-JA, installed to limit the flow of warming water. These can also be used for small start-up water flow requirements. Each pump also has blindable flanges on the suction and discharge nozzles and has 6” nozzles with blind flanges for chemical cleaning activities.

WARNING Both 104-J BFW pump suction valves must remain open as long as there is a potential for high pressure BFW to enter the pump from downstream as the suction side and piping are not designed to withstand the high pressure BFW pressure and failure will result. Boiler feedwater temperature is indicated in the DCS on TI-1556 with a high alarm and pressure shown on PI-1095. 104-JA has a motor run status indication to the DCS on XL-1033 and a common trouble alarm XA-1005. 2 The flow of 381,931 kg/h from the 104-Js is metered by flow indicator, FI-1006. A DCS low flow

indicator with alarm FSL-1106 that will sound FAL-1106 in the DCS and automatically start the 104-JA pump when the flow drops if the HOA switch is in the auto position and the 101-U level is not low. The flow passes through 131-C where it is preheated to 173°C before splitting into parallel flows going to the 103-Cs, 123-Cs and 130-D. The BFW flows through 131C has a bypass for temperature. Local TW/TG-1836 indicates the temperature directly out of 131C tubes. TIC-1420 controls the BFW temperature to the 103-Cs and 123-Cs as preheated in 131-C. TIC-1420 controlls TV-1420. TV-1420 is the coil bypass valve. TV-1420 fails close on instrument air failure or loss of control signal. It is provided with a handjack for manual operation. The 123-Cs boiler feed water pre heaters / steam generators are provided with DCS controller FIC-1020 which directs BFW to the 141-D Steam Drum. FV-1020 is set to fail Section 5 – Process Operating Principles

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open if instrument air is lost. This controller has high and low flow alarms to warn of those conditions. FV-1020 is equipped with a hand jack. The BFW flow of 227,437 kg/h is set on FIC-1020 and TIC-1415 and HIC-1032 are adjusted for flow through or around 123-C2 to maintain a process gas outlet temperature from the 123-C2 at approximately 197°C as shown in the DCS on TI-1371. 123-C2 outlet boiler feed water temperature is expected to be 292°C and is DCS indicated on TIC-1415 and the BFW / steam exit temperature from 123-C1 is expected to be 328°C. At this temperature there will be an approximate 20.7% vaporization rate. 152,044 kg/h of BFW flows through 103-C1/C2, heating the feed water to about 328°C, high pressure steam saturation temperature, as influenced by TIC-1011 adjusting BFW flow through and around 103-C2 to control the LTS process gas inlet temperature.TIC-1011 provides a split range control, 0-10% to TV-1011B on 103-C2 BFW by pass and 10-100% to TV-1011A on 103C2 BFW inlet. TV-1011A fails open and TV-1011B fails close on loss or control signal or instrument air. Both have hand jacks for manual operation. Process gas temperature exit 103C1 is shown on DCS TI-1610. Increase in temperature is achieved by exchange with the HT Shift Converter effluent. The temperature of the feed water exiting 103-C2 is estimated to be 262°C as shown on DCS on TI-1601 and after the by-pass on TI-1611. The vaporization rate in 103-C1 is expected to be 20.7%. This flow through 103-C1/C2 is monitored at FT-1072, which via the controller FIC-1072 provides a 10-100% and 0-10% splits range control to FV-1072A/B respectively, both on the BFW inlet line to 103-C2. FV-1072A/B both fail open on loss of instrument air or control signal and have hand jacks for manual operations. There are 6” blind flanged nozzles upstream and downstream of both 123-Cs (total of 4) and both 103-Cs (total of three – one common one in between) for use during pre commissioning for chemical cleaning and flushing. All BFW inlet and outlet flanges on all four exchangers can be blind isolated.

WARNING Over adjustment of TIC-1011, as well as on FIC-1020 can place the 123-Cs and / or the 103-Cs in a transition from boiling to non-boiling which could cause an upset in the 141-D levels. A low level in 141-D will trip the fires and feeds to the reformers. The lines feeding the 141-D from both exchanger sets have non-return valves to stop reverse flow during upsets. The lines have isolation valves that must be chained and locked in the open position for normal operations. BFW quality at steam drum are as below : pH @25oC : 8.5 – 9.8 Conductivity : less than 60 micro S/cm 3Phosphoric ion as PO4 : 3 ppm (max) Silica as SiO2 : 0.3 ppm (max) Phosphate for steam drum pH and corrosion control is injected into the BFW line from the Section 5 – Process Operating Principles

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103-Cs going to the drum through a non-return valve and an isolation valve. The injection rate is manually controlled by adjusting the amount of the pump’s injection strokes. The phosphate injection is located on the 108-L skid. The phosphate injection system, 108-L, is a skid mounted system comprised of four phosphate injection pumps and a chemical mix tank. The tank has a level glass, LG-1808, and is equipped with an overflow line and a drain line to the sewer. A motor operated mixer is added for completely mixing solid phosphate material with the water. Water supply to the tank is demineralized water. Each pump can be isolated for maintenance and each also has a suction strainer for protection and a discharge double block valve. Discharge pressure gauges, PG-1820 and 1827 are provided as are pump DCS running indications on XL-1124, XL-1827. Overpressure protection is from internal relief valves within the injection pumps. 5.1.18.

Steam Systems

5.1.18.1. High Pressure Steam Generation High pressure steam at 123.1 kg/cm²(G) and 510°C is generated in the 101-C, Secondary Reformer Waste Heat Boiler, 103-C1 / C2 HTS Effluent Steam Generator / BFW Pre heater, and 123-C1 / C2 Ammonia Converter Effluent Steam Generator / BFW Pre heater. The level in the 141-D steam drum is maintained by DCS LIC-1001A/B which is a part of the two element control system. LT-1001A and LT-1001B, located on opposite ends of the drum, send output signals to DCS hand switch, HS-1103 and indicate the uncompensated level in the DCS on LI-1001A and LI-1001B. This switch can be used to select which of the two signals goes to the single or 3-element controls. The signal sent through is compensated by PI-1036 (with high and low alarms) from 141-D drum, to compensate the level transmitters for water density. This is especially useful during start-up when water densities are much higher at the lower steam pressures than normal which would cause a false higher level indication than actually exists if not corrected. The 141-D has two separate forms of level control and all of these points are in the DCS:  3-element  single-element The 3 element control uses a PI-1036 pressure with high and low alarms, corrected steam flow from FY-1033A in the DCS to FI-1033 and biases it with BFW flow from FI-1020 in a DCS calculation block FY-1033B. FI-1033 has high and low flow alarms associated with the indication. FY-1033B output is sent to FIC-1072 as a remote setpoint by selecting the appropriate HS-1104A switch settings. The single element control system has LIC-1001B controlling the level by sending an output to HS-1104A to forward the output directly to FV-1072 through FIC-1072.

Section 5 – Process Operating Principles

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WARNING There is very little difference between the normal and maximum levels in the 141-D. Operating the drum higher than the maximum design level will cause the separation cyclones to become covered and they will no longer function. Water will be carried over with the steam causing severe damage to 102-C, 105-JT, 103-JT, and possibly the 101-B superheater coil. The retention time of the 141-D under normal flow conditions is only about 5 minutes and is considerably less from a low level.

LIC-1001A has both high and low alarms incorporated. LG-1601A and LG-1601B level glasses are also provided. Three additional level transmitters are also provided – LT-1223A / B / C. If the level becomes critically low for two out of the three, level alarms LALL-1223 A/B/C/D in the DCS in the control room, will sound and shutdowns through interlock I-101. Transmitter failures are DCS monitored on XA-1223 A/B/C. PT-1036 is used for density compensation. LI-1223 A/B/C have associated high and low alarms. Water is withdrawn from the drum through two vortex breakers into two lines that combine into a single down comer by gravity and thermally circulates through the 101-C. It is a single pass, shell and tube, refractory lined, water jacket cooled heat exchanger. Within the limitations of the process temperatures, the steam generated by 101-C can be varied by adjusting the 102-C steam superheat using TIC-1004. The 101-C down comer line has a removable elbow and a 6” blind flanged nozzle for use during chemical cleaning. The five riser lines have flanges for blinding on all five outlet nozzles and 6” blind flanged nozzle for use during chemical cleaning on each line. Externally the drum is instrumented with pressure indicators, PI-1036 in the DCS with a high and low pressure alarm and PG-1750 locally. The saturated steam temperature exiting the drum is shown on TI-1550 in the DCS. This temperature can be used to verify the drum pressure by using steam tables showing saturated steam pressure and temperature relationships. There is also an ASTM steam sampling station, incorporated into the steam line exiting the drum to sample the steam for purity. A DCS conductivity monitor, AI-1051 with a high alarm, is mounted on the ASTM probe line to sample steam conductance. A grab sample point has also been provided. The drum has a 2" top mounted double block valve vent line for use during start-up and shutdown. DCS PI1236 denotes the system pressure on this vent line. The drum is protected from overpressure by safety relief valves PRV-141D1 and D2, set at 139.9 kg/cm²g and 144.1 kg/cm²g respectively, exhausting to the atmosphere. Section 5 – Process Operating Principles

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Internally the 141-D typically contains cyclone type steam separators for disengaging the liquid / vapor mixture entering to the vessel from the steam generating equipment. The demister pad covering the steam outlet nozzle is a chevron type separator to assure dry steam exiting the drum. The vessel also contains vortex breakers at each liquid outlet nozzle plus water distribution pipes attached to each boiler water inlet nozzle. To maintain the drum water total dissolved solids, TDS, a system of boiler water blow downs are incorporated. The continuous blow down, which is expected to be about 1%, or 3,795 kg/h, of the total steam generation, is manually drained (blown down) to 186-D, Steam Blow down Drum, through a special blow down valve, SP-BDV-141. If a larger amount of blow down is required, a second blow down line capable of up to 5% blow down can be manually opened to the 186-D using SP-BDV-142 valve. 101-C down comer can also be blown down to the 186-D using SPBDV-143 valve. There is also a double blocked drain line on this down comer as well. Each SP valve has an upstream gate type isolation valve. Cooled and hot grab sample points are provided for checking the drum water constituents through a double valve block arrangement to a water cooled sample cooler. AE-1050 will continually monitor the conductivity of the water in the drum. AI-1050 will indicate this value on the DCS and will have a high alarm. To monitor the pH of the blowdown water AE-1006 is supplied. Indication will be in the DCS by AI-1006 with high and low alarms. 186-D drum contains an inlet deflection nozzle and demister in the top section. Level is indicated and controlled on DCS controller LIC-1129 which has high and low alarms built in. The level valve LV-1129 fails open on loss of air or control signal and has a handjack for manual operation. Level glass, LG-1629, can be used locally to view the drum level. There is also a 3” bypass line to the Cooling Water Basin if LV-1129 is isolated for maintenance. In 186-D is provided 1” overflow line. Blowdown water that enters the 186-D from 141-D flashes when the pressure is reduced from 126.5 kg/cm²g to 3.6 kg/cm²g. The steam flashed exits the top of the vessel to the LP steam header through a non-return valve to prevent blowback from the header should the level valve fail open. The remaining water, about 2,210 kg/h, is drained through a disengaging piping section to the blowdown pit. 5.1.18.2. HP (123.1 Kg/Cm²g) Steam System HP Steam, after being superheated to 510°C, is primarily used as the driving force for the turbine drivers of the 103-JT, Synthesis Gas Compressor, and 105-JT, Refrigeration Compressor.

Section 5 – Process Operating Principles

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The saturated HP steam flows in series from the 141-D, Steam Drum, through the special ASTM steam sampling probe. The saturated steam to the 172-C exchanger takes off just downstream of the sampling probe. Flow then continues through 102-C superheater, continues through the Steam Superheater Coil, contained in the convection section of the 101-B furnace to the inlet of the 103-JT and 105-JT steam turbines. In exchanger 102-C the saturated steam is superheated by exchanging heat with the 101C process gas effluent stream. The various process gas streams exiting 101-C and 102-C are rejoined with the average temperature of the mixed stream going to the HTS sensed by TIC1010 and controlled at 371°C. The two controllers, TIC-1010 and TIC-1004, will work independently of each other but the overall split of the duties is related. The actual superheat temperature control is sensed by TIC-1004 controlling the valves in the process gas outlet of the 101-C, and the main 102-C outlet line. The HP steam temperature at the outlet of 102-C is 338°C. WARNING The superheated steam temperature exiting the 102-C should not exceed 399°C under normal conditions and should never exceed 426°C under any conditions. In the 101-B convection coil, the steam is further superheated to 510°C by exchange of heat with the furnace flue gases. The temperature exiting the cold superheater coil is DCS indicated on TI-1552 which has a high alarm. Should the temperature become excessive, PLC temperature switch TSHH-1109 will activate and trip the fuel gas to the superheater burners. The temperature is indicated on DCS at TI-1009, with a transmitter failure at XA-1011 and it also has an associated TAHH-1009. The superheat temperature out of the hot coil is sensed by DCS TIC-1005 and TIC-1005A. This controls the temperature by adjusting the firing rate of the superheater burners in the 101-B convection section using TIC-1005 adjusting TV-1005 fuel gas valve. TIC-1005A controls temperature by adjusting the BFW valve, TV-1553 (through TIC-1553), to the cold HP Steam Superheat Coil outlet desuperheater, SP-DH-210. TV-1553 fails closed when instrument air is lost and is equipped with upstream and downstream double block with a non-return valve and a strainer. TSHH-1007 also indicates hot coil outlet and will activate the superheat burners trip logic on high temperature. The temperature is indicated on DCS at TI-1007, with a transmitter failure at XA-1012 and it also has an associated TAHH-1007. Just downstream of SP-DH-210 is a 6” diameter boot in the piping to remove any liquid water that may be present and trap it into the MP steam header. The trap has an upstream strainer, a double block bypass with one globe valve and can be fully isolated for maintenance.

Section 5 – Process Operating Principles

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TIC-1005 comes with both high and low temperature alarms. TIC-1553 senses the cold coil outlet temperature downstream of the desuperheater and alarms in the DCS if a high or low temperature is sensed. WARNING The piping downstream of the superheater coil is only designed for 530°C maximum temperature at design pressure. This temperature must not be exceeded or the piping may be overstressed. The steam flow from the 141-D to the 103-JT and 105-JT is instrumented for monitoring temperature as described and pressure using PIC-1018 and local PG-1098. A high pressure alarm and a low pressure alarm will sound on PIC-1018 if either of those conditions are reached. For steam import during ammonia plant start-up and after ammonia plant trip, PIC-1018 controls PV-1018 . This line has an isolation valve. From PV-1018 the HP steam go through DH-102, which the BFW inlet controlled by TIC-1216 use TV-1216. TIC-1216 get temperature input from TT-1216 at DH-102 outlet line to MP header. PIC-1018 uses split range control through high selector PN-1018 with PIC-1013, 0-50% signal going through PY-1013 to 103-JT governor, and then 50-100% signal goes for letdown to MP by PV-1018. The PY-1018 high select signal from PIC-1013 and PIC-1018 is sent to PV-1018. PIC1013 output and PIC-1018 output track when the control signal is not the selected greater signal for bumpless transfer. The steam system piping and the superheater coil are protected from overpressure by safety relief valve PRV-101B1/2 set at 135 and 137 kg/cm²g relieving directly to the atmosphere. The header also contains a manually operated, vent HV-1048 and silencer, SP-152, that is used during startup, shutdown, and emergency situations. This silencer duty is shared with the medium pressure steam vents. HV-1048 is a tight shutoff class valve and has an upstream gate valve for isolation. Normally, all HP superheated steam flows through the 103-JT and 105-JT turbines. The amount of HP steam required by the 103-J compressor is directed through the condensing section of the turbine and on to the surface condenser while the remainder of HP steam flows to the MP header. All of the HP steam is sent to the MP steam header in 105-JT. When one or both of the turbines are not operating, the steam flow is passed through letdown valves PV-1018 and HV1028. HV-1028 will open on a 103-JT or 105-JT trip, into the MP steam system. DCS HIC-1028 controls HV-1028 and receives internal DCS inputs from the 105-J and 103-J trip circuits through internal block XS-1128. If one or both of these turbines trip, a corresponding output will be sent to HIC-1028 to immediately open the letdown valve. The PV-1018 control valves fail closed if instrument air or the control signal fails but are supplied

Section 5 – Process Operating Principles

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with a volume bottles on the supply air so that the valve can be operated for a period even if instrument air pressure is too low, both valves have handjacks for manual operation. PV-1018 fails to last position. These valves also all have handjacks for manual operation. HV-1028 control valve close open if instrument air or control signal is no longer available but also contains a volume bottle as described for PV-1018. All valves can be fully isolated for maintenance 5.1.18.3. MP (46.9 Kg/cm²g) Steam System MP steam is consumed in the ammonia process and is used as the driving force for steam turbines. The MP steam header is measured by pressure transmitters PT-1013, PT-1014 and PT-1015 to median select PN-1015 which provides control necessary for the MP steam system. PIC-1013 uses split range control through PT-1018 with 0-50% signal to 103-JT governor to first control 103-JT extraction pressure, then letdown to MP by PV-1018 (50-100%). PIC-1013 output and PIC-1018 output track when the control signal is not the selected greater signal for bumpless transfer. HIC-1028 controls letdown valve HV-1028 by DCS operator setpoint and is overridden by I-103J or I-105J shutdown signal thru XS-1128. XS-1128 sets the position change for valve based on flow of HP steam thru the appropriate turbine. PIC-1014 controls PV-1014 to provide overpressure thru MP steam vent silencer. A portion of MP steam is export to offsites. Local PG1752 indicates MP header pressure. When the 105-JT and / or 103-JT are not operating or the medium pressure steam header pressure is too low due to operational upsets, pressure controller PIC-1018, sensing the MP system pressure, first acts upon the 103-JT HP steam governor and then opens the control valve in the letdown system to supply MP steam. In the event 103-JT or 105-JT trips, HIC-1028, in the HP to MP letdown system, will open to the output set on the controller dumping the HP steam into the MP system. The output setpoint on HIC-1028 is set to match the value of the letdown flow to the flow being extracted from the HP section of the 103-JT or 105-JT and the HIC can be used to modulate the letdown valve as needed. HIC-1028 input comes from a DCS internal summary relays, XS-1128, where the signal is calculated to the output from HIC-1028, 103-JT / 105-JT trip setpoint. The summed signals then position HV-1028 accordingly. When the HP to MP letdowns are in service, an attemperation system is provided to maintain the steam temperature at the design 386°C. DCS TIC-1216 use high pressure BFW to an internal attemperator in DH-102 to maintain this temperature and is provided with a high and low temperature alarm on the DCS. TV-1216 valve fails closed and is provided with isolation valves, a handjack to operate manually and an in-line strainer. The line to the desuperheater contains a non-return valve to prevent the backflow of steam to the BFW system and an isolation valve. Section 5 – Process Operating Principles

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DCS TIC-1116 uses high pressure BFW to an internal attemperator in DH-112 to maintain this temperature and is provided with a high temperature alarm on the DCS. TV-1116 valve fails closed and is provided with isolation valves, handjack and in-line strainer. The line to the desuperheater contains a non-return valve to prevent the backflow of steam to the BFW system and an isolation valve. If the MP steam header pressure becomes too low for any reason, DCS PIC-1013 through PN-1013 as detailed earlier will open the HP to MP header letdown valves to bring the header pressure back to normal. Doing this will sacrifice the HP steam header pressure but will save the plant process from tripping. If excessive steam is being supplied, PIC-1014, sensing the MP header pressure and alarming if the pressure goes high, vents excess steam to the atmosphere through silencer, SP-152. The vent valve will fail closed if control air or signal is lost and handjack can be used to manually operate the valves. The valve can be isolated for repair without having to depressure the system. PG-1752 can be used to monitor the header pressure locally. The header is further protected from overpressure by safety relief valve PRV-1314 set at 51.6 kg/cm²g and relieve to atmosphere. Medium pressure steam can be exported to offsites. Import flow is measured in the DCS on FI1350A and totalized on FQI-1350A whereas the export flow is measured on FI-1350B and totalized on FQI-1350B. The two flow rates are pressure and temperature compensated using PN-1015 and TI-1554 There is a battery limit blindable isolation valve. ISBL MPsteam header pressure is controlled by OSBL boiler. In case export flow can not be sustained PIC-1015 will protect the ISBL MP steam header pressure and reduce the export flow rate. PV-1015 fails close on loss of instrument air or control signal and has a hand jack for manual operation. PV-1015 has a 18” bypass with a non-return valve installed on it. PV-1015 has an isolation valve upstream to it at the battery limit, and this has a bypass line with a double block and bleed arrangement valve to allow unhindered import of MP steam from OSBL. 5.1.18.4. LP (3.5 Kg/Cm²(G)) Steam System The main users of the LP steam is the 101-U deaerator. Other users include: turbine gland condenser ejectors, utility stations, Make-up to the 3.5 kg/cm²(G) steam system is from 186-D, HP and MP turbine gland and packing leakages, as well as a pressure controller PIC-1016, MP to LP letdown valve. DCS PIC-1016 senses the pressure in the LP header and lets down steam from the MP header Section 5 – Process Operating Principles

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to make up for any shortfalls through DH-103. PV-1016 control valve has a handjack and fails closed. The valve has upstream, downstream and attemperator isolation valves. The letdown steam temperature is sensed and DCS indicated on TIC-1023 which has a high and low alarm. Condensate from 119-J/JA is used to reduce the stream temperature. TV-1023 is equipped with a handjack for manual operation, upstream isolation valve, downstream non-return and isolation valve and an inlet strainer. The valve fails closed on instrument air or control signal loss. The LP steam header is measured and controlled by PT-1016, PT-1017 and PT-1020 to median select PN-1017 to provide control for the LP header. PIC-1016 has control of letdown valve PV1016 by median select PN-1017. PIC-1017 provides additional flow and protection for the LP header. The output signal from PIC-1017A is sent to 101-JT governor. The output signal from PIC-1017B controls PV-1017B to vent through SP-153 to provide overpressure thru LP steam vent silencer. The valve is fail closed on loss of instrument air or control signal. Hand jacks are provided for manual operation. PV-1017B has an upstream isolation valve. The export flow rate is temperature and pressure corrected using TI-1555 with a high and low alarms. Overpressure control on the LP system is provided by pressure controller DCS PIC-1017A/B, which includes high and low pressure alarms. PIC-1017A/B receive its signal from PN-1017 mid select block which receives signals from PT-1020, PT-1017 and PT-1016. PN-1017 also sends a signal to PIC-1016 MP to LP letdown described above for controlling LP header pressure. Overpressure protection is provided by PRV-2239 and is set at 5.3 kg/cm²g to vent the atmosphere. The LP steam header temperature is DCS indicated on TI-1555. The outside operators, to check the header pressure, can use local pressure gauges PG-1756. 5.1.18.5. Import Steam (OSBL) MP steam from offsite boiler will be introduced during the start up phase. The MP header will be controlled by letdown valves from HP header and the LP header controlled by the letdown valve from MP header. The ammonia plant exports 37,000 kg /h MP steam once the process is near design rates. 5.1.18.6. Steam Condensate System The steam condensate system consists of condensate formed by condensing the exhaust steam from turbine drivers of 103-JT, 101-JT and 102-JT, this exhaust steam is condensed in surface condensers 103-JTC, 101-JTC and 102-JTC respectively. The condensate from SP-104-JT is directed to the 102-JTC. Section 5 – Process Operating Principles

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The exhaust steam condenses, against cooling water in the tubes, collects in the hot well section of the 103-JTC surface condenser at 90.3 mmHg(a) and 49.4 °C. From the 103-JTC hot well, the condensate is withdrawn by motor driven Condensate Pumps, 123-J / JA. Each of the pumps is fully isolatable and is equipped with a suction strainer for trash removal, a seal flush line from the discharge of the pump through a non-return valve and the seal to the condenser. Each pump also has a local suction pressure indicator, PG-1778 for 123-J pump, PG-1779 for 123-JA pump. Each pump also has a local discharge pressure indicator, PG-1776 for 123-J pump, PG-1777 for 123-JA pump. Each has a running indication in the DCS XL-1036 for 123-J pump, XL-1032 for 123-JA pump. There is an auto start for each of the pumps, SIS LSHH-1127 will auto start the spare pump if the Hand – Off - Auto (HOA) switch is in the automatic position. LSLL-1127 will shutdown the pumps on low-low level. These receive signal from LT-1127. LG-1618 is provided for local indication. The condensate pumps have a minimum flow they must not be allowed to operate below. To protect the pumps a minimum flow controller, FI-1038, has been installed. The flow is measured on the common pump discharge line and LIC-1018 acts on the control valve, LV-1018. LV-1018 is designed to fail close if instrument air is lost and isolation valves and bypass line with a globe valve allows manual operation. AE-1019 indicates the conductivity of the discharge flow on DCS at AI-1019 with a high alarm. Condensate from 103-JTC (123-Js) is directed to and joins a common header from 101-JTC (118-Js) and 102-JTC (119-Js) and are directed to Condensate Filter 112-L. From the 101-JTC hot well the condensate is withdrawn by motor driven Condensate Pumps, 118-J/JA. Each of the pumps is fully isolatable and is equipped with a suction strainer for trash removal, a seal flush line from the discharge of the pump through a non-return valve and the seal to the condenser. Each pump also has a local suction pressure indicator, PG-4778 for 118-J pump, PG-4779 for 118-JA pump. Each pump also has a local discharge pressure indicator, PG-4776 for 118-J pump, PG-4777 for 118-JA pump. Each has a running indication in the DCS, XL-4031 for 118-J pump, XL-4032 for 118-JA pump. There is an auto start for each of the pumps, SIS LSHH-4127 will auto start the spare pump if the Hand – Off - Auto (HOA) switch HS-4127 is in the automatic position. LSLL-4127 will shutdown pumps with low-low level. These receive signal from LT-4127. LG-4618 is provided for local indication. The condensate pumps have a minimum flow they must not be allowed to operate below. The flow is measured on the common pump discharge line indicated on DCS at FI-4038 and LIC4018 acts on the discharge control valve, LV-4018 to control the discharge flow. LV-4018 is designed to fail close if instrument air is lost and isolation valves and bypass line allow for manual operation.

Section 5 – Process Operating Principles

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From the 102-JTC hot well the condensate is withdrawn by motor driven Condensate Pumps, 119-J/JA. Each of the pumps is fully isolatable and is equipped with a suction strainer for trash removal, a seal flush line from the discharge of the pump through a non-return valve and the seal to the condenser. Each pump also has a local suction pressure indicator, PG-6778 for 119-J pump, PG-6779 for 119-JA pump. Each pump also has a local discharge pressure indicator, PG-6776 for 119-J pump, PG-6777 for 119-JA pump. Each has a running indication in the DCS, XL-6031 for 119-J pump, XL-6132 for 119-JA pump. There is an auto start for each of the pumps, SIS LSHH-6127 will auto start the spare pump if the Hand – Off - Auto (HOA) switch HS-6712/6713 is in the automatic position. LSLL-6127 will shutdown pumps with low-low level. These receive signal from LT-6127. LG-6618 is provided for local indication. The condensate pumps have a minimum flow they must not be allowed to operate below. The flow is measured on the common pump discharge line indicated on DCS at FI-6038 and LIC6018 acts on the discharge control valve, LV-6018 to control the discharge flow. LV-6018 is designed to fail close if instrument air is lost and isolation valves and bypass line allow for manual operation. Line TC6003-4” from 119-Js goes to 112-L whose flow is controlled by LIC-6018 controlling LV6018. LIC-4018/LV-4018 controlled TC-4003-6” from 118-Js and LIC-1018/LV-1018 controlled TC1003-4” tie in to the discharge line from 119-Js and export condensate to OSBL. 103-JTC is provided with all the instrumentation necessary to ensure efficient operation. Level is controlled by LIC-1018 which has associated high and low level alarms. Demineralized water can be imported from offsites through isolation valves through line DM1085-2” for initial filling at startup and during emergencies. LV-1018 is located on the discharge of 123-J / JA will fail closed if instrument air is unavailable and comes with isolation valves and a bypass. Level glass LG-1618 can be used for level verification at the condenser hotwell. The condensate flowing from the surface condenser is analyzed for conductivity by on-stream analyzer AI-1019, with DCS indication and high conductivity alarm. A high conductivity alarm may indicate cooling water leakage into the condenser. An automatic three way valve can be employed if the water quality is not good enough to forward to the offsite polishers through a nonreturn valve. There is also a local grab sample for manual analysis. isolate it. 101-JTC also is provided with all the instrumentation necessary to ensure efficient operation. Level is controlled by LIC-4018 which has associated high and low level alarms. Demineralized water can be imported from offsites through isolation valves through line DM4085-2” for initial filling at start-up and during emergencies. LV-4018 is located on the discharge of 118-J / JA will fail closed if instrument air is unavailable Section 5 – Process Operating Principles

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and comes with isolation valves and a bypass. Level glass LG-4618 can be used for level verification at the condenser hotwell. The condensate flowing from the surface condenser is analyzed for conductivity by on-stream analyzer AI-4019, equipped with DCS indication and high conductivity alarm. A high conductivity alarm may indicate cooling water leakage into the condenser. An automatic three way valve can be employed if the water quality is not good enough to forward to the offsite polishers through a non-return valve. There is also a local grab sample for manual analysis. 102-JTC also is provided with all the instrumentation necessary to ensure efficient operation. Level is controlled by LIC-6018 which has associated high and low level alarms. Demineralized water can be imported from offsites through non-return and isolation valves through line DM60852” for initial filling at start-up and during emergencies. LV-6018 is located on the discharge of 119-J / JA will fail closed if instrument air is unavailable and comes with isolation valves and a bypass. Level glass LG-6618 can be used for level verification at the condenser hotwell. The condensate flowing from the surface condenser is analyzed for conductivity by on-stream analyzer AI-6019, equipped with DCS indication and high conductivity alarm. A high conductivity alarm may indicate cooling water leakage into the condenser. A manual drain can be employed if the water quality is not good enough to forward to the offsite polishers through a non-return valve. There is also a local grab sample for manual analysis. Inerts and non-condensables are removed from 103-JTC, 101-JTC and 102-JTC by a set of LP steam driven jet ejectors. Local pressure indicator PG-1812 on 103-JTC and PG-4812 on 101JTC and PG-6812 on 102-JTC shows the pressure (vacuum) to ejectors from 103-JTC, 101JTC and 102-JTC respectively with the temperature indicated locally on TW/TG-1831 on 103JTC and TW/TG-4831 on 101-JTC and TW/TG-6831 on 102-JTC. The hogging jets, which is a large volume steam jets normally used for start-up and / or upset cases, exhausts the steam and non-condensables to the atmosphere typically through a silencer. The ejectors typically come in two pairs with each pair capable of 100% of design non-condensable removal. The ejectors pull the non-condensables from the surface condenser shell top. The driving steam from the ejectors is condensed in a condenser against cooling water and the water is trapped back to the hotwell. The non-condensables are vented to the atmosphere. The traps are furnished with upstream drains, strainers, bypasses, and isolation valves for on-line maintenance. There are local PG-1812 on 103-JCC and PG-4812 on 101-JCC and PG-6812 on 102- JCC that indicate pressure on condensers. The surface condensers are protected from overpressure by atmospheric relief valves

Section 5 – Process Operating Principles

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PRV-103JTC, PRV-102JTC and PRV-101JTC all set to relieve at 1.1 kg/cm g. A small flow of condensate is put on top of the relief valve plate to seal it and not allow air to be pulled back into the condenser. The flow of condensate is manually controlled through a globe valve on the inlet. Only enough flow so that drips of condensate are seen going from the overflow line to the sewer. HP Steam Blowdown Drum 186-D’s condensate blowdown is sent to cooling tower basin. 5.1.19.

Jacket Water System

The Secondary Reformer 103-D and Primary Reformer Effluent Transfer Line 107-D water jackets form continuous cooling systems to help protect the respective vessels pressure shells from overheating. The systems are designed to be continually supplied with water and there are two different sources - steam condensate and demineralized water. Steam condensate is the normal supply of water to the jackets, while demineralized water from offsites is the emergency source. Condensate and demineralized water flows, with a normal design flow rate of 3,600 kg/h, are DCS measured by FI-1151 with high and low alarms and on FI-1152 for the demineralized water with a high and a low alarm as water flows to the water jackets. A low pressure alarm on DCS PIC-1113 warns if low flow conditions exist. PIC-1113 is installed in the demineralized water line to automatically supply water if the condensate header pressure falls. PG-1758 local pressure indicator is also available. The PV1113 control valve fails open when instrument air or control signal is not available and has a bypass for manual use and isolation valves. Non-return valves in both the process condensate and demineralized water lines prevent back flowing into that system from the other. The steam condensate line can be isolated if required. Each vessel is supplied with its own source of makeup water by separate level control valves. One stream flows through DCS controlled LIC-1142 control valve LV-1142 to the Secondary Reformer 103-D jacket. Overflow from this water jacket is directed to the drain through a collector and drain system. Level glass, LG-1742 gives local verification of level and LIC-1142 has a high and low level alarm. WARNING The water that is overflowing from the vessel jackets is at the boiling temperature as it is being directed to the sewers through the overflow lines. Operators must use extreme care when looking at the overflows into the sewers or when near the sewer openings so that they do not get scalded by the water or the steam flashing from the water. The 107-D transfer line is supplied water through LV-1143 which is controlled by LIC-1143 with a high and low level alarm. LG-1743 is the local level glass for this vessel jacket. The 107-D is also provided with blowdown drain lines on each of the riser jacket canisters so that

Section 5 – Process Operating Principles

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sediment can be blown to the drain system periodically. Drains are provided at all jacket low points and should be opened occasionally to ensure sludge is not accumulating in the bottom of the jackets. Each jacket system is provided with vents to the atmosphere so that steam produced in the jackets at the vessel walls are cooled can be directed safely away. Operators should check for unusual steaming from the jacket vent or higher water consumption on FI-1151 as early warnings that internal insulation may be failing and vessel walls are beginning to overheat. WARNING It is imperative that water jackets levels be maintained when heat is applied to the primary or secondary reformers. Failure to maintain adequate water levels in the water jackets could possibly cause rupturing of the jacketed vessels. Loss of water flow from the jackets could also cause undue stress in the transfer line piping to the secondary reformer. In the event of loss of jacket water, it is recommended that the reformers be taken out of service until water jackets are again serviceable and water levels can be maintained.

All of the water level control valves fail open if control signal or air is lost and each valve has isolation valves and a bypass line for manual operation. The bypass lines are used to set the base flow for the jackets during normal operation and the level control valves open to make up any difference. Operating experience has shown that better control is seen if the bypass valves are used keeping the level control valves closed but ready in case of a low level. The bypass valves should be set to just have a trickle of water overflowing into the hot sewer from each jacket. 5.1.20.

Cooling Water Systems

The ammonia unit is supplied with cooling water by utility plant. The ammonia unit is supplied with 19,083 ton/h of water at 33°C and 4.5 kg/cm²(G). The cooling water flow is split: • 127-C • • • • •

101-JC1/C2/C3 124-C1/C2 173-C 128-C 110-C

at 11,810 Ton/h then splits again to 103-JTC at 1,245 ton/h, 102-JTC at 2,105 Ton/h and 101-JTC at 8,450 Ton/h. at 1,553 ton/h at 1,645 ton/h at 0-250 ton/h at 103 ton/h at 621 ton/h

Section 5 – Process Operating Principles

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108-C/CA 116-C’s 115-C 174-C Turbine gland LO Cooler 101-J/102-J LO Cooler 103-J/105-J Ejector Condenser

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at 1,453 ton/h at 645 ton/h at 560 ton/h at 280 ton/h at 181 Ton/h at 300 Ton/h at 167 Ton/h at 130 Ton/h

before returning to the cooling tower at 42.1°C and 2.5 kg/cm²(G). Cooling water supply condition at B.L is at 4.5 kg/cm2G and 33°C while the cooling water return at 2.5 kg/cm2G and 43°C (max). The cooling water temperature exiting the tubes in 127-C is designed to be 35.3°C and can be monitored on local TW/TG-1645. The water exit the 127-Cs splits flowing to the 103-JTC, 101JTC and 102- JTC surface condensers. The 127-C exchanger has an inlet butterfly valve for isolation purposes. 103-JTC has a local temperature indication exit the 103-JTC tubes, on TW/TG-1770 and TW/TG2770 which will run 43°C max operating temperature. Cooling water splits at the inlet to the surface condenser and goes to the jet ejector condenser. The flow through the ejector condenser is controlled using inlet and outlet butterfly valves to isolate and control and the exit temperature can be seen on local TW/TG-1771. 101-JTC has a local temperature indication exit the 101-JTC tubes, on TW/TG-4770 and TW/TG4870 which will run 43°C max operating temperature. Cooling water splits at the inlet to the surface condenser and goes to the jet ejector condenser. The flow through the ejector condenser is controlled using inlet and outlet butterfly valves to isolate and control and the exit temperature can be seen on local TW/TG-4771. 102-JTC has a local temperature indication exit the 102-JTC tubes, on TW/TG-6771 and TW/TG-6772 which will run 43°C max operating temperature. Cooling water splits at the inlet to the surface condenser and goes to the jet ejector condenser. The flow through the ejector condenser is controlled using inlet and outlet butterfly valves to isolate and control and the exit temperature can be seen on local TW/TG-6871. Temperature at inlet cooling water can locally indicate on TW/TG-6769 and TW/TG-6770. Each of the 103-JTC, 101-JTC and 102-JTC surface condensers and jet ejector condensers have inlet and outlet butterfly valves. 101-JC1 has inlet and outlet butterfly valves to isolate and control the cooling water flow and a local temperature indicator, TW/TG-1683, at 44.3°C to monitor the exit cooling water temperature. Section 5 – Process Operating Principles

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101-JC2 has inlet and outlet butterfly valves to isolate and control the cooling water flow and a local temperature indicator, TW/TG-1684, at 44.3°C to monitor the exit cooling water temperature. 101-JC3 has inlet and outlet butterfly valves to isolate and control the cooling water flow and a local temperature indicator, TW/TG-7207, at 44.3°C to monitor the exit cooling water temperature. 110-C has inlet and outlet butterfly valves to isolate and control the cooling water flow and a local temperature indicator, TW/TG-1653, to monitor the exit cooling water temperature at 43.8°C. 115-C has inlet and outlet butterfly valves to isolate and control the cooling water flow and a local temperature indicator, TW/TG-1617, to monitor the exit cooling water temperature at 40.7°C. 116-C has inlet and outlet butterfly valves to isolate and control the cooling water flow and temperature indicator TW/TG-1638 with a high alarm, exit water temperature at 40.3°C to monitor the exit cooling water temperature. 124-C1/C2 has inlet and outlet butterfly valves to isolate and control the cooling water flow and a local temperature indicator, TW/TG-1632, to monitor the exit cooling water temperature at 43.2°C. 143-C has inlet and outlet butterfly valves to isolate and control the cooling water flow and a local temperature indicator, TW/TG-7206, to monitor the exit cooling water temperature at 44.3°C. 173-C has inlet and outlet butterfly valves to isolate and control the cooling water flow and a local temperature indicator, TW/TG-1901, to monitor the exit cooling water temperature at 42.5°C. 174-C has inlet and outlet butterfly valves to isolate and control the cooling water flow and a local temperature indicator, TW/TG-1651, to monitor the exit cooling water temperature at 44.3°C. 128-C has inlet and outlet butterfly valves to isolate and control the cooling water flow and a local temperature indicator, TW/TG-1634, to monitor at 45.2°C the exit cooling water temperature. Miscellaneous flows are to LO coolers, gland condensers, etc. Each will have valves to control flow and temperature with local temperature indications. The combined return flow is expected to be 43°C.

5.1.21.

Service Water System

Fresh filtered water, from the local utility, is supplied from the offsite area for the service water system. The system has main and branch headers through the ammonia unit to supply water for Section 5 – Process Operating Principles

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hose connections. 5.1.22.

Potable Water

Treated water, suitable for human consumption (potable) is supplied to the ammonia unit from the existing offsite area. This water is used for emergency showers and eyewash stations in the utility and ammonia areas. 5.1.23.

Instrument and Plant Air Systems

The normal source of compressed air for the instrument and plant air systems is extracted from the fourth stage suction of the 101-J, Process Air Compressor. The wet compressed air flows to the offsite area for drying and distribution pressure of line to the Plant Air header can locally indicate by PG-1618 with a flow indication on FE-1040. While, the pressure of Passivation Air to offsite area is controlled by PIC-2200 with flow indication on FE-1000. It is also protected by PRV-PV2200 at set point 10.5 kg/cm 2g. The plant air system has main and branch headers through the ammonia unit, supplying hose stations. The basic use of the air is to drive pneumatic tools. 5.1.24.

Instrument Air System

Instrument air is supplied from the off sites to the ammonia facility. All of the instrument air headers to each of the units has isolation valves. 5.1.25.

Inert Gas System (Nitrogen)

Nitrogen is the medium of the inert gas system. It is supplied from off sites at 5 kg/cm²g. The piping headers goes through the ammonia unit supplying hose stations and various permanent connections piped to process equipment. Nitrogen purity in the header must not exceed 50 mg / m3v total oxides for use as a purge medium for vessels containing reduced catalyst. 48. Fuel Gas System Fuel gas to the ammonia unit is supplied by Natural Gas supply lines from upstream of 174-D. Downstream of PV-1001A/B, line FG1002-10” takes off to fuel to 101-B Arch burners and 102-B. PV-1001B controls the pressure for supplying fuel gas to 101-B and 102-B. The header is protected from overpressure by PRV-FG1002 set at 9 kg/cm²g. Downstream PV-1001B the flow splits and goes to arch burners and superheat burners. PIC-1002 controls pressure to arch burners through valve PV-1002-A and B. PV-1002B and is used during start up of the furnace. Fuel to 102-B is pressure controlled with PIC-1051/PV-1051 and the flow is indicated on DCS 1

Section 5 – Process Operating Principles

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as FI-1047. PCV-1154 regulates the pressure to pilots and PV-1051 controls pressure to burners. TIC-1005 and PCV-1144 control fuel gas to superheat burners. 5.1.26.

Fuel Gas To 101-B

The fuel gas header to the arch and superheat burners supplies fuel gas for seven rows of fourteen (98) arch burners for the Primary Reformer radiant section and two rows of nine (18) superheat burners each. All of the isolation valves for the fuel gas to the different areas are manifolded together so that safe isolation during upsets and fire cases is possible. Fuel gas pressure to the 101-B, arch burners will be controlled by PIC-1002. PIC-1002 will alarm on a high or low pressure condition. PIC-1002 is a split range controller, first is controls PV1002A 3” by-pass valve from 0-20% for start up and minimum firing and PV-1002B from 20100% normal operation. The control valves are designed for failing closed on low instrument air pressure or loss of control signal and have handjacks for manual operation. Locally, PG-1768 indicates the pressure and DCS TI-8152 indicates temperature to arch burners. PIC-1002 will be ramped to a preset output through DCS block XS-1129 upon a trip of the reformer 101-B. The arch burner fuel gas system has a burner management system for purging, checking and allowing the burners to be lit that is described later in section 7. Secondary (purge) fuel gas will normally be supplied from the molecular sieve driers regeneration / purifier waste gas – 109-DA / DB, ammonia recovery system – 123-D and 124-D and the HP flash Column 163-D. A non-return valve protects each system, except from the 109-Ds, from backflow of any gases into it from the main purge gas header. A grab sample point is installed on the line after the three fuel lines merge. The Secondary Fuel Gas pressure after merging the fuels is controlled by PIC-1029 venting to the hot vent header. The control valve PV-1029 is TSO type, fails open if the control signal or instrument air is lost and can be operated using the handjack, if necessary. PG-1765 indicates the header pressure locally. DCS controller TIC-1042 (with low and low-low alarms) controls the Secondary Fuel Gas temperature acting on TV-1042 across 183-C that preheats the Purifier Waste Gases. TV-1042 fails close on loss of instrument air or loss of control signal. TV-1042 is provided with a hand jack for manual operation. Manual secondary fuel gas trips are provided. Hand switch HS-1225 and HS-1225A locally will trip the tight shutoff double block and bleed isolation valves XV-1222A (block), XV-1222B (block), and XV-1222C (bleed) by action of the solenoid valves XY-1222A, XY-1222B, and XY-1222C. XV-1222A and XV-1222B valves fail closed on loss of instrument air or control signal while XV1222C fails open. These valves have DCS valve position indications on ZLO/ZLC-1222A/B/C. Section 5 – Process Operating Principles

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SIS Emergency shutdown PSHH-1226B will trip the secondary fuel gas valves by sending a signal to XY-1222 closing valves XV-1222A / B and opening bleed valve XV-1222C which also sounds a DCS alarm PAHH-1226. PI-1226 in the DCS indicates the pressure and has high and low alarms. Local pressure indicator PG-1780 shows the fuel gas header pressure. XA-1231 indicates transmitter failure on DCS. The secondary fuel gas system also has a burner management system for purging, checking and allowing the burners to be lit. This system is also protected from over pressuring by rupture disc PSE-SG1119 set at 2.5 kg/cm²g which relieves into the hot vent. This system is also protected from over pressuring by pressure relief valves PRV-SG1119A/B set at 9.0 and 1.5 kg/cm²g which relieves into the front end vent. Manual fuel gas trips are provided of fuel gas system. Hand switch HS-1252A locally, HS-1250 in the control room and HS-1252 in the penthouse, will trip the tight shutoff, double block and bleed isolation valves XV-1220A (block), XV-1220B (block), and XV-1220C (bleed) by action of the solenoid valves XY-1220A, XY-1220B, and XY-1220C. XV-1220A and XV-1220B valves fail closed on loss of instrument air or control signal while XV-1220C fails open. These valves also have DCS valve positions indicated on ZLO/ZLC-1220A/B/C. There are also pressure transmitters on the main fuel gas system PI-1221 A/B/C with high and low pressure alarms from the SIS. Emergency shutdown, two out of three signal of PI1221A/B/C to PSLL-1221/PSHH-1221 will trip the fuel gas valves by sending a signal to XY-1220A, XY-1220B, and XY-1220C closing valves XV-1220A / B and opening bleed valve XV1220C. These switches will sound DCS alarms on PALL-1221 or PAHH-1221 as well. XA1221A/B/C indicate transmitter failure on DCS. Local pressure indicator PG-1769 shows the fuel gas header pressure. Each system has its own nitrogen checking system for safe ignition. The nitrogen is supplied from the plant nitrogen header. The checking gas nitrogen pressure is controlled by PCV-1728 to the fuel gas and secondary fuel gas headers. A local pressure gauge, PG-1729, downstream of the PCV can be used to monitor the checking nitrogen pressure and PI-1124 to the DCS is downstream of the PCV. A non-return valve in the nitrogen header line prevents fuel gas and purge gas from flowing into the nitrogen header. XV-1221A (block), XV-1221B (block), and XV-1221C (bleed) are the tight shutoff nitrogen supply valves for the main fuel gas to the arch burners. XV-1221A and XV-1221B are designed to fail closed on air loss with XV-1221C failing open. The valves are activated by the action of the solenoid valves XY-1221A/B/C to supply a nitrogen purge to the fuel gas header through a Section 5 – Process Operating Principles

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non-return valve for purging and checking the burner headers as a part of the burner management lighting permissive system. XV-1223A (block), XV-1223B (block), and XV-1223C (bleed) are the tight shutoff nitrogen supply valves for the secondary fuel gas to the arch burners. XV-1223A and XV-1223B are designed to fail closed on air loss with XV-1223C failing open. The valves are activated by the action of the solenoid valves XY-1223A/B/C to supply a nitrogen purge to the secondary fuel gas header through a non-return valve for purging and checking the burner headers as a part of the burner management lighting permissive system. The main fuel burner header can be manually vented through double block valves to the atmosphere if desired. PG-1769 shows the pressure on the main fuel gas header. Each main fuel gas header has a local pressure gauge, PG-1791 A-N through PG-1796 A-N and PG-1809A-N: one for each burner. There are local pressure gauges located on each header for pressure indication of the secondary fuel gas system to the primary reformer burners on PG-1781, 1782, 1783, 1883, 1773, 1804 and 1884. Measurement of fuel gas which flow to primary reformer is done by FI-1015. Primary Fuel Gas Checking HS-1221 Purge / checking Sequence Start handswitch XL-1221A Purging Light XL-1221B Purging Completed Light XL-1221C Checking Light XL-1221D Checking Failed Light XL-1220A OK to open Fuel gas valves XL-1220B Open fuel gas valves Secondary Fuel Gas Checking HS-1223 Purge / checking Sequence Start handswitch XL-1223 Checking Complete XL-1223B Checking failed

NOTE Tripping of the secondary fuel gas system will not trip the primary fuel systems. 5.1.27.

Fuel Gas To 102-B Start-Up Heater

The fuel gas to the 102-B Start-Up Heater tees off of the fuel gas line to 101-B downstream of Section 5 – Process Operating Principles

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PV-1001B fuel gas control valve to 101-B. Total fuel gas supplied to the eight (8) burners of 102-B is regulated from the DCS by PIC-1051 controller and the flow is indicated in the DCS on FI-1047. The flow passes through the double block and bleed trip valve system. PIC-1051 is installed upstream of double block and bleed system. The control valve fails closed on instrument air or control signal failure and has isolation valves and a bypass. Downstream of PIC-1051, the line contains automatic tight shutoff valves XV-1250A/B/C which are activated by solenoid valve XY-1250A, XY-1250B and XY-1250C. XV-1250A and ‘B’ are the isolation block valves while ‘C’ is the bleed. The blocks will close and the bleed will open if a signal from either of the hand switches HS-1257, in the control room, or HS-1257A, locally, is received and will fail in those positions if instrument air supply is lost. They will also operate to isolate the fuel gas to the heater if low-low pressure switch SIS PSLL-1150 or high-high pressure switch PSHH-1150 initiate. A low-low pressure alarm PALL1150 and a high-high pressure alarm PAHH-1150 from pressure indicator PI-1150 (with high and low alarms) in the DCS will alarm to indicate those conditions. Local pressure indicator PG-1785 can be used to monitor the pressure in the fuel gas header. Upstream of the PIC-1051 control valve is a fuel gas take off to the burner pilots. Pilot fuel pressure is controlled by PCV-1154 which has an upstream isolation valve and this system also has a set of tight shutoff trip valves, XV-1255A through ‘C’ activated by solenoid valve XY-1255A, XY-1255B and XY-1255C. XV-1225A and ‘B’ are blocks and ‘C’ is the bleed with ‘A’ and ‘B’ failing closed on loss of air supply and ‘C’ failing open. These are activated when any trip circuit on the heater is activated to trip the pilot burners. All of these valves have DCS valve position indications on ZLO/ZLC-1255A/B/C. Pressure is locally indicated on PG-1797 downstream of the PCV and 1799 downstream of the XVs along with PT-1155 in the DCS with high-high, high, low and low-low pressure alarms. The burners will be tripped if either high-high or low-low fuel pressure is sensed by SIS PSHH-1155 or PSLL-1155, respectively. Both the main and pilot fuel gas headers can be manually vented through double blocks to the atmosphere if necessary. Both fuel gas systems have a nitrogen checking system for safe ignition. The nitrogen is supplied from PCV-5143 through line N3420-2” . Valves XV-1260A (block), XV1260B (block), and XV-1260C (bleed) are the tight shutoff (TSO) nitrogen supply valves for the fuel gas to the main burners through action by solenoid XY-1260A/B/C. XV-1260A and XV1260B are designed to fail closed on instrument air loss with XV-1260C failing open. Valves XV-1261A (block), XV-1261B (block), and XV-1261C (bleed) are the tight shutoff (TSO) nitrogen supply valves for the fuel gas to the pilot burners through action by solenoid XY-1261A/B/C. XV-1261A and XV-1261B are designed to fail closed on instrument air loss with Section 5 – Process Operating Principles

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XV-1261C failing open. The nitrogen flows into the headers through a non-return valves to prevent backflow from one header into another and giving a false pressure indication.The nitrogen pressure is indicated locally on PG-5144 and on DCS at PI-5145. 102-B burners are supplied with a UV scanners, BE-1202 through A9 for main burners and Flame Rod TE-1250 through A9 for pilot burners, to indicate that the flame is burning. Loss of flame shutdown of 102-B will occur if less than 3 or any two adjacent pilots and/or burners lit. 102-B Fuel Gas Checking • HS-1205A Open Main Fuel Gas Valve • XL-1205 Purging • XL-1205B Purge complete • XL-1205C Checking • XL-1205D Checking failed • XL-1215 OK to open pilot fuel gas valves • XL-1210 OK to open Main fuel gas valves • HS-1205A Open Main fuel gas valves handswitch • HS-1215 Open pilot fuel gas valves handswitch

5.1.28.

Fuel Gas To 101-B Superheater Burners

The fuel gas to the 101-B superheater burners also tees off of the fuel gas line upstream of PV1002B, fuel gas control valve to 101-B arch burners. A remotely located isolation valve is provided for safe isolation and shutoff capabilities. Total fuel gas supplied to the eighteen (18) superheater burners is automatically regulated from the DCS by TIC-1005 controller as described earlier. TV-1005 fails closed on instrument air failure and has a handjack for manual operation. Total fuel gas flow to the superheater burners is indicated in the DCS by FI-1031. FI-1031 is pressure and temperature corrected using TI-8154 and PIC-1001B respectively. PCV-1145 is a pressure control valve located bypassing the TV-1005 valve and is use to maintain minimum firing flow to the superheater burners with TV1005 fully closed. Locally, this pressure can be seen on PG-1788. PI-1143 indicates the fuel gas pressure on DCS. 1 Upstream of TV-1005 is the take-off point for the fuel gas to the pilot burners. Pressure control

valve PCV-1144 controls the pressure to the pilots which can be seen locally in PG-1790. The line contains automatic tight shutoff (TSO) trip valves XV-1245A, ‘B’, and ‘C’ which are activated by solenoids XY-1245A/B/C . XV-1245A and ‘B’ are the isolation block valves while ‘C’ is the bleed. Section 5 – Process Operating Principles

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The blocks will also close and the bleed open if low-low pressure switch PSLL-1246 or high-high pressure switch PSHH-1246 initiate which requires a 2 out of 3 failure of PT-1246A/B/C. This will also sound the alarm PA-1246. Low, low-low, high and high-high pressure alarms from pressure indicators PI-1246A/B/C, respectively, in the DCS will alarm to indicate those conditions before a trip point is reached. PSL-1246 is used in the nitrogen purging to verify header pressures. Local pressure indicator, PG-1901 can be used to monitor the pressure in the fuel gas header to the pilot burners. XV-1245A/B/C have valve indication switches ZLO/ZLC-1245A/B/C which indicate valve position. Downstream of TV-1005, the line contains automatic tight shutoff (TSO) trip valves XV-1240A/B/C which are activated by solenoid valve XY-1240A/B/C. XV-1240A and B are the isolation block valves while C is the bleed. The blocks will close and the bleed open if a signal from either of the shutdown hand switches HS-1256, in the control room or HS-1256A, locally is received and will fail in those positions if instrument air supply is lost. They will also operate to isolate the fuel gas to the burners if low-low pressure switch PSLL-1241 or high-high pressure switch PSHH-1241 initiate which requires a 2 out of 3 failure of PT-1241A/B/C. Low, low-low, high and high-high pressure alarms from pressure indicators PI-1241C, PI-1241A and PI-1241B, respectively, in the DCS will alarm to indicate those conditions before a trip point is reached. Alarm PA-1241 will alert on either of the above conditions. XV-1240 A/B/C have valve indication switches ZLO/ZLC-1240 A/B/C that indicate valve position in DCS. Local pressure indicators, PG-1788 and PG-1789 can be used to monitor the pressure in the fuel gas header to the main burners with PG-1788 located upstream of the trip valves. Both the main and pilot fuel gas headers can be manually vented to the atmosphere if necessary. Both fuel gas systems have a nitrogen checking system for safe ignition. The nitrogen is supplied from PCV-1728 through line N1028-1”. Valves XV-1247A (block), XV-1247B (block), and XV-1247C (bleed) are the tight shutoff (TSO) nitrogen supply valves for the fuel gas to the main burners through action by solenoid XY-1247A/B/C. XV-1247A and XV-1247B are designed to fail closed on instrument air loss with XV-1247C failing open. Valves XV-1246A (block), XV-1246B (block), and XV-1246C (bleed) are the tight shutoff (TSO) nitrogen supply valves for the fuel gas to the pilot burners through action by solenoid XY-1246. XV-1246A and XV-1246B are designed to fail closed on instrument air loss with XV-1246C failing open. The nitrogen flows into the headers through a non-return valves to prevent backflow from one header into another and giving a false pressure indication.

Section 5 – Process Operating Principles

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Each superheater burner is supplied with a flame rod to indicate that the flame is burning. These will report to the PLC on BS-1200A/1201 A through I and common alarm in the DCS on BA1200A/1201 A through I. Section 7 includes a detailed description of the gas checking system but below are the indications and switches associated with each system and they are all located locally to the burners: 101-B Superheater Burner Checking HS-1246 Purge / checking Sequence Start handswitch XL-1246A Purging Light XL-1246B Purging Completed Light XL-1246C Checking Light XL-1246D Checking Failed Light XL-1245 OK to open pilot fuel gas valves HS-1245 Open pilot fuel gas valves handswitch HS-1240 Open fuel gas valves handswitch XL-1240 OK to open Fuel gas valves Fuel gas flow measurement is done by FI-1031. 5.1.29.

Fuel Gas to 101-B Tunnel Burners

The fuel gas to the 101-B tunnel burners also tees off of the fuel gas line upstream of PV-1002B, fuel gas control valve to 101-B arch burners. A remotely located isolation valve is provided for safe isolation and shutoff capabilities. Total fuel gas supplied to the seven (7) tunnel burners is automatically regulated from the DCS by PIC-4143. PV-4143 fails closed on instrument air failure and has a handjack for manual operation. Total fuel gas flow to the tunnel burners is indicated in the DCS by FI-4031. FI-4031 is pressure and temperature corrected using TI-8154 and PIC-1001B respectively. PCV-4143 is a pressure control valve located bypassing the PV-4143 valve and is use to maintain minimum firing flow to the tunnel burners with PV-4143 fully closed. Locally, this pressure can be seen on PG-4788. Downstream of PV-4143, the line contains automatic tight shutoff (TSO) trip valves XV-4240A/B/C which are activated by solenoid valve XY-4240A/B/C. XV-4240A and B are the isolation block valves while C is the bleed. The blocks will close and the bleed open if a signal from either of the shutdown hand switches HS-4256, in the control room or HS-4256A, locally is received and will fail in those positions if instrument air supply is lost. They will also operate to isolate the fuel gas to the burners if low-low pressure switch PSLL-4241 or high-high pressure switch PSHH-4241 initiate which requires a 2 out of 3 failure of PT-4241A/B/C. Low, low-low, high and high-high pressure alarms from pressure indicators PI-4241A/B/C, respectively, in the DCS will alarm to indicate those conditions before a trip point is reached. Alarm PA-4240 will alert on either of the above conditions. PSLL-4241 is used in the nitrogen purging to verify header pressures. XV-4240 A/B/C have valve indication switches ZL-4240 A/B/C that indicate valve Section 5 – Process Operating Principles

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position in DCS. Local pressure indicators, PG-4788 and PG-4789 can be used to monitor the pressure in the fuel gas header to the tunnel burners with PG-4788 located upstream of the trip valves. Fuel gas headers can be manually vented to the atmosphere if necessary. The fuel gas system has a nitrogen checking system for safe ignition. The nitrogen is supplied from PCV-1728 through line N1024-1.5”. Valves XV-4247A (block), XV-4247B (block), and XV-4247C (bleed) are the tight shutoff (TSO) nitrogen supply valves for the fuel gas to the tunnel burners through action by solenoid XY-4247A/B/C. XV-4247A and XV-4247B are designed to fail closed on instrument air loss with XV-4247C failing open. Section 7 includes a detailed description of the gas checking system but below are the indications and switches associated with each system and they are all located locally to the burners: 101-B Tunnel Burner Checking HS-4246 Purge / checking Sequence Start handswitch XL-4246A Purging Light XL-4246B Purging Completed Light XL-4246C Checking Light XL-4246D Checking Failed Light HS-4240 Open main fuel gas valves handswitch XL-4240 OK to open Fuel gas valves Fuel gas measurement is done by FI-4031. 49. Vent and Relief Systems There are two (2) main vent systems that collect vented gases, such as start-up vents, and relief valve discharges. The collection systems direct the gases to atmosphere through elevated silencers. The first system, the Hot Vent and Cold Vent Header, collects the hot gases venting from the process equipment usually, but not only, associated with the front end of the plant. The venting gases are directed to the front end flare in OSBL. The major sources of gases vented to this system are: • V1012 - from PV-1084 • V5510 - from 104-D2 • V-2510 - from 104-D2 • V1007 - from 104-D2 • V2203 - from PV-1005 • RV1425 - from PRV-121 D

Section 5 – Process Operating Principles

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• • • • • • • • • • • • • • • • • • • • •

V1103 RV1007 V1006 RV1090 RV1003 RV1089 V2210 V1091/V1092 RV4057 PG1065 V1090 RV-1060 RV-1050 V3225 RV1417 RV1019 RV1022 V-2205 V1150 V1112 V1100

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from PV-1029 from PRV-102J from PV-1032 from PRV-101C1 from PRV-101C2 from PRV-144D from PV-1039A from 108-D’s from PRV-175C from PV-1040 from 108-DA/B–HV-1108 from PRV-SG1024 from PRV-183C from 101-BJT from PRV-FG1002 from PRV-SG1119B from PRV-SG1119A from 173-D from HV-1049 from PV-1004 from 132C vent

Condensate, rainwater, or liquid carryover is separated and the liquid gravity flows to a water seal (goose neck) to open sewer. WARNING Manual drains must be closed after checking system to prevent air ingress into the system that could lead to an explosive atmosphere within the vent piping. The height of the vent system plus the fact that hydrogen is lighter than air helps to create a chimney effect that draws air in through an open lower open drain. The second system, NH3 flare, collects mainly cold, ammonia laden gases intentionally and unintentionally vented from the refrigeration section and also gases from the synthesis loop and compression. The major sources of vented gases are: • RV1020 - from PRV-125D • RV2411 - from PRV-132C1 • RV2410 - from PRV-132C2 • RV2204 - from PRV-103JS Section 5 – Process Operating Principles

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• • • •

V1042 V1060 V1061 RV1015

-

from HV-1019 from PV-1033B from PV-1038B from PRV-120CF4

• • • • • • • • • • • •

RV1014 RV1418 RV1017 RV1421 RV1016 RV2411 RV1018 RV1422/1424 NHV3011 NHL1611 V-1112 RV1060

-

from PRV-103J 3rd stage from PRV-123D from PRV-120CF2 from PRV-124D from PRV-120CF3 from PRV-105J from PRV-120CF1 from PRV-147D1/2 from 105-J drain from PRV-120J from PV-1004 from Recycle H2 124-D

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These gases are directed to the ammonia flare. The vent system has a source for continually nitrogen purging, one is N1022-1”, at end of header has these purge. It has upstream and downstream isolation valves and bleed with a non-return valve between so that vent gases cannot enter the headers. CAUTION WARNING The silencers for the process vents venting highlyto flammable gases and Manual drains must be closed after are checking system prevent air ingress do, on occasion, ignite. Although this can be a spectacular sight and can into the system that could lead to an explosive atmosphere within the ventbe accompanied by a loud noise of ignition, there is no danger from this vent piping. lighting off as it has been designed for this to occur. The height of the vent system plus the fact that hydrogen is lighter than air helps to create a chimney effect that draws air in through an open lower open drain. WARNING Liquid ammonia can accumulate in the NH3 vent system under certain relief valve relieving conditions. Use extreme care when draining the system to the ground if it contains high ammonia concentrations.

50. Safety Showers / Eye Washes Safety Showers / Eye Washes There are safety shower / eye wash combination stations located throughout the plant near areas where dangerous or toxic chemicals may be accidentally contacted by plant personnel. These Section 5 – Process Operating Principles

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stations contain an overhead deluge shower that can be operated by a pull handle and an aerated eyewash deluge operated by pushing a handle. Each station has an alarm that indicate the use of a station on the control room. The potable drinking water system is the water supply for the stations and the water supply piping should be set up so that only one section of safety showers can be taken out of service if repairs are required on the header. Each station can be individually isolated for repairs if needed.

Section 5 – Process Operating Principles

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6. Unit Conditioning 51. Introduction This section covers the work of cleaning, testing and otherwise preparing new equipment for service. The procedures described are carried out as a whole only once, at the completion of construction and before initial operation of the unit, but appropriate phases should be repeated after any major repair, alteration, or replacement during subsequent shutdowns. Scheduling of these initial conditioning procedures should be carefully coordinated with construction in order to accomplish the most expeditious start-up possible. Unit conditioning requires steam and makes it urgent that the steam being supplied from the OSBL boiler be commissioned and proven to facilitate commissioning of the Ammonia Plant. All other offsite facilities being provided should also be available. The ensuing discussion of conditioning is, for the most part, general in nature and does not attempt to establish the order in which the work will be done. This is best determined in the field with due regard to the status of construction and the available utilities. Detailed blowing and flushing procedures are best done in the field where piping configuration may be observed and considered, as well as the mechanical problems involved at certain points. 52. Pressure Testing Pressure tests are made on new or repaired equipment and piping to prove the strength of body materials and welds. They are conducted by filling the equipment involved with air (pneumatic), inert gases (pneumatic), or water (hydrostatic) and building pressure with a portable test pump. These tests are not to be confused with others, made in different ways and at less severe conditions, which may be imposed on assembled sections of the unit before each start-up, to check the tightness of bolted and screwed connections. Construction personnel ordinarily do the initial pressure testing required. If, for any reason, it becomes necessary for the operators to carry out such tests, the specified test pressure and media for each item should be obtained from the proper source and must not be exceeded. Before testing a line, for example, it must be blinded off from any connected vessel or other equipment having a lower test pressure than that of the line being tested. Pressure relieving devices such as relief valves and rupture discs must be removed, gagged, or blinded prior to hydrostatic testing. If the settings of these valves have not previously been verified, this is a good time to certify their relieving pressures before reinstallation.

Section 6 – Unit Conditioning

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CAUTION Rupture discs are subject to damage from corrosion and rough handling. Extreme care in handling and installation is essential. Scratches, dents, pinching, or deformation in the retaining flanges as a result of assembly can cause premature bursting of the disc. Rupture disc installations are usually designed to avoid corrosion and to permit bench assembly of the disc in its retaining flanges. When making up the disc assembly, make sure that the retaining flanges are clean and that the disc is properly aligned. The bolts must be pulled down evenly using controlled torque as specified by the manufacturer. Maintenance of rupture discs must include periodic inspection and replacement as dictated by experience. As the minimum, it is advisable to replace or at least inspect rupture discs during scheduled turnarounds of the unit. Lines and equipment which are tested with media other than water must be isolated, if connected, from any system under hydrostatic (water pressure) test. Instrument piping is to be disconnected from the instruments as close to the instruments as possible. This piping, including instrument manifolds, is to be tested at the same pressure as the process line to which it is connected. Steam supply and exhaust lines must be blanked off from turbines before testing the associated piping. Similarly, suctions and discharges must be blanked off from pumps and compressors. Vessels are provided with connections at the bottom for handling the water required for testing. When filling the vessels, the top of the vessel must be vented to remove all the air. After the vessel is tested an atmospheric vent must be provided to allow air or inert gases to replace the water removed during draining. This is done to avoid creating a vacuum on the vessels as they drain. Draining of towers and drums may be arranged to use the water for further flushing and washing of connecting lines if the quality is acceptable. CAUTION Caution must be exercised to avoid filling some large overhead lines from vessels and towers. The design of hangers, supports, or foundations may not be adequate to support the weight of equipment when filled with water. When testing tubular equipment (exchangers, condensers, and coolers), open bleeder valves on the opposite side to the test side to detect any leakage. For example, if the pressure is being applied on the tubes, open bleeders on the shell side, and vice versa.

WARNING The NH3 Converter Feed Section / Effluent 6 – Unit Exchangers, Conditioning 121-C, and the NH3 Unitized Chiller, 120-C, tube and tube sheet are designed for specific maximum differential pressures. Therefore, when testing these items do not exceed this maximum value between the tube and the shell sides.

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53. Inspection Of Vessels Before the final bolting of the cover plates on manways, or loading of any catalyst in vessels, the interiors of the vessels must be inspected for cleanliness, completeness, and proper installation of internal equipment. The points checked should include the location and length

WARNING It should be specially noted that stainless steel lines and equipment must be contacted with chloride free water only. Since much of the material used in the demineralized water system is stainless steel, lines should be blown with air or steam. If water flush is used, the water must meet the above standard. of thermowells, the location and fabrication details of distributor piping, the location and fabrication details of internal trays, and the range of level instrument floats or outside float cage connections. NOTE During the inspection of vessels, a thorough check of the primary reformer catalyst tubes and collection headers should be made. Check all heat resistant alloy piping for signs of paint. Paints containing zinc, copper, or lead may cause inter-granular corrosion of this alloy piping when heated. If any is found, it must be removed before any heating of this equipment is initiated. The P&ID drawings should be used to verify piping, instrumentation, control valves, block valves, and drain valves. Nameplate data attached to field equipment should be reconciled with the data sheets. Punch lists should be compiled to identify any discrepancies.

54. Catalyst Loading The table below captures the details of catalysts loaded various reactors in the Ammonia Plant

Reactor Tag

Catalyst Supplier

Catalyst

Installed volume(m3)

Hydrotreater

101-D

Clariant KSC

HDMax 200

22

Desulfurizer

108-DA/DB

Clariant KSC

Actisorb S2

2x32

Reactor

Section 6 – Unit Conditioning

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Primary Reformer

101-B

64

HTS Converter

104-D1

Clariant KSC

ShiftMax 120

Synthesis Converter

104-D2A/D2B Clariant KSC Clariant KSC

109 DA/DB

105-D

HH

34

Clariant KSC

Mol Sieve Drier

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38.56

103-D

106-D

CHKD

Clariant KSC

Secondary Reformer

Methanator

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40% Reformax 210 LDP, 60% Reformax 330 LDP 40% Reformax 400 GG, 80% Reformax 400 LDP

LTS Converter

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TBD

Clariant KSC

REV

108 38

TBD

2x41.0

Bed 1: Amomax 10RS Bed 2: Amomax 10 Bed 3: Amomax 10

Pre-Reduced : 17.28 Oxidic : 96.72

55. Primary Reformer (101-B) When storing, handling, loading, reducing, operating, discharging, and disposing any catalyst the instructions and precautions defined in the relevant catalyst supplier’s catalyst manual should be followed. Relevant Data 2 Refer REKIND document number P2B-10-21-DS-001 for tube details

Catalyst The Tubes will contain 2 layers of catalyst type, i.e: Nickel Catalyst on a calcium aluminate support with potassium promoter and Nickel oxide on an aluminate support type. Scope Activity The following techniques may be used to load the Primary Reforming Catalyst: • Sock loading • D ense Loading. The main steps in loading the primary reforming catalyst are: • Keep the tubes covered at all times except the ones that are being loaded at any point of time Section 6 – Unit Conditioning

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Empty tube and catalyst support grid visual inspection & cleaning Draw a retain a sample of each catalyst lot supplied (retain 1 litre sample of each type of catalyst) Measure & record empty tube outage Measure & record empty tube differential pressure Load bottom catalyst layer to the pre-defined level Measure & record bottom catalyst layer outage Measure & record bottom catalyst layer differential pressure Make the appropriate adjustments to those tubes whose bottom catalyst layer differential pressure is outside the allowable +/- 5% of the average differential pressure Load top catalyst layer to the pre-defined level Measure & record combined catalyst layer outage Measure & record combined catalyst layer differential pressure Make the appropriate adjustments to those tubes whose combined catalyst differential pressure is outside the allowable +/- 5% of the average differential pressure.

It is important that the catalyst is not loaded above the specified outage so as to avoid any chances of catalyst milling. A uniform distribution of the mixed feed gas to the reformer tubes is a key element to ensuring optimum Primary Reformer performance. The loaded catalyst tube differential pressure is used as a measure in determining the uniformity of the Primary Reforming catalyst loading. A maximum deviation of +/- 5% is the permissible limit for catalyst tube differential pressure after loading. Any catalyst tube outside the permissible limit will require adjustment either by hammering with a soft hammer in case of low pressure or by partial/complete evacuation in case the pressure drop is on the higher side. In case a delay is foreseen between catalyst loading and start up, follow the catalyst supplier’s guidelines for preservation in the interim period. PD RIG A suitable PD rig should be used for PD measurement during catalyst loading. Dry oil free air is recommended for use in PD rig. Following is a guideline for orifice sizes to be used for PD measurement for different tube ID using 2-4 kg/cm2G upstream air pressure: Tube ID (mm)

100

120

140

Orifice Size (mm)

7

8

9

Section 6 – Unit Conditioning

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56. Packed Bed Reactor Catalyst Loading The following vessels fall into this category: • Hydrotreater (101-D) • Desulfurizer (108-DA/DB) • Secondary Reformer (103-D) • High Temperature Shift Converter (104-D1) • Low Temperature Shift Converter (104-D2A/B) • Methanator (106D) • Molecular Sieve Driers (109-DA/DB) • Convertor (105-D) – further details are given in subsequent paragraphs When storing, handling, loading, reducing, operating, discharging, and disposing any catalyst the instructions and precautions defined in the relevant catalyst supplier’s catalyst manual should be followed. See Catalysts and Chemicals Specs along with Reactor Drawings for the relevant reactor dimensions, catalyst bed configuration, catalyst support configuration, catalyst retaining mesh/grids, etc. The main steps in loading the reactors catalyst are: • Empty reactor vessel and internals inspection & cleaning • Place chalk markings of the levels of the various catalyst inert support and catalyst bed levels o on the vessel wall (markings being made at two points 180 opposed to each other) • Draw a retain a sample of catalyst from each catalyst inert support and catalyst lot supplied • (retain 1 kg each sample for all types of catalysts) • Load catalyst inert support and catalyst layers to the pre-defined levels (recording the mass and loaded outage of each catalyst inert support and catalyst layer) Equipment Required The following items are typically required for the loading of catalyst in various reactors: • Catalyst ‘Superbag’ or a loading hopper and tube with a canvas or flex hose at the lower end for guiding the placement of the catalyst. • Scaffold boards or ‘snow shoes’ for the person inside the vessel to stand on and prevent excessive damage to the catalyst. • Explosion proof / low voltage or GFI, ground fault interrupted, mesh protected lights. • Air supply • Personnel protective equipment such as disposable clothing, dust masks, goggles, gloves • Safety harness with rope or lanyard secured outside of the vessel manway • Screen for dusting catalyst prior to loading ( usually not required with ‘superbag’) Section 6 – Unit Conditioning

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Marking pen for marking refractory walls - bright color and chloride-free where relavant like Secondary Reformer Measuring tape Crane or air hoist with capacity for lifting catalyst to screen or load Rope ladder of at least 18 meters in length Flashlight or battery lantern Weigh scale capable of at least 50 kilograms 3 3 0.0283 m (1 ft ) exact box Air mover to provide ventilation inside the vessel. Rake or other catalyst leveling device Covering over the top of the vessel and the catalyst screening area if rain is a likely possibility. Portable vacuum unit

Preparation Personnel working inside the vessel and the required manway watch must have the approved safety training prior to the start of the loading operation. Entry permits with atmospheric testing are required at all times work is in progress in the vessels. The vessel will have been inspected prior to loading to ensure any internals needed are properly installed, all construction material removed, and vessel walls cleaned of excessive material. There should be no major visible cracks in the refractory lining. All bed heights are to be marked on the vessel walls in a minimum of two places equal distance apart (minimum of two places 180° apart) prior to loading. Records An accurate and complete record must be maintained of the quantity of catalyst loaded. This will ensure the correct amount and types of catalyst have been loaded and possibly assist in solving future operating difficulties. Samples of each batch number of catalyst loaded should be collected. Reactor closure isolation & preservation Follow catalyst suppliers’ guidelines for preservation of each reactor after catalyst has been charged in the reactors Prior to the initial plant start-up all catalyst beds should be de-dusted following the guideline described in Chapter 8 of this document. Section 6 – Unit Conditioning

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57. Catalyst Loading of 105-D Ammonia Converter Scope This procedure with the 105-D drawings will describe the requirements for loading the Ammonia Converter, 105-D. Catalyst • The vessel will contain no beds of ballast material • The vessel will contain four beds of catalyst: 3 3  Bed 1 will contain 17.28 m of pre-reduced iron synthesis catalyst with 1.73 m of 3-6 3 mm granules and 15.55 m of 1.5-3 mm. 3 3  Bed 2 will contain 37.52 m of iron synthesis catalyst with 3.75 m of 3-6 mm 3 granules and 33.77 m of 1.5-3 mm. 3 3  Beds 3A and 3B will each contain 29.6 m each of iron synthesis catalyst with 2.96 m 3 of 3-6 mm granules and 26.64 m of 1.5-3 mm. The catalyst should be kept dry and if it is pre-reduced, it should be under a nitrogen blanket at all times. Records An accurate and complete record must be maintained of the quantity of catalyst loaded. This will ensure the correct amount and type of catalyst has been loaded and possibly assists in solving future operating difficulties. Samples of each batch number of catalyst loaded should be collected. Equipment Required The following items are required for the loading of catalyst: • Catalyst ‘Superbag’ or a loading hopper and tube with a canvas or flex hose at the lower end for guiding the placement of the catalyst • Explosion proof / low voltage or GFI, ground fault interrupted, mesh protected lights • Air supply • Concrete vibrator, air actuated with rod tip, to be operated using nitrogen • Nitrogen supply • Vacuum cleaning equipment (101-B reformer equipment can be used for this) • Five each of the following loading tools: Large “T” pusher - 10 mm high x 45 mm thick x 250 mm wide with a telescoping handle

Section 6 – Unit Conditioning

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having a range of 450 mm to 1,450 mm made of light weight materials. Small “T” pusher - 10 mm high x 45 mm thick x 150 mm wide with a telescoping handle having a range of 450 mm to 1,450 mm made of light weight materials • • •

• • • • • • • •

Ten 15 liter cans Ten hand scoops Scaffold boards ~450 mm square with edges rounded to prevent screen damage or ‘snow shoes’ for the person inside the vessel to stand on and prevent excessive damage to the catalyst Sleeves fabricated to fit between the inner and out manways to prevent catalyst from getting on to the distributor plates Personnel protective equipment such as disposable clothing, dust masks, goggles, gloves Mobile crane with capacity for lifting catalyst to load Flashlight or battery lantern Weigh scale capable of at least 100 kilograms 3 3 0.0283 m (1 ft ) exact box Air mover to provide ventilation inside the vessel Covering for end of the vessel and the catalyst area if rain is a likely possibility

Preparation Personnel working inside the baskets and the required manway watch must have the approved safety training prior to the start of the loading operation. Entry permits with atmospheric testing are required at all times work is in progress in the vessels. The vessel basket assembly will have been extracted from the shell, opened and inspected prior to loading to ensure any internals needed are properly installed and all construction material removed and no water is present If water is observed, it must be removed using swabs of cotton or other absorbent lint-free material. Water that can not be reached can be dried with cool, clean, dry air like instrument air. Catalyst Screening NOTE Screening is normally not done on pre-reduced catalyst although it is possible to do so. If fines are present, they will be in the bottom of the shipping drums and care should be taken not to fully empty the drum during initial loading. If more catalyst is required after nearly emptying all of the drums, the remaining catalyst can be carefully screened to remove the fines then loaded. Section 6 – Unit Conditioning

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Screening of the catalyst, if required, should be started prior to the loading operation. This will ensure the loading can proceed without interruption once started. Screening of catalyst is usually not required as it is pre-screened at the manufacturer before being loaded into drums or bulk bags. However, attrition can occur during rough handling or shipping and screening becomes desirable to avoid excessive pressure drops in vessels and tubes. The screen mesh opening should be sized to pass anything smaller than the smallest specified diameter of the catalyst. That is passing 1.4 mm or smaller for catalyst specified 1.5 to 3 mm as an example. Screening is best done on a simple sloped screen by pouring the catalyst over the screen and letting it gravity flow directly into the loading hopper and into the vessel or into a drum for handling. The angle of the screen should be enough to allow the catalyst to free flow without vibration or mechanical means to assist the catalyst flow. Vibration and mechanical rakes, scrapers, etc., tend to increase attrition of the catalyst and should be avoided. The screen should be wide enough to have enough surface area to allow pouring of the catalyst in ample amounts so as not to slow down the loading process. Short sides should be built up on the screen to help avoid spillage and to help guide the catalyst toward the screen outlet. A portable vacuum unit can be used to help control the dust, if required. Catalyst Weighing During screening or loading, representative samples of catalyst should be weighed to confirm the bulk density and thus the total weight of the catalyst being loaded. 3 3 Fill the previously mentioned 0.0283 m (1 ft ) box with catalyst and be sure that the catalyst is level full with the top of the box. Weigh and record the results as kilograms per cubic meter (pounds per cubic foot). Loading The converter basket assembly is removable by taking off the converter end head and pulling the basket assembly out using the railway rails and vendor removal procedures provided. Catalyst loading will be accomplished with the basket in the removed position. 3-6 mm size catalyst will be loaded in the bottom portion of each of the four beds to a height of 150 mm then leveled. Vibration, using a concrete-type vibrator, can be used to get the required density. A template must be developed and used to assure that vibration is done evenly over the entire catalyst bed or channeling may occur. See example on next page. CAUTION Vibration of pre-reduced catalyst in an air atmosphere is not recommended. The vibration has been known to create enough heat to start a reaction and Section 6 – Unit Conditioning re-oxidation of the catalyst.

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1.5-3 mm size catalyst will be loaded directly on top of the larger catalyst in each of each of the four beds. The T-bars and scoops will be used to push the catalyst under the top distributor plates. Vibration, using a concrete-type vibrator, can be used to get denser loading if desired. A template must be developed, sized to fit the catalyst beds (see example below), and used to assure that vibration is done evenly over the entire catalyst bed or channeling may occur. See the previous CAUTION concerning vibration of pre-reduced catalyst. CAUTION Care must be taken to avoid the penetration of the vibrating tip into the interface between the smaller and larger catalyst. Tight mixing of the two catalyst sizes could lead to excessive pressure drops across the beds. When the loading of the catalyst is completed, the catalyst density should be 99% of design or greater. Close the inner and outer bed manhole covers using new gaskets. Be sure the distribution screens are vacuumed cleaned of any catalyst spilled on the screens. Reinsert the basket into the converter shell using the vendor provided procedures. Replace the converter head and torque the head bolts to the proper specifications as provided by the vessel vendor. Place the converter under a nitrogen blanket and continuous purge.

Section 6 – Unit Conditioning

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58. Line Blowing And Flushing All fluid-handling equipment, particularly piping, should be thoroughly cleaned of scale and the internal debris, which accumulates during construction. Operating personnel should follow up construction with the thorough flushing and blowing required to precommission the unit for operation. Most utility systems, such as water and steam, may be satisfactorily cleaned by means of their normal media introduced through normal channels. Other systems should be flushed or blown with "foreign" media, admitted through temporary hose or pipe connections. Major steam lines will be blown to a polished target bar of agreed upon material, normally aluminum, brass or stainless steel, until a target is acceptable to all parties. Definitions of what is acceptable may need to be altered depending on the hardness of the material used for the Section 6 – Unit Conditioning

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targets. Normally, supervision in charge of line blowing will designate those lines to be blown to targets but as a general rule, all steam turbine inlet and main steam letdown lines will be targeted. Vessels containing catalyst must be blinded-off to prevent wetting catalyst. To whatever extent the lines are connected at the time, they may be flushed with water used in hydrostatic testing. A single filling of a vessel may not provide adequate flushing of all lines for which it is the reservoir. In this case, a continuous or intermittent flow of water into the vessel should be maintained. Water may be admitted to most vessels through temporary connection to a nozzle or into the top of the vessel by hose connection through a top entry line. CAUTION Caution must be exercised to avoid filling some large over head lines from vessels and towers. The design of hangers, supports, or foundations may not be adequate to support the weight of equipment when filled with water. If construction has included a line or piece of equipment (with the line or equipment in place) in their hydrostatic test, this is the ideal time to perform any required flushing. In situations where necessary, construction will install additional temporary supports to accommodate the weights involved in hydrostatic testing. When washing lines from a vessel always be certain that the vessel is adequately vented to prevent vacuum conditions from forming in the vessel.

WARNING The quality of the water to be used is of the utmost importance in all cases. Water used to test or flush stainless steel vessels and / or pipe or vessels with stainless steel internals must be "chloride free". Stress corrosion cracking could occur as a result of contacting the stainless steels with chlorides. Of particular importance is the ammonia converter basket. Every precaution must be taken to prevent water inadvertently entering or being blown into the ammonia converter where it could contact the stainless steel baskets.

To the greatest extent possible, flush down or horizontally, and at low points. The low point outlets will usually be temporary openings made by disconnecting flanges or fittings. Normal drains may be used for flush outlets provided they are equal to line size, or nearly so. Section 6 – Unit Conditioning

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For the best results, there should be no restriction at the outlet or any other point in a line undergoing cleaning. Where it is necessary to throttle the flushing flow, do so at the supply end. The higher the velocity of flushing, the more thoroughly a line will be scoured. Following are some guides for flushing: • Do not flush through control valves • Do not flush through too many circuits or openings simultaneously • Flush through all vents, drains and other side connections • Flush bypasses alternately with their main channels (see remarks on control valves) • Avoid flushing debris into nozzles, small-bore lines, mist collectors and other equipment where it may become lodged or trapped So far as it is possible, divert the initial flow ahead of, or around, equipment until the lines upstream are clean, then flush or blow into or through the item concerned, such as exchangers or vessels. Some instances where this practice is particularly important are enumerated in the following paragraphs. All control valves should be removed or rolled out and a temporary spool piece installed until all foreign material has been removed from their systems. Finally, replace the valve and flush through the valve in normal alignment and / or through the bypass if the valve cannot be opened.

WARNING Special care in line blowing and flushing must be carried out for lines that are using the noise reducing trim control valves which are much more common in today’s plant designs. The holes in the valve cages are very small, <3 mm in diameter. The control valve will plug with rust and dirt if the lines are not very well flushed and blown and could lead to a plant upset or shutdown. It is advisable to start the plant up using the bypass lines around the noise reducing control valves if at all possible to ensure that the lines are well flushed prior to placing the valve in service. Flow meter and restriction orifices should not be installed until lines are clean. Any orifice installed before cleaning should be removed prior to flushing / blowing and line verified clean

Section 6 – Unit Conditioning

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before replacement. This is a good time to measure and verify orifice bores. All connections at pumps, compressors and drivers must be closed off, blinded, or disconnected while the lines running to / from them are thoroughly flushed. This applies to the main suction and discharge lines; driving and exhaust steam; jacket cooling water; and auxiliaries. The flushing or blowing outlet should be at some convenient point as near to the pump or driver as possible. Generally, it will be necessary to disconnect a flange or fitting. Where this is done on the pump or compressor side of the block valve, the open connection on the equipment must be covered to prevent entry of debris. In discharge lines containing a check valve immediately adjacent to the pump, as is generally the case with centrifugal pumps, a flushing outlet may be made by removing the check valve cover plate, provided the flapper or disc remains in place to seal off the pump itself. Where it is desirable to back-flush through a check valve, the flapper must be removed and the cover replaced, or the check valve inverted. CAUTION The pump discharge must still be blinded to prevent any accidental leakage back through the discharge check valves from entering the unit. All connections to instruments must be disconnected at the instrument and blown or closed off during flushing. Instrument air lines must be blown with special thoroughness with clean, dry, instrument quality air. By-pass steam traps until the lines are clean. Check the operation of traps after they have been opened to the condensate and remove for inspection and cleaning any that are not working properly. Have the furnace burners disconnected until all lines to them are blown clean then reconnect and blow air through the burners. Check each individual burner’s orifices to be certain it is unobstructed. After initial water circulation through cooler and condenser tubes, it may be advisable to open the cooler which was flushed first in the series, or one of the first group, for inspection and, if required, cleaning of the tube sheets. If much foreign material is found, other units should be examined. The cooling water system is flushed with its normally supplied water. At the conclusion of flushing any system, check carefully to see that normal alignments are restored, temporary connections broken, and temporary breaks reconnected. Replace check valve flappers and / or cover plates, install orifices, etc. In the case of lines, which will Section 6 – Unit Conditioning

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receive further cleaning during the subsequent breaking-in of pumps, this instruction may be qualified in part. When flushing of the process lines is finished, drain all water from the system as completely as possible. Provide ample top venting or add pressure with air or nitrogen during the draining operation, or whenever the level is being lowered in a vessel, to avoid pulling a vacuum on the equipment. Blow the drained lines to effect further water removal. The basic utility systems, steam, water, nitrogen, and air should be put in normal working order after they have been cleaned, so that supplies will be available for further flushing and commissioning operations.

59. Steam Line Blowing 6.1.1.

Scope

This section identifies the minimum KBR requirements for the cleaning of steam piping with steam blowing. 6.1.2.

Introduction

The purpose of steam blowing is to remove weld bead deposits, pipe slag and other foreign material (iron oxides, etc.) from steam piping and the boiler (all upstream of the turbines) to minimize the possibility of turbine damage. Particles carried by steam will plug turbine strainers and will affect the turbine performance. Larger objects could damage or tear the strainer and pass objects through which could result in damage to the turbine blades and wear to its internals. A number of steam blow cycles will be required for each set of piping. Each steam blow cycle consists of heating, blowing steam through and cooling the related piping until the steam is free of debris (a clean system is obtained). The inherent design of the unit should allow steam to be supplied from the boiler with the necessary temporary piping, materials, and silencer to satisfy a steam blowing operation. The effectiveness of cleaning of specified lines is determined by the use of a polished target properly located in temporary piping. Solid particles carried by the steam blow impact the target and produce pits on the target surface. The target is then analyzed by visual observation. This observation is concerned with the amount and size of all pits on the target. A decision is made with regard to the line being adequately clean, signifying the termination of that particular steam blow. Non-targeted lines are normally blown using three blowing cycles for each line. As a precautionary measure, after steam blowing, it is recommended that an engineered Section 6 – Unit Conditioning

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fine mesh screen be attached to the coarse screen in the inlet strainer casing at each turbine main stop and combined reheat (if applicable) valve. This fine mesh screen is ONLY a temporary device that helps to collect foreign particles and debris not removed by the steam blowing during the initial operation of the unit and MUST be removed after full load operation is achieved (at the next shutdown of that piece of equipment). 6.1.3.

Prerequisites to an Effective Steam Blow

The necessary steam blowing procedure outlining how the steam blows will be conducted must be developed and reviewed with all involved personnel. It is important that this procedure incorporate all related equipment interfaces, safety precautions, and the steam blow target acceptance criteria. A summary of the calculated / preferred system pressures and cleaning force for each phase of the steam blowing operation must be included in the written procedure presented to involved personnel, allowing verification of the pressures to be used during the actual operation. The procedure will also serve to inform the steam blow personnel of the pressures required for adequate steam blowing of the piping at each phase. The steam blowing procedure is to include P&IDs with each phase of the steam blow identified on them. The P&IDs will identify such things as: • which valves are to be removed • instrumentation to be removed • the direction and routing of the blows • the sequence of the blows • amount of steam flow for each blow • the installation of temporary spools and piping • the installation points of the silencers • the equipment affected by the steam blows • any other information deemed necessary A sufficient quantity of polished targets (material: stainless steel, aluminum or brass may be used as agreed with involved personnel) with two or more opposing sides polished to obtain multiple uses must be available. Square stock polished on both sides has also been used successfully. 6.1.4.

Cleaning Effect

During a steam blow the product of the values of velocity and density of the steam at any point in the pipe is constant according to the law of mass conservation. At the exit of the pipe, the velocity is very high, most of the time sonic. The density is low but as the drag force is proportional to the square of the velocity, the effect of high velocity is prevailing and the cleaning effect is excellent. Section 6 – Unit Conditioning

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The Drag Force Equation's primary concern is the cleaning disturbance factor - C. This factor is defined as follows:

where: • ρ1 = density of cleaning medium • V1 = velocity of cleaning medium • ρ2 = density of normal operating fluid • V2 = velocity of operating fluid during upset cases • C measures the flushing or blowing effectiveness and its value must be > 1, ideally > 1.5 The place where the velocity and hence the cleaning effect will be at minimum is at the point following the throttling valve which controls the flow during the steam blowing. Therefore, the drag force comparison should be made at the throttling valve (within 2 to 3 meters of the valve). The mass velocity developed during the actual steam blowing operation must be verified to be correct by the recording of the system pressures at the inlet to the steam blow throttling valves and at the discharge of the temporary blowdown pipe, thereby confirming that the proper mass velocity was attained. NOTE The throttling valve SHOULD be located at the inlet to the pipe being cleaned, NOT at the outlet. It should be replaced at the completion of the steam blow as it will have been subject to excessive wear and may not prove reliable for isolation. The throttling valve function can be replaced by installing additional temporary Restriction Orifice right at the downstram of supply valve to avoid excessive wear of the respective valve 6.1.5.

Steam Blow Preparations

Do not blow contaminated steam through exchangers or other equipment in which debris might become lodged. Steam should be exhausted upstream of this equipment until clean. Control valves, desuperheaters, or any equipment which might be damaged or plugged by entrained particles in the steam flow must be removed. Pipe spools should be fabricated and installed in their place (temporary pipe spools must conform to the piping class of the lines being blown). Precautions must be taken to protect equipment. Examples are: Section 6 – Unit Conditioning

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check valve or the internals removed flow elements removed thermowells and instrumentation removed / disconnected strainer baskets removed control valves removed - especially reduced noise trim type valves atomizing nozzles removed remove any equipment susceptible to steam blow damage / plugging

Steam is to be exhausted as close to the turbine inlet as possible. The trip and throttle valve should be removed and this opening will provide a good exhaust point. The steam is to be opened to the piping and blown at least 10 to 15 minutes after maximum piping temperature is attained. The piping is then to be cooled to at least ½ the maximum temperature attained during the steam blow. 6.1.6.

Steam Blow Target Acceptance Criteria

Acceptable discoloration is only as a result of heat discoloration (i.e., heat being applied to cold rolled steel) and not because of black iron oxide carried in the steam. The target is to be polished material that has been agreed upon by the involved personnel with a cross sectional area of approximately 10% of the pipe cross sectional area. There must be a sufficient number of targets available so as not to delay the steam blowing procedures. The duration of the steam blows with a target in place is to be at least 15 minutes. A recommended target acceptance criteria is the number of unraised pits allowed will be five or less. No pits resulting in metal above the target surface are permitted. The final acceptance criteria will be determined in the field and agreed to by all involved personnel. Since turbulent flow will exist, the number of acceptable unraised pits is restricted to an area on the target inside 85% of the radius (from the pipe center). That is the area on the target experiencing greater than average velocity. Any pits outside of this area will cause rejection of the target. A target with less than five unraised pits must be obtained to conclude that no additional cleaning will be accomplished by continuing the steam blowing process.

Section 6 – Unit Conditioning

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NOTE If this target exceed the pitting criteria, further steam blows must be performed to obtain the correct number of acceptable targets in the specified sequence. The targets, once removed for inspection are to be labeled with the target location, the number of the blow taken, date, time, and the inspectors' name and their conclusion. Various target bracing and securing techniques are to be approved by all of the responsible personnel. NOTE Turbine Manufacturers may have a recommended blowing procedure and target specification that may vary from the above guidelines. Turbine Manufacturers recommendations are to be STRICTLY adhered to. The above guidelines can be used if no recommendations are given by the Manufacturer. 6.1.7.

Safety and Environmental Precautions

Exhaust steam should be directed into a collection bin of substantial construction (able to withstand the rigors of a steam blow). It must allow the steam to vent up and any condensate to drain out the bottom. Installation of temporary elbows or stacks may be required. Ensure that all lines are adequately braced and supported. During initial warm-up of the piping (thermal cycle) inspect lines for any expansion restrictions and for possible leaks. Steam is not to be opened suddenly into a cool line. A bypass valve should be installed to slowly warm the line prior to blowing. All bleed valves should be opened to drain condensate from the line, reducing the incidence of water hammer. The target brackets are to be designed to withstand the force of the exhaust steam at sonic velocity. The steam exhaust area must be roped off and access restricted. be required in the affected area.

Hearing protection must

Temporary and uninsulated piping must be roped off and / or tagged. Results may be realized faster if the steam blows can be done prior to insulation being installed. This will allow faster cooling of the blown piping. This must be coordinated with construction. Section 6 – Unit Conditioning

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Steam silencers should be used at all times and locations, whenever possible. 60. Instruments All instrument elements should be checked against design data for correctness of location, connection, labeling, and range of measurement. Control valves should be tested for proper response to their control indices and for proper action on air failure. Alarm devices and automatic safety switches should be tested. As many instruments as possible should be checked while running-in equipment. A check should be made to determine that all orifice plates, venturis, pitot tubes, annubars, Coriolis, vortex shedding and other flow measuring devices are installed in their correct location. Check each orifice plate, venturi, annubar, and pitot tube for proper orientation installation. 61. Running-In Pumps New pumps should be given a preliminary run, circulating water or normal process fluid in order to test their mechanical performance and reveal any defects before attempting to start up the unit. This preliminary circulation serves also as a supplemental cleaning operation for the line and equipment involved in the flow path. Direction of rotation of electric motors must be checked before they are connected to the pumps. Over-speed trips on turbines are generally checked before they are connected to the pumps as well. The trip mechanisms should be set to shut off the steam supply at about 10% above normal speed. However, always refer to the turbine data sheets for specific over-speed trip settings. In preparation for starting a steam turbine driver, drain all condensate from the inlet steam, exhaust lines and turbine casing. If the turbine is non-condensing crack open the exhaust valve, and slowly warm up the driver with exhaust steam. Keep the turbine casing drains open to insure that all condensate is well drained. Throttle the casing drains and fully open the exhaust valve before setting the machine in motion. However, do not close the drains entirely until the turbine is running and the steam bleeding from the drains is dry. NOTE Establish vacuum on condensing turbines before setting machines in motion with inlet steam. This will insure that exhaust temperature will not be excessive, particularly for the initial run of the turbine. Before starting a centrifugal pump, it should be rotated by hand to ascertain that it turns freely. Section 6 – Unit Conditioning

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This is good practice always, but is especially important during the first few starts. If the pump feels tight, it should be dismantled and inspected for grit in the casing, excessive friction in the packing, or inadequate clearance in rotors or bearings. If the pump is rotating free, open its suction valve wide, vent the casing to ensure that it fills with liquid, and open the discharge valve slightly (open fully or open a recycle valve if the pump is a positive displacement type). The pump is then ready for starting assuming that its driver is also ready. Pumps handling certain fluids, particularly solutions containing dissolved solids which may precipitate, are normally provided with an external flushing media, usually water, to their mechanical seals or packing. When provided this flushing media must be established on pumps or hydraulic turbines prior to putting the machine in rotation. Once it has been put in rotation, a centrifugal pump must be quickly brought up to normal speed, or at least to a speed which develops substantial discharge pressure in order to provide internal lubrication for the rotor. This is achieved automatically with motor drive with the usual type of motor starting control. With turbine drive, the rate of acceleration depends upon the rapidity of opening the turbine steam valve. In either case, the pump discharge valve should remain in its initial throttled position until the pump is up to speed and full discharge pressure is established. The valve may then be opened gradually until the desired liquid flow is obtained or until an automatic valve assumes control. In the latter instance, the pump discharge valve is then opened wide. All pumps should be watched closely during preliminary circulation and particularly when first started. If bearings or packing begin to over-heat, usually this means hot to the touch, or other manifestations of trouble appear, shut the pump down for inspection. The fine screen of a strainer somewhat reduces effective suction line area. As solids collect on the screen, the open area is further restricted. Pumping rates must be limited accordingly to avoid loss of suction causing cavitation, but should be kept as high as possible for thoroughness of line flushing. A pump should be stopped after running for several hours or whenever it shows signs of losing suction for removal, inspection and cleaning of the strainer. After the strainer is cleaned and reinstalled, the pump is started, and the process is repeated until the screen remains clean, preferably until it shows clean on two successive inspections. At this time the fine mesh strainer screen is permanently removed. Time permitting, all centrifugal pumps should be run for a period of 6 or 8 hours. Operability of the metering pumps should be established. Standby pumps should be run in alternation with their counterparts. It will be found helpful to keep a record for each pump of running time, screen inspections and condition, and final removal of the fine screen.

Section 6 – Unit Conditioning

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Closed recirculation loops should be established with flow routed through normal channels, as far as possible, to obtain the maximum benefit of flushing. All vessels not completely filled should be vented to the atmosphere to prevent any possibility of damage by accidental establishment of a vacuum. The process system may be circulated section by section or all pumps may be broken-in simultaneously, as desired, utilities permitting. Operating personnel should be familiar with the literature furnished by pump and driver manufacturers and should follow any special instructions. 62. Calibrating Proportioning Pumps Breaking-in of proportioning pumps occurs simultaneously with the calibration exercise. The chemical injection pumps should be calibrated before being put in normal service. To do this, a temporary line should be run from each proportioning pump discharge bleed valve into a drum or any suitable container. A level of the material is pumped into the container in a given period of time and at a particular pump stroke setting. Pumping rates can be calculated against the measuring drum level. The gauge glass on the measuring drums is usually provided with a scale calibrated in millimeters or inches. Pumping rates should be checked at various pump stroke settings and recorded. This information will prove useful in actual operation when setting up chemical injection flow rates. The same rules apply to running in of these pumps as for the centrifugal as far as running for a few hours then stop to check the strainers, feel the pump to see if it is running hot, etc. 63. Steam Systems The import steam system must first be blown thoroughly clean before importing steam to the Ammonia Unit. See the steam line blowing description found earlier in this section. It may be necessary to remove selected end caps from main steam headers to achieve satisfactory cleaning of these lines. On replacing the end caps, the first weld pass should be inert gas (TIG or MIG) welded to prevent slag and shot formation inside of the line. The weld must then be 100% x-ray inspected for weld quality. It is not necessary to blow the lines at design pressures to achieve thorough cleaning. As a general rule, the lower the line pressures the higher the velocity. Calculations for each line need to be done as line pressure drop, equivalent line lengths, inlet and outlet pressures, blowing medium temperature and medium characteristics all play a part in the calculation. Steam blowing of all steam piping will be facilitated using import MP steam from the offsites MP boiler. Section 6 – Unit Conditioning

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After the medium and low pressure systems are clean, flow measuring elements should be installed and instrumentation put in service along with steam traps. It will be necessary to have the 141-D Steam Drum mechanically cleaned prior to other cleaning. The drum may also be rinsed with boiler feedwater to openings at the chemical cleaning nozzles on the 101-C downcomer and to the blowdown drum. Ensure the 101-C has been blinded at all nozzles before doing this. Chemical cleaning is normally done by a contractor specialized in this field. A procedure for chemical cleaning is given later in this section of this manual. Inspection of the 141-D Steam Drum will be necessary after chemical cleaning is finished. Then a wet or dry lay up of the steam generating system may be done depending on the plant requirements at the time. Nitrogen will be required for the steam system in either case. 64. Turbines And Compressors Detailed operating instructions for the compressors will be furnished by their manufacturers. Initial starting and break-in of the machines should be under the supervision of the manufacturer's representative, if possible. The lubricating oil consoles must be completely clean, the settings of alarm and shutdown switches associated with the oil and seal systems must be verified, and the operability of main, auxiliary, and emergency oil pumps should be established before any attempt is made to run the compressor turbines. Temporary oil filters are normally used for the lube oil flush as well as certain jumper lines and strainers in the system. After satisfactory completion of the lube oil flush, the system is drained, the reservoirs cleaned, and clean oil installed. The turbine is then ready for the over-speed trip checks. All steam turbines in the unit must be over-speed trip tested. Three trips at the design speed are required to establish repeatability. CAUTION When shutting down a turbine always maintain lube oil circulation with either the main or auxiliary lube oil pump at least until the turbine rolls to a complete stop. It is possible for the machine to roll for a considerable period of time and could result in damage if lube oil circulation is not continued during this coasting period. The turbine shaft conducts and convects heat to the bearings even after the unit is shutdown. The lube oil system must also be run long enough to prevent the bearings from being overheated. Some compressors may be coupled to the driver and be run in on air, with the suction and discharge open. A closed loop on air tends to be hazardous and should be avoided. Running in Section 6 – Unit Conditioning

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a compressor in this fashion may require establishing an external reference pressure on the seal gas / oil systems. Running the synthesis gas or refrigeration compressors on air requires close attention to the compressor loads and discharge temperatures. Since air is much denser (heavier) than either synthesis gas or ammonia, more load is put on the machine at a lower speed and the discharge temperatures for each stage increase proportionally. The manufacturer's representative will normally be familiar with these temporary expedients, if required, and his written approval must be obtained prior to running the compressor on any gas other than that for which it was designed. Inspect the cooling water and auxiliary systems frequently during these initial operations. Check the operation of control instruments, alarms, and shutdown devices. 65. Refractory Dryout Prior to being placed in normal service, the refractory lining in any new furnace, or any furnace having undergone major refractory or lining repairs, must first be cured, and artificially dried out under controlled conditions, to remove the water or moisture contained in the refractory mortar or castable, remaining from the original mix and / or from a moist curing operation. Controlled refractory dryout is employed to prevent the sudden explosive release of water at elevated temperatures, which would spall or crumble the refractory material. This procedure applies to all types of refinery or chemical plant furnaces or auxiliary boilers, containing any of the three basic type refractory materials: 1. brick 2. castable 3. plastic. It must be noted that this procedure is applicable only when one of the basic refractories is installed and not to be used in the dryout of exotic or specially prepared refractory materials; for example, mizzou tile, at which time special dryout procedures shall be incorporated. Before starting the dryout, a thorough inspection should be made of the interior of the furnace, radiant and convection areas, to assure the completeness of the refractory installation and also the cleanliness of the interior. Debris left in the furnace such as wooden planks, scaffolding, etc., could not only interfere with the normal flow of flue gases, but inflammable debris will ignite and cause localized overheating of the refractory. Thermocouples, which are to monitor the temperatures during dryout, should be checked for Section 6 – Unit Conditioning

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proper location and operability. In some cases, it will be necessary to install temporary thermocouples if the normal couples are situated too far away from critical refractory areas. For example, it is not uncommon for the normal flue gas thermocouple temperature points to start in the convection section. During dryout radiant box temperatures are critical. TI-1317A through TI-1317E will be used for 101-B radiant box refractory dryout. Before final closing of the furnace in preparation for dryout, alignment and the mechanical condition of all burners should have been checked. Fan damper operations should have been verified correct from inside the furnace. For the purpose of this procedure, it is assumed that all fuel gas, oil, and steam piping, associated instrumentation, fans, and pumps have been properly commissioned, purged, blinds removed, and the fuel is available up to the furnace main fuel isolation valves. Since the initial temperatures of the furnace during dryout will not exceed 250°C, it will not be necessary to have any fluid or gas flow through the furnace radiant or convection tubes throughout the dryout period. During the dryout, burners should always be fired in a symmetrical, evenly spaced pattern. The pattern should insure uniform distribution of heat throughout the box. Where possible, burners directly adjacent to the walls should not be fired until the last 24-hour period of the dryout. Burner firing should be alternated every four hours during dryout to check the operability of all the burners, recognizing that even distribution of heat must always be adhered to. Burner flames must be adjusted so that there is no direct flame impingement on furnace tubes or refractory. If flame impingement occurs, the burner fuel must be reduced or taken out of service and the fault corrected, whether it be burner alignment, dirty tips, etc. During the dryout, it is desirable to have a large movement of air through the furnace with which to carry away the evaporated moisture being removed from the refractory. Peephole doors, registers on burners not in service, etc., should be open to admit the air. New refractory must be allowed to cure at ambient conditions for a minimum of 48 hours, but preferably for 72 hours, before the start of artificial drying. 6.1.8.

Dryout of the 101-B, Primary Reformer

The main steps of drying out 101-B are as follows: 1. Start the induced draft fan and forced draft fan and establish a nominal low draft at burners. 2. Purge the firebox for 10 to 20 minutes prior to lighting any burners. The newer design burner management systems will not allow the burners to be lit until a timed purge has been Section 6 – Unit Conditioning

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completed. 3. Light a few small fires and bring the radiant box temperature to 120°C at a rate of 15°C per hour. Hold the temperature at 120°C to the completion of the first 24-hour period, from initial light off, about 16 hours, or a minimum of 1 hour per inch thickness of the refractory, after achieving 120°C or as recommended by the refractory supplier. KBR’s recommendations are typical and the final decision should be as per the refractory supplier. 4. After the first 24-hour period, start increasing firing to raise the radiant box temperature at a rate of 15°C per hour to 250°C. 5. After reaching 250°C, hold the radiant box at these conditions for 16 hours, or a minimum of 1 hour per inch thickness of the refractory or 8 hours as previously mentioned. 6. At the completion of this portion of the drying period, start lowering radiant box temperature at28°C per hour to about 120°C, then extinguish the fires. Box in the furnace by shutting down the fans, closing all open registers and peep doors, and allow the furnace to cool gradually. CAUTION This may not be the completion of the reformer dryout. An additional increase from 250°C to a higher temperature according to the manufacturer’s instructions may need to be done with a hold for a minimum number of hours. This step, if required, will be accomplished during start-up of the reformer once process has been introduced into the coils so that they can be maintained within their temperature constraints. Refer to the refractory vendor’s specific dryout instructions and follow them. 7. When furnace is cool enough to enter, fuel lines should be blinded, fans locked out and tagged, the furnace entered, and a thorough inspection made of all dried refractory to assure that no major cracks or spalling of the refractory occurred during dryout. Any repairs made to the refractory must also be dried out to prevent spalling but this can be done locally at the repair if the area is small.

6.1.9.

Dryout of the 102-B, Start-Up Heater

The main steps of drying out 101-B are as follows: 1. Purge the firebox for 10 to 20 minutes prior to lighting any burners. This can be accomplished by opening all of the peep doors, all of the burner registers and fully open the stack damper. Section 6 – Unit Conditioning

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LP steam can also be introduced as a purge medium, if desired, but this may not be desirable due to the potential damage to the refractory because of steam condensate formation. Confirm by use of a portable combustion gas meter or lab analysis that the box has been adequately purged free of explosive gases 2. Since the initial temperatures of the furnace during dryout will not exceed 250°C, it will not be necessary to have any gas flow through the furnace coils throughout the dryout period. 3. Light the burner pilots one-by-one and bring the radiant box temperature to 120°C at a rate of 15°C per hour. If all 8 pilots are lit and the temperature does not reach 120°C, then light small flames on burners 1, 3, 5 and 7 one-by-one being sure to maintain the 15°C per hour temperature increase. 4. Hold the temperature at 120°C to the completion of the first 24-hour period, from initial light off, about 16 hours, or a minimum of 1 hour per inch thickness of the refractory, after achieving 120°C or as per KBR’s Standard minimum hold time of 8 hours or as recommended by the refractory supplier. KBR’s recommendations are typical and the final decision should be as per the refractory supplier. 5. After the 120°C hold period, start increasing firing to raise the radiant box temperature at a rate of 15°C per hour to 250°C. It will be better to have more evenly-spaced burners with small flames, if required, rather than 3 with larger flames. 6. After reaching 250°C, hold the radiant box at these conditions for 16 hours, or a minimum of 1 hour per inch thickness of the refractory or 5 hours based on refractory thickness but KBR’s Standards have a minimum hold time of 8 hours as previously mentioned. CAUTION This may not be the completion of the heater dryout. An additional increase at 28°C/h from 250°C to a higher temperature may need to be done according to the manufacturer’s instructions with a hold for a minimum number of hours. This step will be accomplished during start-up of the heater once process has been introduced into the coils so that they can be maintained within their temperature constraints. Refer to the refractory vendor’s specific dryout instructions and follow them. 7. At the completion of the drying period, decrease the temperature at 28°C per hour to about 120°C, then extinguish the fires. Box in the heater by closing the stack damper, all open registers and peep doors, and allow the furnace to cool gradually. When heater is cool enough to enter, fuel lines should be blinded, the furnace entered, and a thorough inspection made of all dried refractory to assure that no major cracks or spalling of the refractory occurred

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during dryout. Any repairs made to the refractory must also be dried out to prevent spalling but this can be done locally at the repair if the area is small.

See the chart on the following page showing one refractory vendor’s dryout curve for both 101-B and 102-B. PT PUSRI should develop and utilize a similar chart based on the selected refractory vendor’s dryout procedures.

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103-D Secondary Reformer Dryout

Please refer to 103-D Secondary Reformer Dryout Procedure (Doc. No. P2B-10-00-PE-0008-R) 66. OASE System Preparation It is very important that the OASE System be properly prepared for operation by carrying out a

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degreasing and descaling program. The objective is to remove oil, grease, mill scale, rust, or other contaminants from the system that contribute to foaming of the OASE solution. Mill scale in piping and towers, formed during the manufacturing and construction phases, is potentially one of the greatest sources of sludge formation and iron that can contribute to foaming problems when the system is placed in operation. Foaming in a CO2 removal system can result in inadequate removal of CO2, pump damage, exchanger damage, and tower internal damage. Experience has shown that a careful cleaning of OASE systems is not only indicated as good operating practice, but is mandatory to minimize foaming of the solution and delays in the initial start-up. The time used in properly cleaning the OASE systems pays large dividends later on when process gas is admitted to the system for removal of CO2. Therefore, special effort should be made to have the system as clean as possible before start-up. During the water wash circulation steps, instrument flushes, seal flushes, control valve, and instrument operation should be checked and adjusted as required for correct operation. The following procedures are recommended to produce as clean a system as possible. This includes the construction phase and initial circulation. 6.1.11.

Mechanical Cleaning and Inspection

The initial step in the cleaning program will start with the water flushing of the equipment, either with the addition of demineralized water or water remaining from hydrostatic testing, if the quality is acceptable, to remove the debris accumulated during construction. The internals of the towers, exchangers, and tanks should be carefully examined for rust and scale. Rust or scale should be as completely removed as possible by wire brushing, scraping, or mechanical removal. At this time, the internals should be checked, using the vessel drawings, to verify that the packing, supports, flash galleys, chimneys, bubble caps, trays, weirs, nozzle locations, demisting pads, reboiler traps, and sparger sizes and their locations conform to the specifications on the drawings. The entire system must be checked to see that all necessary insulation has been completed. After the system has been mechanically cleaned and internal inspection has been completed, loading of the packing rings into packed towers can be started. The filter elements should be installed in the filters 104-L and 115-L. All pump strainers should be checked for installation and fine screen covering, turbine over-speed trips complete, directional rotation of pump motors determined correct, operation of

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all remote-controlled actuators and control valves verified, remove all orifice plates and confirm operation of all equipment activated by the safety shutdown systems (simulate shutdown conditions). The OASE Solution Storage Tank, 114-F, and antifoam injection system, 109-L, must receive the same careful inspection and mechanical cleaning as the absorber and stripper.When all of this work has been completed, the water wash of the system can commence. At this time, an operator leak test and nitrogen purge should be performed on the Absorber, 121-D, and the process gas path up to the Methanator, 106-D, inlet valving. Install a temporary blind in the Methanator, 106-D, inlet nozzle flange or nearest available upstream flange. Using nitrogen, pressure the absorber, absorber overhead line, absorber knockout drum, 142-D2, up to the blind at 106-D inlet including the tube side of 114-C, the shell side of 172-C, the 114-C bypass line, and the 106-D inlet line if applicable. A pressure test of 2 about 10 kg/cm should reveal any leaks in the system. With a successful leak test performed, nitrogen purge the system to get 0.5% O2 or less. The temporary blind at methanator inlet should remain in place until the process is ready for commissioning. 6.1.12.

Initial Circulation and Degreasing

Initial circulation will require: • Electric power for 110-JM / JAM, 111-JM, 115-JM, 117-JM / JAM, 107-JCM and 108-JAM • LP steam • Demineralized water or steam condensate for establishing an inventory in the OASE system. 6.1.13.

Water Washing (Cool Water)

Demineralized water or steam condensate is to be circulated through the system for removal of rust, scale, and dirt. NOTE When water first enters a piece of equipment from the top and before levels are established, the washing action of the falling water tends to carry loose scale, rust, and dirt with it to the low points of the equipment. At this time the low point drains should be open until the drains run clear. Establish a level in 153-D using demineralized water through FV-1013. Ready the 110-J pumps for operation to provide seal flushing water to the semi-lean solution circulation pumps 107-Js and 117-Js. Water flush the 153-D and the 122-D1 using demineralized water. Circulate to 153Section 6 – Unit Conditioning

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D through the minimum flow lines of the 110-Js. Drain, refill and clean 110-J suction strainers as required until 153-D is clean. Flush to and through 122-D1 under control of FIC-1016 until the piping and vessel are clean. Draining of the dirty water can be done by removing the suction strainers of 117-Js and 107-Js. This will have to be done in a batch process refilling 153-D as the level becomes low. Flushing the lines to the seal flush systems, 163-D and 121-D can also be accomplished at this time being sure to maintain the level in 153-D. Once they are flushed clean, isolate all other 110-Js flow paths until required for start-up to 163-D, 121-D, and 122-D1. Start a 110-J pump and open XV-1117 by activating HS-1117A in the DCS to provide seal flushing water to 107-J and 117-J pumps. Levels can be established in the OASE system in a number of ways. Temporary hoses can be used if normal systems are not yet ready for operation. If the demineralized water system is in service and has been flushed, a level can be established in the bottom of 122-D1 using the 3” demineralized water line around. A level can then be established in the 122-D2 by unblocking the 117-J / JA pump and opening FV-1017. Start and run 117-J / JA to bring the level up in 122-D2. Be sure that the level in 122-D1 does not go too low. With a level in the stripper established on LIC-1042, commission one of the Lean Solution pumps, 108-J and start transfer of water to the absorber. The flow rate will be controlled using FIC-1014. If not previously accomplished, the CO2 Absorber, 121-D, can now be pressured with nitrogen to a pressure high enough to cause transfer of water from the bottom of the absorber to the 2 stripper. The pressure is expected to be about 5 - 7 kg/cm . Transfer of water from the absorber to the stripper should be through control valve LV-1004B on manual control. Later, when normal operating levels are accomplished throughout the system, additional circulation will be done initially using the 107-JC with near full circulation using 107-JB and JC pumps. 163-D will also have to be pressurized with nitrogen to force the water / solution levels up to 122-D1. This pressure must be less than the 121-D absorber pressure in order for flow to be maintained from 121-D. Continue adding make-up water and establish normal levels in both stripper sections. As levels reach normal values, start 117-J or JA, semi-lean circulating pump, pumping through the semi-lean system using FIC-1017 for control to 122-D2 and through 104-L back to 122-D1. With the lean flow path and tower levels stable, start 107-JC, semi-lean solution pump, to 121-D with flow controlled by FIC-1005. Section 6 – Unit Conditioning

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As normal operating levels are established, circulation will be established in the system through the normal flow paths which will also include using 108-JA pump and FIC-1014 to 121-D. Filters and strainers should be placed in service, checked frequently, and cleaned as necessary. The line from 110-Js through FIC-1018 can also be flushed to wash the top section of the absorber. The cool, circulating water should be continually filtered and changed as often as necessary to assure that relatively clean water is flowing through the system. Check the pumps for signs of reduced pumping rates, which usually indicate suction strainer plugging. Switch the pumps and clean suction strainers as required. Circulation should be continued until the cool circulating water remains clear. Check 104-L differential pressures often and clean the filter element as required. 6.1.14.

Water Washing (Hot Water)

When inspection shows the cool circulating water continues to be clear, the water should be heated to 70°C maximum. This can be accomplished by admitting LP steam to the CO2 Stripper, 122-D2, in the return solution line from, the CO2 Stripper Reboiler, 105-C, using the LP steam to the start-up connections provided. Raise and lower the tower section levels in each tower during each wash cycle by adjusting the level controllers to assure cleaning of the storage section walls. When the water wash is complete, the hot water should be drained from the system and preparations made for the flushing with 3% potash (potassium carbonate) solution. 6.1.15.

Flushing with 3% Potash (Potassium Carbonate) Solution

Prepare the solution from condensate or demineralized water and potash (K2CO3). The pH value of the 3% solution is about 12. Ensure that the chloride content is < 100 ppm. NOTE Instead of potassium carbonate, tri-sodium-phosphate or sodium hydroxide can be used. The pH value is higher in these cases (13 and 14, 0 respectively). Therefore, the recommended maximum temperature of 70 C must not be exceeded in order to prevent corrosion damage of the equipment. Circulate the solution through the system for about 8 hours at a temperature of 50 to 70°C using the solvent circulation pumps as indicated for the water washing. As soon as steady conditions are achieved, check the circulation rate by means of the FIC valve positions. Simultaneously, the Section 6 – Unit Conditioning

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level indicators are to be checked. Raise and lower the tower section levels in each tower during each flush cycle by adjusting the level controllers to assure cleaning of the storage section walls. Empty the entire system. Take liquid samples. Remove and clean the filters and screens in the pump suction lines. NOTE The operator foam test permits the operator to make a quick check on the system during cleaning and in normal operation. Before acting on the results of an "operator foam test", the laboratory should be requested to perform standardized "Lab Foam Test" to confirm the operator's findings. In case the 3% potash solution has to be neutralized prior to disposal, the neutralization must be carried out outside the CO2 removal unit. Never neutralize the solution within the system. NOTE Confirm with all governmental authorities on the proper method for the disposal of the 3% potash solution or neutralized solution.

6.1.16.

First Condensate / Demineralized Water Flush

This flush is carried out as described in the flushing with 3% potash solution section above. The water is initially heated to about 70 °C and the system is flushed for about 5 hours at the full flow rate. To achieve this rate, two 107-J pumps will have to be placed in service. Take a liquid sample of the water used for flushing and add about the same volume of OASE to the sample. Check this diluted amine solution for foaming tendency (see analytical procedures for the "Activated OASE" in the Process Lab Manual). Check the pH of the solution. The pH value should be < 9. A higher pH value indicates too high a potassium carbonate content remaining in the system. Drain the water and remove and clean filters and screens in the pump suction lines. If the flushing water is clean and the foaming tendency is low (foam volume < 300 ml and collapse time < 20 seconds), the second condensate / demineralized water flush can be omitted. Reinstall orifice plates if second flush is not being done otherwise wait until after the second Section 6 – Unit Conditioning

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flush is completed. 6.1.17.

Second Condensate / Demineralized Water Flush

This flush is carried out as described for the first condensate / demineralized water flush. Circulate the water through the system for about 6 hours at the maximum flow rate possible using two 107-J pumps, if possible, and simultaneously raise the temperature to the operating temperature. Add Natural Gas to the absorber for higher pressure and increasing the nitrogen pressure in the HP flash vessel will have to be used to attain the desired flow rates that are at or near design levels. Take a liquid sample of the water used for flushing and add about the same volume of OASE to the sample. Check this diluted amine solution for foaming tendency (see analytical procedures for the "Activated OASE" in the process lab manual). If foaming tendency exceeds guidelines, repeat flushing with 3% potash solution, followed by condensate / demineralized water flushes according to instructions previously used. Check pH of the solution. The pH value should be < 9. A higher pH value indicates too high potassium carbonate content remaining in the system. Check the distributors of the columns and the suction strainers for dirt. If the flush water is clean and the foaming tendency is low (foam volume < 300 ml and collapse time < 20 seconds), the OASE can be charged. Otherwise, flushing with 3% potash and / or the demineralized water flush must be repeated. After the final water flush, the content of particles in the wash water should be small. As a rule of thumb, the solids content can be judged as follows: •

< 10 ppm (w.) solids: excellent

•

< 50 ppm (w.) solids: good

•

< 100 ppm (w.) solids: acceptable

A higher content of solids usually leads to an excessive foaming tendency. In this case, a further flushing is required. Once the system is determined to be clean, OASE solution can be prepared and the system filled to prepare for normal operation. See Section 8 of this manual. 67. Flush Cooling Water Systems Generally, the cooling water flushing will follow the same guidelines as other flushing or blowing procedures. Due to the line size and configuration at exchangers or the cooling tower some variations may be in order.

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After system inspection and mechanical cleaning of the cooling tower basin, fill the basin to a high level. Flushing will be done using alternate cooling water pumps one at a time on an intermittent basis. NOTE The large electric motors in the unit have a limited number of starts allowed in any given time period. Typically, this limit is two starts per hour. The vendor information or electrical department should be consulted for verification on any given motor. Often with the cooling water system, it is more practical to remove the head from the large first in-line exchangers and cover the tubes than to attempt to open or spread and blind at the inlet side. After flushing to large openings at various points of the system, water circulation can be initiated. The secondary or smaller lines may now be flushed to their users, and then incorporated into the circulation. It will likely be necessary to drain and clean the cooling tower basin one or more times during the circulation period. Open and inspect, or clean, the water inlet channel heads of the refrigeration condensers, surface condenser, and as many other exchangers as possible, particularly those furthest from the supply. After the system is clean, refill with fresh water, establish circulation and chemical treatment program levels in keeping with the vendor’s recommendations. 68. Process Line Blowing Air blowing of process lines, catalyst dusting and the run in of the Process Air Compressor, 101-J, will normally take place in the same operation. Temporary piping will be required for some of the process line blowing. Commission and test the air compressor in accordance with the vendor’s instructions. After starting 101-J under the vendor’s supervision, the process line blowing may be carried out at a discharge pressure that avoids excess heat of compression, but develops sufficient air flow for good blowing velocity. With temporary piping and valving, line blowing can be carried out alternately to the front end, the synthesis loop and the refrigeration system. Field procedures will be written to establish the order of blowing and preferred methods.

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Line blowing to catalyst vessels where the piping is all welded can be done by installing a weighted tarp over the catalyst bed and the manway open the tarp with any debris is removed and the manway closed before proceeding to the next step. 69. Leak Test Unit Leak test of the unit is conducted before start-up to ensure that valving is properly aligned and flanges are made up tightly. The intent is to eliminate major over sights. In some cases leak testing is combined with nitrogen purging. Leak testing is usually done in sections, such as desulfurization, reformers, and shift converters, CO2 removal, methanator to 103-J, refrigeration, and synthesis loop. Flanges should be carefully checked for leakage, bleed and drain valves for closure, and manways checked. Applying tape over flanges and providing a small hole to check with a soap 2 solution is proven method for checking flanges and manway covers. Normally 5.0 to 7.0 kg/cm pressure is used for leak testing. After all leaks have been repaired, the unit should be purged with nitrogen to an oxygen content of 0.5% or less. The Low Temperature Shift Converter, 104-D2, should now be blinded in preparation for catalyst reduction. The Low Temperature Shift Converter, 104-D2, the Methanator, 106-D, and the Ammonia Converter, 105-D, should now be oxygen free, under 0.5% O2, and under a positive nitrogen pressure. The refrigeration system, after nitrogen purging, can be left under a pressure of about 3.5 2 kg/cm , to be displaced with ammonia vapor during the filling of the Refrigerant Receiver, 149-D.

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Health Hazards of Anhydrous Ammonia It is not practical to consider all of the events or situations, which could result in a massive spillage of anhydrous ammonia and / or the release of a high concentration of ammonia vapors. The strict adherence to the established safety procedures relating to the safe handling of liquid ammonia will minimize the possibility of a spill occurring. All personnel must be aware of the hazard of contact with liquid ammonia or inhalation of ammonia vapor. Protective equipment should always be immediately available for use in the ammonia transfer and storage area. Anhydrous ammonia is a strong irritating chemical to the skin, eyes and respiratory tract. The liquid produces severe burns. The gas has a characteristic sharp penetrating odor. In sufficient concentrations, it produces painful irritation. Because of the unpleasant odor and prompt irritation, it is unlikely that anyone would remain in an atmosphere seriously contaminated with ammonia. However, serious injury may result if escape is not possible. Inhalation of high concentrations produces violent coughing due to its local action on the respiratory tract. If rapid escape is not possible, severe lung irritation, pulmonary edema and death can result. Lower concentrations may cause eye irritation, laryngitis, and bronchitis. Exposure to high gas concentrations may cause temporary blindness and severe eye damage. Direct contact of the eyes with liquid anhydrous ammonia will produce serious eye burns. Liquid anhydrous ammonia produces skin burns on contact. Chronic irritation to the eyes, nose and upper respiratory tract may result from repeated exposure to the vapors. A threshold limit value of 25 ppm in air has been set as the maximum concentration that personnel may be exposed to repeatedly without adverse effect. Personnel will be instructed and supervised in the proper methods of handling anhydrous ammonia in order to prevent direct contact with the liquid and exposure to the vapor. Emergency showers and eye wash fountains are provided in convenient locations wherever anhydrous ammonia is handled in quantity. All personnel should understand that direct contact with the chemical requires the instant application of large amounts of water to the affected area.

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70. Ammonia Concentration Limits And Effects

Vapor Concentration

General Effect

Exposure Period

First perceptible odor.

Prolonged repeated exposure produces no injury.

35 ppm

Slight eye irritation.

Short term exposure limit 15 minutes or less.

100 ppm

Noticeable irritation of eyes and nasal passages.

No permissible exposure. Infrequent (1 hour) exposures ordinarily produce no serious effect.

400-700 ppm

Nose and throat irritation. Eye irritation with tearing.

Prolonged exposure may produce severe scarring of exposed eye tissue and damage to the mucous tissue of the lungs.

2000-3000 ppm

Convulsive coughing. Severe eye irritation. Skin burned and blistered.

May be fatal after short exposure.

5000-10,000 ppm

Respiratory spasm. Rapid asphyxia.

Rapidly fatal.

20-25 ppm

Under normal conditions of temperature and pressure, anhydrous ammonia is stable, but ammonia is capable of forming flammable mixtures with air within 16% to 28% by volume. Personnel should be diligently instructed in the proper methods of handling anhydrous ammonia. Proper supervision must be used to prevent accidental contact with liquid or exposure to gas. All personnel should be instructed in the proper use of personal protection equipment and be made aware of the locations where such equipment is located. Personnel should be made aware of conditions, which are sufficiently hazardous to require protective equipment. When working in hazardous locations where exposure to ammonia is likely, the use of protective equipment is mandatory. The use and selection of the type of equipment must be properly supervised. Section 6 – Unit Conditioning

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71. Chemical Cleaning Of The Steam Systems 6.1.18.

Purpose Of Chemical Cleaning and Passivation

The following description covers general overview of chemical cleaning and passivation programme. Detailed procedure shall be developed and might be slightly differ from this overview. Internal surfaces of steam generators and boiler feed water pipe work are cleaned to remove contaminants such as mill scale, corrosion products, weld scale, oil, grease, sand, dirt, temporary protective coatings, and other construction debris that may impair heat transfer and ultimately cause tube failure. 6.1.19.

Chemical Cleaning and Passivation Program Chemistry

A number of chemical cleaning and passivation program chemistries exist. To minimize the risk of damaging vessels and pipe work exposed to the cleaning solutions it is preferable to utilize an organic acid as against an inorganic acid based cleaning program. There are two basic methods of cleaning: • Circulating cleaning solution • Static cleaning solution (also known as fill and soak) Normally the circulation solution method is used. In situations where it is not possible to configure a circulation loop then the static cleaning solution method may be used. The guideline below describes a circulating cleaning solution method which utilizes an Inhibited Ammoniated Citric Acid solution as the cleaning agent in the acid cleaning step. 6.1.20.

Items To Be Chemically Cleaned and Passivated

Listed below are those vessels and pipe work that should be chemically cleaned and passivated prior to being placed into operation. Essentially the systems to be chemically cleaned include the BFW and HP steam piping

Section 6 – Unit Conditioning

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System to be Vessel to be Pipe Work to be Chemically Cleaned Chemically Cleaned Chemically Cleaned and Passivated and Passivated and Passivated Boiler Feed Water System

High Pressure Steam System

BFW2017-2" BFW1006-10" BFW1040-8" BFW5003-6" BFW1004-10" BFW1005-8" BFW1007-12" BFW1062-8" BFW1009-14" BFW1037-10" BFW2018-6" BFW1043-1.5" BFW1019-6" BFW1020-6" BFW1022-3" BFW1056-3" BFW1001-16" BFW1036-6” BFW1051-6” BFW1008-16" BFW1043-0.75" BFW1080-0.75" BFW1082-2" BFW1083-2" BFW2017-2" BFW5002-12" HS1001-18" HS1002-18" HS1172-3" HS1001-18" HS1172-3" HS1002-18" HS1003-24" HS1004-14" HS1008-20" HS1103-20" HS1105-16" HS1180-12" Section 6 – Unit Conditioning

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PI&D PID-62-D105 PID-62-D108 PID-62-D108 PID-62-D108 PID-62-D109 PID-62-D109 PID-62-D109 PID-62-D109 PID-62-D114 PID-62-D114 PID-62-D114 PID-62-D128 PID-64-D101 PID-64-D101 PID-64-D102 PID-64-D102 PID-64-D106 PID-64-D106 PID-64-D106 PID-64-D106A PID-64-D106A PID-64-D106A PID-64-D106A PID-64-D106A PID-64-D106A PID-64-D106A PID-62-D107 PID-62-D107 PID-62-D111 PID-64-D101 PID-64-D101 PID-64-D102 PID-64-D102 PID-64-D102 PID-64-D102 PID-64-D102 PID-64-D102 PID-64-D107

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System to be Vessel to be Pipe Work to be Chemically Cleaned Chemically Cleaned Chemically Cleaned and Passivated and Passivated and Passivated HS1181-3"

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PI&D PID-64-D107

Equipment* 101-C Risers 101-C Downcomers 102-C 103-Cs 123-Cs 141-D 101-U 101-BCS1 101-BCS2 *SS Equipment do not specifically require Chemical cleaning. Such equipment would require to be isolated and a jump over provided to complete the chemical cleaning circulation loop . Warning It is important that no blowdown water goes backwards into the 141-D / 101C blowdown lines. Ensure the cleaning fluids are NOT drained from the 141-D / 101-C blowdown lines to the 186-D – they must be disposed of in an acceptable manner. 6.1.21. •

  

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Safety Health and Environmental Requirements

Potential hazards associated with chemical cleaning include: o Chemical burns o Thermal burns o Exposure to atmospheres containing less than 19.5% v/v oxygen) Material Safety Data Sheets (MSDS) for all the chemicals used in the chemical cleaning and passivation program should be available to and reviewed with all involved parties. Chemical cleaning and passivation activities involve the use of nitrogen. All involved parties should be trained in the risks associated with nitrogen and the entry to confined spaces. Appropriate programs should be in place to ensure no party inadvertently enters a confined space in which the atmosphere contains less than 19.5% v/v oxygen. All involved parties should be provided with, trained in the use of, and use the personnel protective equipment defined within the relevant Material Safety Data Sheets when handling the chemicals and cleaning solutions used in the chemical cleaning and passivation program. As a number of the chemicals and cleaning solutions utilized in the chemical cleaning and

Section 6 – Unit Conditioning

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passivation program are corrosive. Safety shower and eyewash stations should be provided at strategic locations within the area where chemical cleaning and passivation activities are being conducted. Temporary signage indicating the hazards present and the personnel protective equipment/permitting requirements should be placed around the perimeter of the area in which the chemical cleaning and passivation activities are being conducted. General access to the areas in which chemical cleaning and passivation activities are being conducted should be restricted by placing temporary barricading around the perimeter of each area. Hydrogen may be formed during the chemical cleaning and passivation program. The areas in which chemical cleaning and passivation activities are being conducted should be assigned temporarily with the appropriate electrical classification and the appropriate “Hot Work Permitting” requirements should be observed (note: to prevent the possible creation of an explosive mixture within temporary chemical circulation and mix tanks air agitation should not be used to mix the contents of said tanks). All vents and overflows should be routed to safe locations away from possible contact with any personnel. All temporary pipe work, pipe fittings, hoses, and equipment utilized during the chemical cleaning and passivation program should be selected/designed to be compatible with the chemicals, temperature, and pressures they will be exposed to during the chemical cleaning and passivation program. It is the responsibility of the party conducting the chemical cleaning and passivation activities to ensure that all waste materials generated are disposed of in accordance with all the host plant site and country environmental regulations. Prior to the use of any cleaning chemicals the appropriate spill: o containment devices o clean up kits/materials should be available on site.

6.1.22.  

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Construction Pre-requisites

During vessel fabrication attention should have been given to cleanliness. During pipe work fabrication and installation attention should have been given to cleanliness. Adoption of a construction “Clean Build” program for pipe work will reduce the time taken to complete any pre-operational cleaning activities. Hydro testing of all vessels and pipe work to be chemically cleaned and passivated should be complete and documented. The insulation of all vessels that are to be chemically cleaned and passivated should be 100% complete. Personnel protection insulation on vessels and pipe work that are to be chemically cleaned and passivated should be 100% complete. Section 6 – Unit Conditioning

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Engineering Pre-requisites

The EPC Contractor should develop for each cleaning circuit a single schematic drawing on which is shown the layout of all the components of the particular cleaning circuit in question. The EPC Contractor should verify that support systems and structures supporting pipe work and equipment that is to be chemically cleaned and passivated has been designed to withstand the imposed load resulting from pipe work and equipment being liquid full. The EPC Contractor should verify the compatibility of the metallurgy of each wetted component with each cleaning solution used during the chemical cleaning and passivation program.

6.1.24. 

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Heat conservation insulation on pipe work that is to be chemically cleaned and passivated should be 70% complete

6.1.23. 

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Preparations For Chemical Cleaning and Passivation

It is recommended that a Specialist Chemical Cleaning Contractor is engaged to conduct all Chemical Cleaning and Passivation activities. The Specialist Chemical Cleaning Contractor should prepare and present for approval a detailed chemical cleaning and passivation procedure for each item of equipment or group of items which are to be cleaned and passivated. Such procedures should be based upon the KBR Chemical Cleaning and Passivation Guideline. Detailed cleaning and passivation procedures prepared by the Specialist Chemical Cleaning Contractor should include: o A listing of the items of equipment and pipe work which will comprise that particular chemical cleaning and passivation circuit. o A highlighted set of the relevant P&ID’s, piping isometrics, and cleaning circuit schematic drawing on which is indicated the particular chemical cleaning circuit in question and also the:  Location of temporary chemical cleaning circulation pumps, tanks, heat exchangers, etc  Location of temporary pipe work and hoses required to facilitate the cleaning circuit in question  Valve line up required to direct the cleaning fluids to the various sections of the cleaning circuit in question  The status of all permanently installed pipe fittings and instruments  Location of high point vents  The location of the bottom and low point drains  The location of cleaning solution sample points  The locations of slip blinds, blind flanges, etc. Section 6 – Unit Conditioning

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A written procedure in which each step of the cleaning program for the cleaning circuit in question is described in detailed (including for each step the cleaning solution chemical composition, pH, temperature, etc). The material data safety sheet, specification, and quantity of each chemical to be used in the cleaning program for the cleaning circuit in question. The utility (demineralized water, steam, nitrogen, electricity, etc) requirements for cleaning circuit in question. Detailed analytical procedures to be used. Cleaning solution sampling locations and the frequency at which samples will be drawn and analyzed. Sample log sheet which will be used to record data collected and measurements made during the cleaning program for the cleaning circuit in question. An estimate of the quantity, composition, and disposal method for each type of waste generated by the cleaning program in question.

Prior to the implementation of each detailed cleaning and passivation procedure the Specialist Cleaning Contractor should present such procedures to the EPC Contractor for review and approval.  Where the Specialist Chemical Cleaning Contractor proposes to use an equal to the chemicals defined in the KBR Chemical Cleaning and Passivation Guideline the Specialist Chemical Cleaning Contractor is responsible to obtain and present to the EPC Contractor documentation from the relevant chemical supplier that demonstrates that the proposed alternative is indeed equal to that defined within the KBR Chemical Cleaning and Passivation Guideline. The EPC Contractor should review and approve/disapprove the use of any proposed equal.  Typically the Specialist Chemical Cleaning Contractor is responsible for supplying temporary equipment such as: o Circulation pump(s) o Circulation tank (with a facility to install a 50 mesh screen at the point where the recirculating cleaning fluid enters the tank) o Heat exchanger (or heating coil in circulation tank) o Chemical mix tank o Chemical hoses o Pipe work o Pipe fittings (such as clip blinds, blind flanges, screens, strainers etc) For use during the chemical cleaning and passivation program. 

Status of permanently installed pipe fittings & instrumentation during the chemical cleaning and passivation program: o Flanged control & shut down valves removed and replaced with a line sized Section 6 – Unit Conditioning

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temporary pipe spool o Welded control & shutdown valves internals removed and valve body sealed with a temporary cover plate o Orifice and restriction plates removed and mating flanges bolted together o Desuperheater spray nozzles removed o Check valve internals removed o Strainer internals removed o Steam traps removed o Flanged pressure relief valves removed o Welded pressure relief valves the internals removed and temporary plugs/gags (supplied by valve vendor) installed in the valve body o Steam drum sight glasses should either be isolated or if required to be in service during the implementation of the cleaning and passivation procedure they should be replaced with temporary sight glasses. o All instrumentation should either be isolated or removed. Machinery should not be exposed to chemical cleaning and passivation solutions at any time. Machinery should be positively isolated from chemical cleaning and passivation fluids by either: o Physical disconnection of pipe work and the installation of blind flanges at all appropriate locations. o Installation of slip blinds at all appropriate locations. At no stage during the chemical cleaning and passivation program should the design pressure of any component of the system being chemically cleaned and passivated be exceeded. Water used for preparing the various cleaning solutions of for any flushing associated with the chemical cleaning and passivation program should be either chloride free demineralized water or chloride free clean steam condensate. Draining of the various chemical cleaning and passivation solutions from the cleaning circuit should be nitrogen assisted to ensure: o No component contained within the circuit is exposed to a vacuum o Moist air does not enter the cleaning circuit. The Specialist Chemical Cleaning Contractor should make the necessary arrangements for the disposal of all waste materials generated during the cleaning program (note: such arrangements should be in accordance with all the host plant site and country environmental regulations). The Specialist Chemical Cleaning Contractor should provide for each cleaning circuit a set of test coupons which are installed in the circulation tank. Following completion of the chemical cleaning and passivation program for the circuit in question these coupons are removed, inspected, and replace with a fresh set of test coupons in readiness for the next

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cleaning circuit. A minimum of one test coupon for each different material of construction present within the system being cleaned should be provided. 6.1.25. 



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Outline Of The Chemical Cleaning, Passivation, and Preservation Procedure

Pre-Cleaning o Use hoses or the Specialist Chemical Cleaning Contractor’s temporary circulation pump(s)/tank to water flush all pipe work on a once through basis with the flush water being directed to a suitable containment system (flush water velocity should be in the range 3 – 4 m/s). o Sample flush water. o If flush water is dirty continue flushing until flush water is clean. Cold Water Flushing o Fill the system with cold Demineralized Water. o Circulate cold Demineralized Water and vent air/from all high point vents. o Maintain the cold flush water circulation for 1 hour ensuring that water has been circulated through all sections of the cleaning circuit in question (maintain a circulating water velocity should be in the range 3 – 4 m/s). o Check screen at circulation tank inlet. o Sample flush water. o If:  The screen is dirty  The flush water is dirty drain the flush water and repeat this step. Hot Degreasing o Fill the system with Demineralized Water. o Circulate cold Demineralized Water and vent air/nitrogen from all high point vents. 0 o Heat the circulating Demineralized Water to 80 C. o

o

o o

Add chemicals:  Trisodiumphosphate (0.75% w/w) pH=11  Caustic Soda (1.0% w/w)  Wetting Agent (Teepol) (0.15% w/w). Sample cleaning solution hourly and analyze for:  Alkalinity  Oil  pH. 0 Maintain the cleaning solution temperature at 80 C and circulate cleaning solution for 4 – 6 hours (maintain a cleaning solution velocity in the range 0.5 – 1.0 m/s, the cleaning solution velocity should not exceed a maximum of 1.5 m/s). Section 6 – Unit Conditioning

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Drain the system using nitrogen supplied to all system high points. Fill the system with Demineralized Water. Circulate for 3 hours. Drain the system using nitrogen supplied to all system high points. Repeat the water wash step until the wash water pH is the same as that of the fresh Demineralized Water supply. Warning Be careful if using hot water for the circulation, when flushing to grade, that personnel are adequately protected from getting burned while flushing these lines.



Acid Cleaning o Fill the system with Demineralized Water. o Circulate cold Demineralized Water and vent air/nitrogen from all system high points. 0 o Heat the circulating Demineralized Water to 80-85 C. Add inhibitor Rodine 92 (0.1%w/w). Circulate for 1 hour. Add chemicals:  Citric Acid (3.0%w/w)  Ammonium Bifluoride to maintain pH=3.5. o Sample cleaning solution hourly and analyze for: 2+ 3+  Total Iron (Fe and Fe )  Acid Concentration  pH. o Continue circulation of the cleaning solution until the Total Iron concentration of the cleaning solution is constant (approximately 2000ppm) (maintain a cleaning solution velocity in the range 0.5 – 1.0 m/s, the cleaning solution velocity should not exceed a maximum of 1.5 m/s). Passivation 0 o Cool the circulating cleaning solution to 65 C. o Add chemicals:  Anhydrous Ammonia to adjust the cleaning solution pH to 9.5  Sodium Nitrite (0.5%w/w) 0 o Maintain the cleaning solution temperature at 65 C and circulate cleaning solution for o o o



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6 hours (maintain a cleaning solution velocity in the range 0.5 – 1.0 m/s, the cleaning solution velocity should not exceed a maximum of 1.5 m/s). Drain the system using nitrogen supplied to all system high points. Fill the system with Demineralized Water. Circulate f o r 3 h o u r s ( maintain a Section 6 – Unit Conditioning

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circulating water velocity in the range 0.5 – 1.0 m/s). Drain the system using nitrogen supplied to all system high points. Fill the system with Demineralized Water. Circulate for 3 hours (maintain a circulating water velocity in the range 0.5 – 1.0 m/s). Drain the system using nitrogen supplied to all system high points.

Note It is important to minimize the number of flushes to retain the passivation. 

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Draining and Drying o Open all system low and bottom point drains. o Test exhaust nitrogen at all system low and bottom point drains for dew point. 0 o When exhaust nitrogen at all system and bottom point drains reaches -20 F close all drains and pressurize the system to 1barg with nitrogen and isolate and remove the nitrogen supply to all high points. Acceptance Criteria and Inspection Of Cleanliness and Reinstatement o Inspect the test coupons from the circulation tank o Random inspect of cleaned surfaces at various locations around the cleaning circuit in question (in particular where the cleaning solution velocity may have be sub optimal). o All the test coupons and cleaned surfaces should:  Have a gun metal grey color  Be free from any iron oxide (rust)  Be free from loose particles, scale, sludge, dust, and /or any foreign materials. If the above cleanliness criteria are not achieved the cleaning circuit in question should be recleaned. Reinstatement o Perform reinstatement activities in such a manner as to limit the ingress of air into the cleaned system. o Perform reinstatement activities in such a manner as to ensure no foreign items or materials enter the cleaned system. o When removing slip blinds installed in vertical pipe work take care that any loose material that may be deposited on the top of the slip blind does not enter the cleaned system. o Reinstall all items that were removed from the cleaning circuit in preparation for the chemical cleaning and passivation program.

Section 6 – Unit Conditioning

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Note While removing blinds, replacing pipe connections or flanges, etc., care must be taken to avoid inadvertently admitting foreign material back into the system that could have been trapped or isolated in the piping during the flushing. Where a blind or a valve has remained closed during the flushing operation it may have material deposited immediately upstream of it, the recommended practice, where possible, would be to insert a vacuum hose upstream and suck out everything from the upstream side. Where a slip blind has been used, especially in a vertical pipe run, its upstream face should be vacuumed or flushed with a hose to clean it off before disturbing or removing it. 

Preservation o Following reinstatement chemically cleaned and passivated systems should be preserved under a 1 bar(g) dry nitrogen blanket until which time they are to be placed into service. o Daily check that cleaned system nitrogen blanket pressure is 1barg. o If the nitrogen blanket is lost determine and rectify the reason for the loss of the blanket and then immediately reestablish the 1 bar(g) dry nitrogen blanket. Warning The chemicals used in the alkaline boilout and in subsequent chemical cleanings must be compatible with all of the metals in the entire system being cleaned and be chloride-free. Solutions that attain high iron levels during or following the cleaning of a circulation path should be disposed and fresh solution prepared. Iron rich solutions must not be used in equipment not cleaned just by adding more chemicals to the previously used mixture.

72. Metallurgy Piping specifications are carbon steel for ASA2R and FSA2R along with GSG2R which is 2¼% Cr - 1% Mo and FSD4R which is 1¼% Cr – ½% Mo Tubes in superheater 101-B(CSSH) / B(HSSH) – SA312 TP-304H

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7. Special Instrumentation And Controls Please refer to the following documents:  Complex Control Narrative (Doc. No. P2B-10-00-PD-0003-R)  Interlock Narrative (Doc. No. P2B-10-00-PD-0002-R)

Section 7 – Special Instrumentation and Controls

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8. Start-Up Procedures 73. Introduction The startup procedure presented is for the initial startup of the unit. It assumes that all offsite facilities have been pre-commissioned, placed in operation and are available to support the ammonia unit startup. A further assumption is that all catalyst bearing vessels have been charged with the proper amount and type of catalyst and that all equipment contains oxygen (air). In the course of subsequent start-ups, certain of these procedures may be eliminated or modified in whole, or in part, as may be applicable to the particular situation. Procedures for each section of the unit are handled separately in the write-up for convenience in presentation; however, it should be recognized that many of these procedures may, and should, be performed concurrently so that the unit start-up is coordinated and expeditious. Prior to beginning the start-up activities, a systematic inspection should be made of the entire unit to insure that all required plugs and blinds are in place, and that all unwanted blinds have been removed, WITH PARTICULAR ATTENTION TO THOSE UNDER SAFETY VALVES. Plugs should be installed in all bleed and drain valves. All instrument and restriction orifices should be verified correctly installed and any check valves that were dismantled should be verified as assembled and correctly installed. Steam requirements for process and equipment operation of the unit are produced from waste heat steam generating equipment that is an integral part of the unit and from the offsite package boiler. It will be necessary to import 46.9 kg/cm2G steam from offsite sources to be used during the initial start-up phases of the ammonia unit. The import flow rate of 46.9 kg/cm2G steam (MP Steam) from offsites can be about 177 ton/h for a case during 101-J start up and the reformer operating at about 25% feed gas and 33% process steam flow rate. Before the offsite Package Boiler produces steam, Ammonia Unit imports 40 kg/cm2G steam from existing plant (OEP) during initial start up. The import flow rate of 40 kg/cm2G steam from OEP can be about 176 ton/h for this case. During initial stages of start up, MP steam import can be utilized in the ammonia unit for process and turbine operation. The ammonia unit will generate as much steam as possible for its own use through the start-up and import what is required from offsites. The steam generating capacity within the ammonia unit is provided by the following equipment: ♦ Secondary Reformer Waste Heat Boiler 101-C ♦ HTS Effluent Waste Heat Boilers 103-C1 and 103-C2 ♦ Ammonia Converter Effluent Steam Generators 123-C1 and 123-C2 Section 8 – Start-up Procedures

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Since major steam generating equipment is an integral part of the process equipment, the startup has to be conducted in such a way as to ensure offsite steam availability and that steam production at each stage of the start-up is adequate to satisfy all steam requirements of the unit. The estimated normal steam balance FD-6A series for the plant should be found and used as reference. NOTE As with any process unit, the ultimate operating conditions and techniques will evolve from experience gained during the initial and subsequent startup operations. Consequently, it must be recognized that the start-up philosophy presented here is, at best, a guide to help ensure an orderly initial start-up of the unit, and all conditions stipulated are not rigid standards, unless specifically noted as such.

The following start-up is presented in two parts: first, the preliminary start-up procedures; second, a detailed unit start-up procedure. Start-up is a continuous operation and is carried forward until the unit is on-stream producing design quality product. However, certain steps require time to complete, so downstream equipment can be purged or commissioned during those periods, to expedite the unit start-up. 74. Preliminary Start-Up Philosophy See Section 6, Unit Conditioning, of this manual for additional information for precommissioning and commissioning of the unit. Inspect the entire unit for completeness and correctness of construction, using the P&IDs and vessel drawings as guides. Give particular attention to thermocouple locations and elevations. The steam systems and systems to support steam generation should be completed as soon as possible to expedite cleaning of these systems. The refractory of the Primary Reformer and Secondary Reformer must be dried under carefully controlled conditions and before catalyst can be loaded in the Secondary Reformer. The procedures for the dryouts are outlined in Section 6 in this manual. This operation is usually supervised by KBR personnel on an around the clock basis. The dryout can be carried out using liquefied petroleum gas, LPG, if the fuel gas systems are not ready for commissioning. Electric power for the plant must be available and commissioned at an early stage. Electric motor rotations should be checked uncoupled and verified as correct.

Section 8 – Start-up Procedures

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When plant air, instrument air, and nitrogen are available from offsites, the systems are to be blown clean and commissioned with their normal media. When cooling water is available from offsites, the system is to be flushed clean and commissioned with the normal media. Clean the cooling water systems simultaneously with the offsite cooling water systems. When demineralized water is available from offsites, the system is to be flushed clean and commissioned with the normal media at the normal conditions. When the service and potable water systems are available from offsites, the systems are to be flushed clean and commissioned with their normal media. With air and nitrogen available, the fuel gas system should be air blown clean and purged to 0.5% oxygen content or less with nitrogen. Load catalyst after vessels have been cleaned and inspected. Standard procedures and vessel drawings should be used to insure proper loading. Loading procedures can be found in Section 6 of this manual. Extra care must be exercised in the loading of the primary reformer. After loading, pressure drops are taken on each tube. Those that fall outside acceptable limits, 3 - 5%, are unloaded and recharged until all tube differential pressures are uniform. This is done to eliminate hot spots, high pressure differentials and to promote uniform gas distribution. Keep a nitrogen blanket on the ammonia converter after loading catalyst if any pre-reduced catalyst is loaded. Load the packing material in the High Pressure Condensate Stripper, CO2 removal and ammonia recovery system columns. Actual loading of the catalyst and tower packing will usually take place nearing the final stages of construction but can be done earlier. Isolate these items, after loading, to prevent damage or the entrance of contaminants. Flush the steam condensate systems clean with demineralized water or steam condensate.

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Water flush all liquid carrying lines using filtered water. For ammonia liquid lines, flush them using demineralized water or air blow using compressed air.

Section 8 – Start-up Procedures

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When 46.9 kg/cm2G steam is available from offsites Package Boiler or 40 kg/cm2G steam from OEP, blow clean the HP, MP and LP steam systems of the ammonia unit with MP steam. As a final check on the cleanliness of the steam system, install “Polished” targets at the open ends of lines (especially steam lines to critical control valves and rotating equipment: 101-JT, 101-JLOT, 101-BJT, 101-BJAT, 101-BJ1T, 101- BJ1AT, 102-JT, 103-JT, 103-JLOT, 104-JT, 105-JT, 107-JBT and 108-JT. Frequently check piping expansions during heat up and blowing. NOTE When warming up any steam system in preparation for blowing, proceed very slowly with many drain lines open to avoid water hammering that can cause serious equipment damage. After steam systems are blown clean, commission all steam traps from headers to insure that they are kept hot and free of all condensate. All laterals to various items of equipment should be kept closed until they are ready for use.

After the steam systems are blown clean and the orifice plates and flow elements for these systems are installed, place the HP, MP and LP systems into service and maintain pressure with offsite Package Boiler steam import using PIC-1015 or using PIC-1075 for steam import from OEP. Commission steam line vents PIC-1014 through PV-1014 and PIC-1017B through PV1017B, on automatic to avoid over pressuring of the systems. With steam available, verify the mechanical overspeed trip mechanisms for all steam turbines. Water flush the boiler feedwater systems with demineralized water or steam condensate. Mechanically clean and then water flush the deaerator, 101-U, with steam condensate or demineralized water, then wash with a chemical detergent and flush clean, if required. Dry the refractory of primary reformer, 101-B; secondary reformer 103-D; and the 102-B, start-up heater; according to the procedures outlined in Section 6 of this manual. The dry out of the 101B may be synchronized with the chemical cleaning of the high pressure steam generating equipment. Chemically clean the high pressure steam generating equipment. A philosophy for the cleaning has been developed and will be implemented by construction and supervised by operating personnel and the sub-contractor awarded the job. An outline typical of this procedure can be found in Section 6 of this manual. If chemical cleaning of the HP steam drum, 141-D, and the HP steam system have been done prior to air blowing the process lines, it will be necessary to do a wet or dry 'lay up' of the HP

Section 8 – Start-up Procedures

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steam drum and nitrogen blanket the HP steam system until process air blowing is complete and the unit ready to make steam. Use the 101-J air compressor for process line blowing and catalyst dusting as described on the following pages. There is a possibility that the Process Air Compressor 101-J is not ready for service for air blowing the process lines. In this case, a number of large capacity, oil-free, auxiliary motor driven air compressors will need to be used along with some storage capacity and temporary piping runs for process line blowing. Typically, three 2,500 m3/h oil-free compressors are used along with the 121-D absorber as a capacity storage vessel. Temporary piping will have to be laid to connect the absorber outlet with the blowing inlet points and temporary isolation and blowing valves will need to be added to these lines.

CAUTION Be sure that the temporary piping and valving is pressure rated for the pressure output of the temporary air compressors or add sufficient relief valves for protection.

Start the air compressor as follows: This start-up sequence assumes that all instrumentation has been commissioned and is ready for service, that all electrical power is available, electrical switches are in the OFF position and that all other valves are closed unless specifically noted otherwise. Ensure suction filters are installed and clean in 101-L, Air Compressor Suction Filter. The compressor will be started in accordance with procedures recommended by the compressor and turbine manufacturers and brought up to the minimum governor speed, venting through FV1004. After blowing the 46.9 kg/cm2G steam from Package Boiler or 40 kg/cm2G steam from OEP to 101-JT and completing all other pre-run work on the machine, 101-J will be used for process line blowing and catalyst dusting as described on the following pages. The 101-JTC, Surface Condenser, will be placed in service prior to starting up 101-J. The procedure for commissioning the surface condenser is as follows: a) Start the cooling water flow through the main condenser and the inter and after condenser. Bleed air or any inert gas out of the water side of the condenser.

Section 8 – Start-up Procedures

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Establish a level of demineralized water in the surface condenser hot well by providing a hose or back flowing from the offsites demineralized water system to the surface condenser through line DM4085-2”. Align the equipment for evacuation of air. Check all isolation valves, bleeds, drains, vents, etc. throughout the entire vacuum system to ensure complete closure. Initiate full steam flow to the "hogging" jet and start non-condensable evacuation. Continue air removal until the pressure on the surface condenser has been reduced as low as possible as indicated on local PG-4812. Then place the after and inter condenser ejectors (in that order) in service. Check operability of the traps on these items to insure that condensate is being withdrawn to the surface condenser hot well. With near normal vacuum on the system of 77.6 mmHga, it will be possible to start the compressor. When 101-J is in operation, the level in the hot well will rise and a 118-J pump will be started with its pump vent open and minimum flow control system in service back to 101-JTC It is customary to send the initial production of condensate to sewer through the manual drain on the 118-Js discharge line, so that any scale or other debris which might be present will not be pumped into the condensate system. So, initially, the condensate from the surface condenser will be discarded. Once this stream is acceptably clean, it can be lined up to DM Water header through 112-L. Before the condensate is directed into the condensate system, the conductivity analyzer, AI-4019, should be placed in service. Cooling water leakage into the condensate system will give a high conductivity. If this occurs at anytime, the condensate from the surface condenser must immediately be diverted to sewer, to avoid contaminating all of the condensate being collected. Initiate sealing water flows to the atmospheric relief valves which are installed on the vacuum exhaust lines of those items which exhaust into the vacuum system. Take the "hogging" jet out of service as soon as conditions stabilize and maintain vacuum with the jets on the inter and after condenser. The surface condenser is now in operation ready for normal duty.

The process air compressor will be run-in as soon as driving steam and the necessary utilities are available. The process air compressor will be used to clean the lines and dust catalyst according to the following procedures: • The initial blow will be from line A1009 back through line NG1004 back to the battery limit isolation. For this purpose, remove NRV on line NG1004, provide spool piece for FV-1130, blind 102-J discharge and create gap at inlet of 143-C to blow at 143-C inlet. Once clean blow through 143-C to battery limit. Confirm FE-1042 and PV-4101A removal prior to blowing. Place a blind at 174-D inlet. Spread the flanges at the battery limit isolation valve and bypass leaving blinds in place to prevent debris entering the valves, blow until clear. Close the flanges with blinds installed and temporary gaskets. Section 8 – Start-up Procedures

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Blow using the same circuit at 174-D inlet. Remove demister and blow through 174-D upto 102-D inlet. Once clean blow through 102-D upto 102-J suction after placing a blind at inlet flange. Install a spool piece for PV-1001A/B and spread flanges at the upstream side of FE-1015 in line FG1002 to blow the fuel gas supply line. Place a blind on the downstream side of the flange to keep the flow element clean. Blow until clear. Close the flange with a permanent gasket. Remove check valve internals of check valve in line SG1014. Spread flanges at FV-1022 and bypass. Place blinds on the valve side of the flanges. Blow until clear and close flanges with permanent gaskets. Install internals in check valve. Remove the removable spool at the inlet to 101-D and manual valve beside SP-SFS-0025 and SP-SFS-0030 in line NG1006 and NG 1003 of 108-DA/DB and cover the manway nozzles to allow the blowing of the lines and dusting of the catalyst. Blow the line, NG1005, to the inlet of 101-D until clear. The catalyst in 101-D can now be dusted by installing the removable spool and blowing through 101-D to the open inlet manual valve of 108-DA until clear. Repeat these steps to dust the catalyst in 108-DA and DB. Remove FV-1001 and install a temporary spool piece. Remove HV-1061 and install a temporary spool piece. Remove FE-1201 for the blow. Remove HV-1108 and place a spool piece in its place the blow vent line V1090 to the vent header Blow through the 108-DA/DB inlet and series line NG1033 to line NG1007 to the removed HV-1108 and FV-1001 temporary spool piece alternately. Alternate blowing through 108DA/DB inlet and series lines until clean. When the above circuits have been blown clean, remove all blinds and replace FE-1201, HV1108 and FV-1001. Remove inlet blinds on 108-DA/DB vessels. Keep the compressor discharge pressure low to minimize heat of compression and do not ignite any primary reformer burners during catalyst dusting and line blowing through the reformer. Remove the top head from the 103-D secondary reformer and place a tarp over the catalyst to catch any dirt and debris then blow to the secondary reformer. Air blow the piping from 101-J to 103-D, through the normal path for process air to 103-D, clean while the top manway is removed and a tarp is covering the catalyst bed. Include bypass line A5001- 6” at the cold air coil in the blow. Remove FE-1003 for the blow. Overriding of the system trips will have to be done to accomplish these steps. Blowing should first be done to FV-1003 /its bypass line valve and XV-1212 with the valves removed before blowing to 103-D. To blow the process gas side, the air will be routed through the start-up line, A-1002-4” to the inlet of the mixed feed preheat coil and out each manifold header (6) upstream of the pig tails to remove dust and debris from the preheat coil and piping. When the primary reformer was loaded with catalyst, the caps on top of the reformer tubes were replaced loosely with one bolt. These caps should now be taken off and rag balls stuffed down the tubes with wire attached so the rag balls can be removed after pig tail Section 8 – Start-up Procedures

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blowing. The rag balls will be placed above the catalyst but below the pig tail inlet opening of the catalyst tube. During blowing of the pigtails, each opening into the catalyst tubes must be checked for positive air flow through each pigtail. • Dusting of the primary reformer catalyst will be conducted by: ♦ Removing the rag balls, installing the top caps on all tubes with permanent gaskets and bolts tightened to specification torque. Blow to 103-D with tarp remaining in place over the 103-D catalyst. ♦ The drains of all six outlet manifold headers must be verified open and be checked frequently during the dusting phase to assure they remain clear. CAUTION Be sure that the blowing air temperature does not exceed 150°C while air blowing equipment to avoid catalyst damage.

• The top head of the secondary reformer should be reinstalled once blows through 101-B and the air line are completed and after the tarp has been removed from on top of the catalyst. Care must be taken to prevent spilling any of the contents into the catalyst. • Dusting of the secondary reformer catalyst will require removing the bottom head, and installing a temporary plug in the outlet nozzle of 103-D to 101-C. After catalyst dusting of 103-D is complete, remove the temporary plug from the outlet nozzle and re-install the bottom head. • Air blow the tube side of exchanger 101-C and shell side of 102-C to opened inlet nozzle of 104-D1, with inlet flange spread and vessel blind protected. • Remake inlet nozzle flange permanently and open outlet nozzle flange for dusting the 104-D1 HTS catalyst and blow through 104-D1. Blind the shell side inlet to 103-C1. Blow at 103-C1 inlet at 10” flange provided for the purpose. CAUTION Do not blow through 103-Cs until the blow to them is completed. 103-C tubes have a fine set of fins on each tube that can plug with excessive catalyst dust / line scale leading to a loss of heat exchange capacity.

• Make the 103-C1 inlet flange permanently and blow lines to the inlet of the 104-D2A LTS, with MOV-1008, its bypass and 104-D2A block valve and its bypass full open, in the same manner as was done with the HTS. Then dust the 104-D2A catalyst at the outlet nozzle to the vent system using line V6007. • Similarly blow at the inlet of 104-D2B by keeping its inlet and bypass full open and then dedust 104-D2B to vent using line V1007. Care should be taken that dust from 104-D2A is not transported to 104-D2B. Section 8 – Start-up Procedures

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• Close MOV-1008 and blind the LTS in preparation for catalyst reduction. • Open the shell inlet flange on 131-C and blind exchanger side for protection. Remove HV1021, MOV-1009 bypass. Blow through MOV-1009 and bypass line to 131-C. • Blow through PV-1032 and then through it to vent. • Blow through MOV-1009 and bypass line, LTS bypass to 131-C. • Remake the shell on 131-C, open the inlet head on 105-C tubes, and place a fitted piece of wood or tarp over the tube sheet for protection. Replace HIC-1021 valve. Close the process bypass line around 105-C • Blow through MOV-1009 and HIC-1021, through 131-C 105-C. • Remake the head on 105-C, open the inlet head on 106-C tubes, and place a fitted piece of wood or tarp over the tube sheet for protection. • Blow through MOV-1009 and HIC-1021, through 131-C, 105-C tubes to 106-C. Also blow through the 105-C process bypass line to 106-C. • Remake the head on 106-C, open the manway on 142-D1, and place a fitted piece tarp over the drum liquid outlet to prevent trash entering the line. • Blow through MOV-1009 and HIC-1021, through 131-C, 105-C tubes, and 106-C tubes to 142-D1. • Close the manway to 142-D1 after removing the tarp and spread the flange on the process gas line inlet to 121-D. Place a thin blind or other type of protection over the 121-D inlet nozzle. Remove PV-1040 on line PG1065-10”. • Blow through MOV-1009 and HIC-1021 through the LTS exchange circuit to PV-1040. • Replace PV-1040 and blow through it to the vent system. • Blow through MOV-1009 and HIC-1021 through the LTS exchanger circuit through MOV-1005 and its bypass to 121-D gas inlet nozzle • Close the inlet flange to 121-D. Open the manway on 142-D2. Place a tarp over the liquid outlet line inlet to keep trash out of the line. • Blow through MOV-1005 to 142-D2, close the 142-D2 manway after removing the tarp. • Spread the upstream flange on MOV-1011. Place a blind or other type of protection over the MOV-1011 inlet nozzle. Blow through MOV-1005 and 121-D to MOV-1011. Close the upstream flange on MOV-1011 with a permanent gasket. • Remove XV-1211 and blow through the previous circuit until clean. Replace XV-1211. • Remove the inlet head on 114-C. Place fitted protection over the 114-C tube sheets. Close TV1012A fully. • Open MOV-1005. Open XV-1211 and blow through MOV-1011 to 114-C. • Replace the head on 114-C. Remove TV-1012A control valve and place a thin blind or other protection over the downstream opening. • Open MOV-1005. Open XV-1211 and blow through MOV-1011 to TV-1012A. • Replace TV-1012A. • Spread the 106-D inlet flange and place a blind on the open nozzle. • Open 172-C process side bypass 100% • Blow through MOV-1011 through and around 172-C to 106-D. Make sure 172-C uipstream piping has been blown clean before allowing the flow through 172-C. Section 8 – Start-up Procedures

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• Remove the blind and close the 106-D inlet flange with a permanent gasket. NOTE Spread the flange on the process gas line inlet to 130-C1 tubes. Place a thin blind or other type of protection over the opening to 130-C1.

• Blow through MOV-1011 through 106-D, 114-C shells (after prior cleaning of 114-C shell side upstream piping), and 115-C (after prior cleaning if 115-C shell side upstream piping) to 130C1 inlet. Close the flange to 130-C1 tubes. • Open manway to 144-D and place a tarp over the liquid outlet line to keep trash out of the line. • Blow to 144-D through MOV-1011. • Clean the debris, remove the tarp and close 144-D manway. • Remove PIC-1084 on line V1012. Place a thin blind or other type of protection over the opening to the vent. • Blow to PIC-1084. • Replace PIC-1084 and blow through it to the vent system. • Open the flanges inlet to 109-DA / DB. Place a thin blind or other protection over the vessel inlets to keep trash out of the inlet distributor. • Remove PV-1049A / B. • Blow through MOV-1011 through to PV-1049A / B and to the opened inlet nozzles of 109-DA / DB, with inlet flanges spread and vessels blind protected. Manually alternate opening MOV1017 and MOV-1018. When a MOV is open close the 2” block valve inlet to PV-1049A or B. • Blow all adjacent piping connected to 109-DA / DB per the detailed precommissioning procedures. Remove and replace valves as required Remove the removable spool at the inlet to 132-C. Place a thin blind or other protection over the downstream flange. Blow through 109-DA / DB to the removable spool. Install the removable spool after blowing and isolate the purifier. DO NOT BLOW INTO OR THROUGH THE PURIFIER EXCHANGER. • Open the flange to the 103-J first stage suction. Be sure to blind the flange downstream of the opening so that no trash is blown into the 103-J and so that no air enters the compressor and spins the machine without lubricating oil being in service. • Using line SG1065, bypassing the purifier, blow first to PV-1004 then through PV-1004 to the vent and finally to the 103-J suction. Because of the complexity of the piping layouts from the molecular sieves through the synthesis loop, specific details and sequences of line, blowing will be developed in the field. However, be sure that all of the lines are blown to and from the following major equipment:

Section 8 – Start-up Procedures

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109-DA and associated piping 109-DB and associated piping 109-Ds regeneration inlet and outlet lines to and from the process stream to fuel gas 154-LA and 154-LB 131-JX – only to Purifier boundary nozzles 132-C – only to Purifier boundary nozzles 134-C – only to Purifier boundary nozzles 137-D – only to Purifier boundary nozzles 116-C 103-J second stage suction, recycle inlet, and anti-surge lines – do not blow into compressor 103-J third stage suction, recycle inlet, and anti-surge lines – do not blow into compressor 103-J Seal Gas supply lines Recycle line to 124-C shell inlet 121-C tube sides 105-D inlet, outlet, and cold shot lines 102-B inlet and outlet lines 123-C1 and 123-C2, lines 121-C shell side inlet and outlet lines 124-C shell side inlet and outlet lines 120-C tubes 146-D Synthesis Gas line from 146-D to 120-C 147-D inlet and outlet lines 146-D and 147-D purge lines 124-D to 101-B / 130-C1 and vent lines 120-CF to 105-J 105-J 1st and 2nd stage suctions – do not blow into compressor 105-J Seal Gas supply lines 105-J recycle to 120-CF1 / CF2 / CF3 and CF4 105-J 3rd stage suction – do not blow into compressor 128-C 105-J 4th stage suction – do not blow into compressor 121-Js 120-CF1 / CF2 / CF3 / CF4 liquid outlets 124-Js Cold ammonia to storage lines Warm Ammonia Product lines to Urea 127-C 127-C to 125-D and 125-D vent 149-D main inlet and outlet lines 149-D purge line 113-Js Section 8 – Start-up Procedures

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120-J 161-C tube / shell 123-D 124-D 125-D 161-Js

After the above dusting and line blowing is complete and all the equipment has been reassembled, including all flow elements removed for the line blowing, an equipment or system leak test will be performed. It will include all of the systems that have been air blown. The purpose of the test is to ensure that all openings created for air blowing have been tightly assembled. Therefore, the pressure test will be at 7.0 kg/cm2G. Air, from 101-J, or from the temporary compressors can be used as the pressuring medium or, to expedite start up, nitrogen can be used for the test and purging at the same time. During this operator leak test, all valves and flanges are to be inspected for tightness. When the systems are considered tight, nitrogen purging will be started and all systems aligned for the start up operation. The following equipment / systems are to be included in the feed gas / reformers nitrogen purge: • 174-D Feed Gas Knockout Drum • 101-D Hydrotreater • 108-DA/DB Desulfurizers • 101-B Primary Reformer • 103-D Secondary Reformer • 101-C Secondary Reformer Waste Heat Boiler shell • 102-C HP Steam Superheater shell • 104-D1 HTS Converter • 103-C1 HTS Effluent Steam Generator • 103-C2 HTS Effluent BFW Preheater Vent through PV-1032 to the hot vent system. The nitrogen purging is continued until the oxygen content has been reduced to 0.5% or less. Three pressure purges at a pressure greater than 3.5 kg/cm2G will usually accomplish this. A positive pressure of nitrogen or gas is then maintained on this system until Natural Gas is used in the heat up of the desulfurizers. After the feed gas / reformers system has been tested and purged, then purge the process system from 104-D2A/B to 121-D inlet. A positive pressure of nitrogen or gas is then maintained on this system until Natural Gas is used in the heat up of the desulfurizers. The following equipment / systems are to be included in the LTS purge: • 104-D2A/B LTS Converters Section 8 – Start-up Procedures

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131-C LTS Effluent / BFW preheater 105-C CO2 Stripper Reboiler tubes and bypass 106-C LTS Effluent / Demin Water Exchanger tubes 142-D1 Raw Gas Separator 173-C LTS Start-up Cooler shell 173-D LTS Reduction System K.O Drum 173-J LTS Start-up Blower 175-C LTS Start-up Heater tubes Lines SG1030, SG5030, SG1019 and SG5019

Vent at PV-1040 to the hot vent system. The purging is continued until the oxygen content has been reduced to 0.5% or less. Three pressure purges at a pressure greater than 3.5 kg/cm2G will usually accomplish this. The feed gas system, previously purged, is to be isolated from the primary reformer and other start-up loops before the system is pressured with Natural Gas. The block valves at the outlet of the desulfurizers are closed to accomplish the isolation. NOTE An acceptable oxygen concentration of a purged system is 0.5% or less.

The low temperature shift converters will now be blinded to isolate it from the system. The low temperature shift converters will be reduced later utilizing a low pressure, recirculation reduction method with nitrogen gas as a carrier. The emergency isolation valve, MOV-1008, at the inlet to the LTS converter 104-D2A will be blinded at the downstream side. The outlet valve from 104D2B, MOV-1007, its bypass and the manual valve to line V1007 to the vent system will also have blinds installed. The 104-D2A/B should be blinded to closed position until the LTS converter catalyst is to be reduced. This will prevent any possibility of hydrogen leaking into the vessel prior to catalyst reduction. CAUTION Once the low temperature shift converter is isolated from the process and has been purged air free it must held under nitrogen atmosphere of sufficient pressure to insure that process hydrogen bearing gas DOES NOT CONTACT the catalyst. This includes the start-up piping to and from 173-J circuit. Prior to reduction, this catalyst is very active in a hydrogen atmosphere of any concentration. Check the pressure of the LTS converter often during subsequent start-up operations to ensure the converter is always maintained in a safe condition.

Section 8 – Start-up Procedures

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The methanator and associated equipment will also be purged with nitrogen by pressuring and depressuring to atmosphere until oxygen is less than 0.5%. Three cycles to 3.5 kg/cm2G then to 0.5 kPag will usually accomplish this. The following equipment / systems are to be included in the methanator purge: • 121-D CO2 Absorber • 142-D2 CO2 Absorber Overhead Knockout Drum • 172-C Methanator Start-up Heater shell • 106-D Methanator • 114-C Methanator Feed Effluent Exchanger shell / tubes • 115-C Methanator Effluent Cooler shell • 130-C1 / C2 Methanator Effluent Chiller tubes • 144-D Methanator Effluent Separator Anytime the system is being depressured after a nitrogen purge, always use the low point drains to ensure any last traces of water are cleared from the system. This is especially important during subsequent purging of the synthesis gas loop and refrigeration systems. After the methanator and associated equipment have been purged air free, the system will be pressured to 5.0 kg/cm2G with nitrogen for a tightness test. Inspect all flanges to verify that the system is tight and tighten as required if leaks are found. Upon completion of the above pressure test, purging of the purifier, synthesis gas compressor, loop, and converter will be undertaken. CAUTION Always purge and pressurize the Purifier from the outlet to the inlet – reverse of the normal flow path.

The following equipment / systems are to be included in the synthesis gas loop purge: • 109-DA / DB Molecular Sieve Driers • 154-LA / LB Molecular Sieve Driers Filters • 183-C Molecular Sieve Regeneration Heater shell • 131-JX Purifier Expander • 132-C Purifier Feed / Effluent Exchanger • 134-C Purifier Rectifier Condenser • 137-D Purifier Rectifier • 103-J Synthesis Gas Compressor • 116-C Synthesis Gas Compressor Interstage Cooler • 121-C NH3 Converter Feed / Effluent Exchangers tubes / shells

Section 8 – Start-up Procedures

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Start-up Heater NH3 Converter NH3 Converter Effluent Steam Generator shell NH3 Converter Effluent BFW Preheater Exchanger tubes NH3 Converter Effluent Cooler shell NH3 Unitized Chiller tubes NH3 Separator

In displacing air from the system, do not impose too high of a pressure. A positive pressure of 3.5 kg/cm2G throughout the circuit will be sufficient for each purge cycle. When tests indicate that the system is essentially air free, 0.5% O2 or less, pressure test the system at 5.0 kg/cm2G and maintain a positive nitrogen pressure after the test is completed. The refrigeration system must be purged with nitrogen to free the entire system of air. This can be accomplished by using the nitrogen from 146-D to 147-D through line NHL1000, from 147-D to 149-D, 120-CF4, 120-CF3, 120-CF2, and 120-CF1. Nitrogen is steadily introduced until the system is purged air free, 0.5% O2 or less. Pressure purging to 3.5 kg/cm2G as previously described can also be used. The first ammonia brought into the system will then be used to sweep the majority of the nitrogen from the system. The following equipment / systems are to be included in the refrigeration system purging: • 147-D Ammonia Letdown Drum • 149-D Refrigerant Receiver • 124-J / JA Cold Ammonia Product Pumps • NHL1014 Cold Ammonia Product to Storage • NHL2106 Warm Ammonia to Urea • 120-CF1 First Stage Refrigerant Flash Drum • 120-CF2 Second Stage Refrigerant Flash Drum • 120-CF3 Third Stage Refrigerant Flash Drum • 120-CF4 Fourth Stage Refrigerant Flash Drum • 105-J NH3 Refrigerant Compressor • 128-C Refrigerant Compressor 3rd Stage Intercooler shell • 127-C Refrigerant Condenser shell • 113-J/JA Warm Ammonia Product Pumps • 120-J Ammonia Injection Pump • 124-J / JA Cold Ammonia Product Pumps • All inter-connecting piping for the above equipment. The refrigeration system, including all of the above associated equipment, will be tightness tested to 5.0 kg/cm2G with nitrogen. Inspect all flanges, valves and fittings to verify that the system is tight.

Section 8 – Start-up Procedures

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As a liquid level of ammonia is established in the refrigerant receiver 149-D, some inerts (N2) will be vented. 75. Initial Start-Up It is assumed that all vents and drains are closed unless otherwise stated. Instructions to close one of these valves means to verify it is closed. It also assumes all blinds are open unless otherwise stated. Instructions to open one of these blinds means to verify it is open. It also assumes that electrical power, cooling water, nitrogen, instrument air, plant air, potable water, demineralized water, and other major offsite support streams are available. It also assumes that all instrumentation has been loop checked, function tested and placed in service. It also assumes that all motors and turbines have been checked for correct rotation and overspeed trips as well as MP steam from offsites is in service and available to the plant. 76. Commission the Steam Systems Steam must be imported into the ammonia plant from the offsites MP steam system using PIC1015 / its bypass line for offsite Package Boiler steam import, or using PIC-1075 for steam import from OEP. The header must be initially heated slowly using 2” bypass line of battery limit block valve and drained during heating to prevent water hammering that could damage piping and supports. Open all low point drains in the HP, MP and LP steam systems. It may be necessary to open bypasses / drains around the various steam traps until the condensate is clean and the lines are hot. Set the control valves as follows: • PIC-1013 on automatic at its normal setpoint of 46.9 kg/cm2G and PV-1018 and HV1028 unblocked. • PIC-1014 on automatic at its normal setpoint of 47.5 kg/cm2G. Be sure that PV-1014 isolation valves are open. • PIC-1016 on automatic at its normal setpoint of 3.6 kg/cm2G . Be sure that PV-1016 isolation valves are open. • TIC-1023 on automatic at its normal setpoint of 236°C. Be sure that TV-1023 isolation valves are open. • PIC-1017B on automatic at its normal setpoint of 3.5 kg/cm2G. Be sure that PV-1017B isolation valves are open. All attemperation valves except TV-1553, TV-1216, TV-1116, and TV-1023 should be ready for service. It is possible with the above setup to warm up the steam headers all at the same time. Since the offsite MP header is already up to pressure with the steam headers hot, use the following procedure. Section 8 – Start-up Procedures

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Slowly open PV-1015 isolation valve just enough to start a small flow of steam into the unit. As the lines warm up, increase the opening to pressure up the systems and eventually open PV1015. As the MP header pressure increases, the pressure of HP header also keeps increasing through PV-1018. PIC-1016 will start closing to control when the pressure nears the setpoint at 3.6 kg/cm2G. 77. Commission 101-U The 101-U, deaerator, should be placed in service to supply water to the utility and ammonia plant's boiler feedwater systems. Manual adjustment of the PIC-1031 bypass valve may be required to obtain adequate steam pressure during cold start-up conditions.

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It is assumed that the 101-U has been mechanically / chemically cleaned, flushed and inspected, piping has been flushed to the pumps and piping has been blown to 101-U. • The oxygen scavenger, 106-L, and 107-L, Ammonia Injection systems should be run-in, filled and ready to operate prior to starting the deaerator. • Unblock LV-1030 and fill the storage section with demineralized water from the offsite demineralized storage pumps through LIC-1030, on manual control, until a normal level has been established. Initial flow should be with TI-1352 and TIC-1558 fully open on manual bypassing 109-C and 106-C as much as possible. • Unblock and place LIC-1031 overflow valve in automatic. • Start the oxygen scavenger injection system, 106-L at full stroke until the LP steam to 101-U is established. Test for residual chemical and oxygen content after a short period of time. • Start the Ammonia Injection system, 107-L. Test the pH after a short period of time. • Place LIC-1030 in automatic at a flow to maintain the level whenever stable. Manually adjust the output of LIC-1030 to match the setpoint of FIC-1056 and put FIC-1056 in remote control. • Place the stripping steam in service as soon as the LP steam system is available as described in the steam system start-up section following. Reduce the stroke on the 106-L pump once normal steam pressures have been achieved. CAUTION Steam must be admitted slowly into the system to prevent thermal shock and water hammer damage to the deaeration section.

As soon as the LP steam system is pressurized and stable, place the 101-U stripping steam in service as follows: • Open the deaeration section atmospheric vent valve fully using block valve upstream RO-101 UA/B/C/D.

Section 8 – Start-up Procedures

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• Start a small flow of LP steam to the 101-U using PIC-1031 on manual and the line to the storage area. Pressure can be verified locally on PG-1743. As flow is increased, a short vapor plume should be seen coming from the atmospheric vent. • Continue increasing the steam flow slowly until the deaerator pressure reaches 1.73 kg/cm2G, place PIC-1031 in automatic. LS2231 a 6” line goes to nozzle N1 of the storage section. This can be used to provide heat for the BFW during start-up. The 6” pipe to nozzle “N” is the secondary heating supply to remove as much oxygen as possible from the water. • Reduce 101-U vent isolation valve until the steam vapor plume is about 1 meter long. 78. Place HP BFW Pumps In Service Initial start-up of a 104-J pump should be carried out following the vendor’s recommended procedures as found in their IOM manual: • Set-up the lubrication system, CAUTION Be sure that the lube oil temperature is above the vendor's recommended minimum before starting the pump. There is a small heater in the oil reservoir that should maintain the oil above this temperature.

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When the pump driver reaches to its normal operating speed, the shaft driven oil pump feeds lubricant fully without using auxiliary oil pump. Stop the motor driven auxiliary pump after making sure then pump speed and supply pressure are normal then place back in “auto”. If the pump speed doesn’t attain normal speed, the auxiliary oil pump can’t be stopped. As long as the changeover switch is located at “Auto” mode, the auxiliary oil pump will run continuously. 2. Check if supply oil temperature is within the range required by the pump vendor. • Open the suction valve to the pump to warm and prime the pump. • Fill the pump with BFW. Vent the air from pump casing vents. Be sure that the pump is full by venting the pump and the seal piping. • Warm up the pump sufficiently prior to starting, by admitting BFW into pump. WARNING To avoid severe thermal shock to the pump as a result of sudden liquid temperature changes, the 104-J pump may need to be pre-heated prior to operation. The external casing temperature should be near the temperature of the BFW from 101-U at start-up. Preheating of a cold pump should be done at a rate acceptable by the pump vendor. Always leave the standby pump warm up line open during normal operation.

Section 8 – Start-up Procedures

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• Close the discharge valves. • Fully open all suction valves and car-seal open the balance line, if applicable. WARNING The rotating parts of the BFW pump depend on BFW for internal lubrication and may seize if the pump is operated without liquid in the pump. Be sure that the pump is primed before starting. Shutdown the pump immediately if suction is lost to the pump.

• • • •

Lock open the minimum flow recirculation line block valves. Open the warm-up lines around SP-ARV-104J and SP-ARV-104JA Test that all shutdown devices are in service and working properly. Start the driver. If a turbine driver is used, bring the turbine speed up as quickly as recommended by the manufacturer, after the slow roll period.

If the 104-J (turbine driven) is operated, the following steps should be followed (after steam systems are energized); 1. Commission the condenser 102-JTC, if not in service. 2. Open drain valves to drain water from the steam inlet piping, turbine casing, steam chest, and the exhaust piping. Open the 1” bypass around the inlet block valve to warm piping and turbine. After fully warmed up as indicated on local TW/TG-1755, close all drain valves. 3. Warm the LP steam line to SP-104JT condensate pumping trap. Place SP-104JT in service by opening the exhaust isolation valve then the LP steam source valve. Lock open the turbine casing drain valves. Do not run the turbine until the system is empty. 4. Adjust the sealing steam supply valve to permit a slight amount of steam to be discharged from the packing case leak off drain lines. A pressure of 3.5 kg/cm2G is usually sufficient sealing steam pressure. However, care must be taken to prevent steam from blowing out of the packing cases and along the turbine shaft. CAUTION Do not apply seal steam to the packing cases for more than duration recommended by Vendor while the turbine rotor is idle. This condition will cause uneven heating of the turbine rotor and casing which may result in a distorted casing, bowed rotor shaft or other related problem.

5. Verify that 104-JT trip valve is closed and close PRV-102JTC then place a small condensate seal flow in service. 6. Latch the trip valve resetting lever. 7. Slowly open the main steam isolation valve until the turbine reaches approximately 2533 rpm. Section 8 – Start-up Procedures

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CAUTION The main steam should never be admitted to the turbine casing by partially opening the main steam isolation valve while the rotor is stationary. This condition will cause uneven heating of the turbine rotor and casing which may result in a distorted casing, bowed rotor shaft or other related problems.

CAUTION If sealing steam is allowed to leak into the bearing housings due to high pressures causing high leakage, the lubricating oil may become contaminated and form sludge and foam. To prevent this condition, adjust the sealing steam accordingly.

8. Immediately verify operation of the trip valve by striking the trip lever. Close the main steam isolation valve as the turbine speed decreases. 9. Latch the resetting lever and slowly open the main steam isolation valve to bring the turbine back to 2533 rpm. Monitor the speed carefully during the low speed operation. CAUTION Do not leave the turbine unattended at any time during the initial start-up.

10. Listen for any unusual noises, rubbing, or other signs of distress in the turbine. Do not operate if any of these conditions are present. Monitor the turbine for signs of overheating and excessive vibration. 11. Close all drain valves when no signs of condensate are visible at drain lines. 12. After a turbine is operating, closely observe oil pressure and temperatures. Adjust sealing steam to maintain 3.5 kg/cm2G with no seal leakage seen. 13. If required, verify the overspeed trip by temporarily overriding the governor to actuate the overspeed trip mechanism. (this should be accomplished uncoupled from the pump) CAUTION Do not operate the turbine more than the rated trip speed of 3442 rpm. If the overspeed trip does not operate within 2% of the designated speed, shut the turbine down and make necessary adjustments.

Section 8 – Start-up Procedures

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a. Three consecutive, non-trending trip speeds within the required 2533 rpm to 3442 rpm range must be recorded to verify safe trip system operation. After a turbine trip and the speed decreases by 15 to 20% of rated speed,the reset lever may be latched and the turbine brought back up to speed. 14. Continue operating the turbine for approximately one hour, while carefully monitoring bearing temperatures, turbine speed, vibration levels, and listening for any unusual noises. 15. Confirm the lube oil pressure from the gear driven pump is normal and the auxiliary lube oil pump is shutdown or shut down the auxiliary pump if it did not shut down and place the switch in the auto-start position. CAUTION If the main pump is running too slow and the pressure is too low when the auxiliary pump is stopped, the BFW pump will trip.

Initial start-up of 104-JA pump should be carried out as follows (this will be the first pump started to bring the plant up from a cold state) : 1. Verify that the reservoir is filled with lubricating oil to an appropriate level 2. Set-up the lubrication system CAUTION Be sure that the lube oil temperature is above the vendor's recommended minimum before starting the pump. There is a small heater in the oil reservoir that should maintain the oil above this temperature.

3. When the driver reaches to its normal operating speed, the shaft driven oil pump feeds lubricant fully without using auxiliary oil pump. Stop the motor driven auxiliary pump after making sure then pump speed and supply pressure are normal then place back in “auto”. If the pump speed doesn’t attain normal speed, the auxiliary oil pump can’t be stopped. As long as the changeover switch is located at “Auto” mode, the auxiliary oil pump will run continuously. 4. Check if supply oil temperature is within the range required by the pump vendor. 5. Open the suction valve to the pump to warm and prime the pump. 6. Fill the pump with BFW. Vent the air from pump casing vents. Be sure that the pump is full by venting the pump and the seal piping. 7. Warm up the pump sufficiently prior to starting,by admitting BFW into pump.

Section 8 – Start-up Procedures

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WARNING To avoid severe thermal shock to the pump as a result of sudden liquid temperature changes, the 104-JA pump may need to be pre-heated prior to operation. The external casing temperature should be near the temperature of the BFW from 101-U at start-up. Preheating of a cold pump should be done at a rate acceptable by the pump vendor. Always leave the standby pump warm up line open during normal operation. 8. Close the discharge valves. 9. Fully open all suction valves and car-seal open the balance line, if applicable. WARNING The rotating parts of the BFW pump depend on BFW for internal lubrication and may seize if the pump is operated without liquid in the pump. Be sure that the pump is primed before starting. Shutdown the pump immediately if suction is lost to the pump. 10. Lock seal open the minimum flow recirculation line block valves. 11. Open the warm-up lines around SP-ARV-104J and SP-ARV-104JA 12. Test that all shutdown devices are in service and working properly. 13. Start the driver using the local H-O-A switch. 14. Confirm the lube oil pressure from the gear driven pump is normal and the auxiliary lube oil pump is shutdown or shut down the auxiliary pump if it did not shut down and place the switch in the auto-start position. CAUTION If the main pump is running too slow and the pressure is too low when the auxiliary pump is stopped, the BFW pump will trip.

Please refer to Vendor Installation and Operating Manual Doc. No. TBD. Be sure the following BFW paths are isolated: • upstream 123-Cs • to 160-C • TV-1553 • TV-1216 • TV-1116 • TV-1023 • TV-1044 • To 130-D

Section 8 – Start-up Procedures

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have all been isolated before opening the discharge isolation valve of the operating pump. Open the 2” globe valve around the pump discharge valve and pressure up the BFW system. Open the ¾ ” warm-up bypass line around the 104-J discharge to keep the pump warm for startup. 8.1.1.

103-JTC Surface Condenser for 103-JT

The procedure for commissioning the 103-JTC surface condenser follows: • Start a warming flow of LP steam to the lines to the inter and after-condenser jets as well as to the hogging jet. • Open cooling water to 127-C, if not already open, which is the supply cooling water for 103JTC and 103-JCC1/2. • Open the cooling water outlet valves for 103-JTC and 103-JCC1/2 to establish a flow of cooling water through the tubes. Bleed the air out of the system using high point vents. • Establish a level in 103-JTC hot well by flowing water from the demineralized water supply using line DM1085-2”. • Close the header isolation valve and the drain to the sewer downstream of LV-1018 and LV-1018 bypass. • Open the suction isolation valves from 103-JTC to the 123-J pumps. • Open the discharge isolation valves of both 123-J pumps. • Lock open isolation valve on minimum circulation lines for 123-Js • Open the seal flushing supply and return lines on both 123-J pumps, and the valves on suction lines for both pumps. • Close the pump casing drains to grade • Place LIC-1018 in automatic with an 85% setpoint. The valve will be closed. • Monitor LIC-1018 and level glass LG-1618 and stop filling when the level reaches 80% by closing the valve in line DM1085-2”. • Close the atmospheric relief valve, PRV-103JTC1/2, if open. • Check that the condensate lines are all isolated to 112-L • Start one 123-J pump and operate on minimum recycle flow. • Put a small flow of condensate from the 123-J discharge header to the PRV103JTC1/2 atmospheric relief valve seat to seal it. A very small trickle of water out of the overflow line is all that is required to assure sealing. • Isolate the inter and after condenser shell side condensate traps and open the drains to the sewer. • Place the LP steam to the hogging jet, one set of inter-condenser jets and one set of after-condenser jets in service to start pulling a vacuum on 103-JTC.

Section 8 – Start-up Procedures

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WARNING When placing the jets in service, ALWAYS open the steam supply valves FIRST and start a flow of steam to the jet THEN open the lines from the surface condenser (or from the inter-condenser jet exhaust as the case may be). When shutting down one set of condenser jets or the hogger jet, ALWAYS close the eductor isolation valves FIRST - THEN close the steam supply to the jet. Failure to do these operations in the right order will allow air to backflow into the surface condenser causing loss of vacuum and possible plant shutdown and turbine damage.

CAUTION After the steam is open to the jets on the inter and after-condenser, open the eductor line to the after-condenser jet FIRST then open the eductor line to the inter-condenser because the supply for the after-condenser jet is the exhaust of the inter-condenser jet. To take the jets out of service, reverse the order, inter first off, then after, then steam.

• When the condensate from the inter and after-condenser shell drains is clear, close the drains FIRST then open the bypasses around the traps to reclaim the water. Commission the traps after the condensate has had some time to clean the lines back to the condenser. WARNING Bypassing the condensate traps may cause a sudden loss of vacuum if air is drawn through the jet condenser into the 103-JTC. It is better to isolate the trap and take the condensate to the drain. Failure to do these operations correctly will allow air to backflow into the surface condenser causing loss of vacuum and possible plant shutdown and turbine damage.

• Maintain the level by opening the line DM1085-2” to fill, as required. • The hogging jet can be taken out of service as soon as the inter and after-condenser jets can handle the air leakage. This is not usually possible until all of the condensing turbines are in

Section 8 – Start-up Procedures

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service. The amount of air leakage is measured on a gauge on the inert outlet line of the after-condenser. NOTE Typically, the hogging jet can not pull the vacuum below about 178 mm Hg(a) and will limit the vacuum to that amount until it is taken out of service.

As 103-JT is started, the level will rise in the surface condenser. The water quality will NOT be good enough to use for exporting to external equipment or offsites for some time. If the level increases, open 3-way valve AV-1019 to the Ammonia cooling water basin until the quality is acceptable for use in other parts of the plant. Monitor the 103-JTC vacuum on PI-6340A/B/C and PG-1847. 103-JT turbine can be started as soon as the vacuum reaches 78 mm Hg(a). 8.1.2.

102-JTC Surface Condenser for 102-JT and 104-JT

102-JTC will need to be commissioned just prior to starting 102-JT and 104-JT. The procedure for commissioning the 102-JTC surface condenser is: • Open cooling water to 127-C which is the supply cooling water of 102-JTC and 102-JCC1/2 .  Open the cooling water inlet and outlet valves for 102-JTC and 102-JCC1/2 to establish a flow of cooling water through the tubes. Bleed the air out of the system using high point vents.  Start a warming flow of LP steam to the inter and after-condenser jets and to the hogging jet.  Establish a level in 102-JTC hot well by flowing water from the demineralized water supply using line DM6085-2”.  Place LIC-6018 in manual and close the header isolation valve and the drain to the sewer downstream of LV-6018. • Open the discharge isolation valve of each 119-J pump. • Open the suction isolation valves from 102-JTC to the 119-J pumps. • Lock open isolation valve on minimum circulation lines for 119-Js.  While the hot well is filling, open the seal flushing supply and return lines and the suction valves for each pump.  Monitor LIC-6018 and level glass LG-6618. Stop filling when the level reaches 90% by closing the valve in line DM6085-2”. • Close the atmospheric relief valve, PRV-102JTC1/2 , if open • Verify that the condensate lines to MP let down, Water Jackets, 124-Js are isolated. • Start one 119-J pump on minimum recycle flow.  Isolate the inter and after condenser shell condensate traps and open the drains to the sewer. Section 8 – Start-up Procedures

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Place the LP steam to the hogging jet, one inter-condenser jet and one after-condenser jet in service to start pulling a vacuum on 102-JTC. WARNING When placing the jets in service, ALWAYS open the steam supply valves FIRST and start a flow of steam to the jet THEN open the lines from the surface condenser (or from the inter-condenser jet exhaust as the case may be). When shutting down one set of condenser jets or the hogging jet, ALWAYS close the eductor isolation valves FIRST - THEN close the steam supply to the jet. Failure to do these operations in the right order will allow air to backflow into the surface condenser causing loss of vacuum, possible plant shutdown and turbine damage.

CAUTION After the steam is open to the jets on the inter and after-condenser, open the eductor line to the after-condenser jet FIRST then open the eductor line to the inter-condenser because the supply for the after-condenser jet is the exhaust of the inter-condenser jet. To take the jets out of service, reverse the order, inter first off, then after, then steam.

• Put a small flow of condensate from the 119-J discharge header to the atmospheric relief valve PRV-102JTC1/2 seat to seal it. A very small trickle of water out of the overflow line is all that is required to assure sealing. When the condensate from the inter and after-condenser shell drains is clear, close the drains FIRST then open the bypasses around the traps to reclaim the water. Commission the traps after the condensate has had some time to clean the lines back to the condenser.

Section 8 – Start-up Procedures

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WARNING Bypassing the condensate traps may cause a sudden loss of vacuum if air is drawn through the jet condenser into the 102-JTC. It is better to isolate the trap and take the condensate to the drain. Failure to do these operations correctly will allow air to backflow into the surface condenser causing loss of vacuum and possible plant shutdown and turbine damage.

Maintain the level by opening the line DM6085-2” to fill, as required. The hogging jet can be taken out of service as soon as the inter and after-condenser jets can handle the air leakage. This is not usually possible until all of the condensing turbines are in service. The amount of air leakage is typically measured on a gauge on the inert outlet line of the after-condenser. NOTE Typically, the hogging jet can not pull the vacuum below about 178 mm Hg(a) and will limit the vacuum to that amount until it is taken out of service.

Once a condensing turbine is placed in service, the level will rise in the surface condenser. The water quality will NOT be good enough to use for exporting to offsites for some time. If the level increases, open the 3-way valve AV-6019 to the Ammonia Cooling Water basin until the quality is acceptable for use in other parts of the plant. Watch the 102-JTC vacuum on PI-6067 on DCS with high alarm and PG-6775 locally.

8.1.3.

101-JTC Surface Condenser for 101-JT

101-JTC will need to be commissioned just prior to starting 101-JT. The procedure for commissioning the 101-JTC surface condenser is: • Open cooling water to 127-C which is the supply cooling water of 101-JTC and 101-JCC • Open the cooling water inlet and outlet valves for 101-JTC and 101-JCC to establish a flow of cooling water through the tubes. Bleed the air out of the system using high point vents. • Start a warming flow of LP steam to the inter and after-condenser jets and to the hogging jet. • Establish a level in 101-JTC hot well by flowing water from the demineralized water supply using line DM4085-2”. Section 8 – Start-up Procedures

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Place LIC-4018 in manual and close the header isolation valve and the drain to the sewer downstream of LV-4018. Open the discharge isolation valve of each 118-J pump. Open the suction isolation valves from 101-JTC to the 118-J pumps. Lock open isolation valve on minimum circulation lines for 118-Js. While the hot well is filling, open the seal flushing supply and return lines and the suction valves for each pump.

Monitor LIC-4018 and level glass LG-4618. Stop filling when the level reaches 90% by closing the valve in line DM4085-2”. • • • • •

Close the atmospheric relief valve, PRV-101JTC1/2, if open Verify that the condensate lines to 112-L is isolated. Start one 118-J pump on minimum recycle flow. Isolate the inter and after condenser shell condensate traps and open the drains to the sewer. Place the LP steam to the hogging jet, one inter-condenser jet and one after-condenser jet in service to start pulling a vacuum on 101-JTC . WARNING When placing the jets in service, ALWAYS open the steam supply valves FIRST and start a flow of steam to the jet THEN open the lines from the surface condenser (or from the inter-condenser jet exhaust as the case may be). When shutting down one set of condenser jets or the hogging jet, ALWAYS close the eductor isolation valves FIRST - THEN close the steam supply to the jet. Failure to do these operations in the right order will allow air to backflow into the surface condenser causing loss of vacuum, possible plant shutdown and turbine damage.

Section 8 – Start-up Procedures

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CAUTION After the steam is open to the jets on the inter and after-condenser, open the eductor line to the after-condenser jet FIRST then open the eductor line to the inter-condenser because the supply for the after-condenser jet is the exhaust of the inter-condenser jet. To take the jets out of service, reverse the order, inter first off, then after, then steam.

• Put a small flow of condensate from the 118-J discharge header to the atmospheric relief valve PRV-101JTC1/2 seat to seal it. A very small trickle of water out of the overflow line is all that is required to assure sealing. When the condensate from the inter and after-condenser shell drains is clear, close the drains FIRST then open the bypasses around the traps to reclaim the water. Commission the traps after the condensate has had some time to clean the lines back to the condenser. WARNING Bypassing the condensate traps may cause a sudden loss of vacuum if air is drawn through the jet condenser into the 101-JTC. It is better to isolate the trap and take the condensate to the drain. Failure to do these operations correctly will allow air to backflow into the surface condenser causing loss of vacuum and possible plant shutdown and turbine damage.

Maintain the level by opening the line DM4085-2” to fill, as required. The hogging jet can be taken out of service as soon as the inter and after-condenser jets can handle the air leakage. This is not usually possible until all of the condensing turbines are in service. The amount of air leakage is typically measured on a gauge on the inert outlet line of the after-condenser. NOTE Typically, the hogging jet can not pull the vacuum below about 178 mm Hg(a) and will limit the vacuum to that amount until it is taken out of service.

Section 8 – Start-up Procedures

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Once a condensing turbine is placed in service, the level will rise in the surface condenser. The water quality will NOT be good enough to use for exporting to offsites for some time. If the level increases, open 3-way valve AV-4019 to the Ammonia Cooling Water basin until the quality is acceptable for use in other parts of the plant. Watch the 101-JTC vacuum on PI-4067 on DCS with high alarm and PG-4775 locally.

Section 8 – Start-up Procedures

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79. General The Ammonia plant is ready for initial start-up after the preliminary preparations described and will proceed stepwise in sections with each section stabilized before proceeding to the next. After the Natural Gas supply is commissioned, the front end start-up can proceed. Nitrogen is to be circulated by the Feed Gas Compressor 102-J, through the Hydrotreater, Desulphurisers, Primary Reformer, Secondary Reformer, Secondary Reformer Waste Heat Boiler, H.P. Steam Superheater, High Temperature Shift, HTS Effluent Steam Generator / BFW Preheater, Low Temperature Shift Converters, Shift Effluent Exchangers, Raw Gas Separator, back to 102-J. This procedure assumes that there will be a plentiful supply of nitrogen available for circulation. The following are start up sequence after nitrogen circulation:  Warm up the Primary Reformer following the heating schedules for Primary Reformer refractory dryout and steam system boilout, if dryout has not already been done.  When the temperatures in the nitrogen circulation loop exit the Primary Reformer is in a range of 400-450 oC and the bed temperatures in HTS reactor are 50 oC above dew point of steam, introduce process steam, while opening HIC-1107 and closing FV-1001 simultaneously. 

Introduce feed gas then process air as the heating schedule permits.

        

Desulfurize the High Temperature Shift catalyst. Line out and put the CO2 removal system into service. Heat the LTS catalyst and put it on stream. Heat the Methanator and put it into operation. Start the Ammonia Refrigeration Compressor. Introduce process gas to the Synthesis gas driers and the cryogenic purifier. Warm up the ammonia synthesis loop. Start the Synthesis Gas Compressor. Start synthesis gas circulation in the ammonia synthesis loop and reduce the ammonia synthesis catalyst. Start the ammonia purge recovery system and burn remaining purge gas in the secondary fuel gas system.



8.1.4.

Prestart-up Conditions

Prior to initial start-up, the following conditions must be established: • The entire unit must be leak tested, purged free of oxygen and under a nitrogen blanket. If air has been introduced after the purging, successively pressure to and depressure from 3.5 Section 8 – Start-up Procedures

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kg/cm2G to reduce oxygen concentration below the levels as described earlier. • Verify that the following sections of the ammonia plant are isolated: o Ammonia Synthesis loop / Synthesis Gas Compressor o Ammonia Refrigeration and Recovery System o Cryogenic Purifier o CO2 Absorber o Methanator / Synthesis Gas Driers o Low Temperature Shift Converter o Feed Gas Supply lines. • The 14” valve on line NG1000 and 1” bypass are closed to 174-D • Close 14” block valve on NG-1001. • The isolation valves in line FG1002-10” are closed • Line up nitrogen circulation from the Feed Gas Compressor 102-J through the normal path to the start-up / nitrogen circulation line upto 142-D1 as follows: 2 ♦ 102-D is not part of the nitrogen circulation loop ♦ 108-DA/DB sample lines are all double block isolated. ♦ HIC-1108 hot vent valve on the outlet out of the Desulfurizers is closed with the upstream isolation valve also closed. ♦ Block valves on lines SG1014, SG2201, SG 1024, A1008 and NH1155 are closed with respective bleeds open ♦ 4” spool on line A1002 and 6” spool on A1009 from 101-J is removed and the lines blinded. ♦ MP steam from 130-D is isolated with the blind removed downstream of the check valve in line MS1006-16”. ♦ FV-1003, its by-pass air to secondary and the downstream XV-1212 valves are closed. ♦ FIC-1044, steam to secondary, line is warming but the isolation valves are closed. ♦ TIC-1004, internal bypass of 101-C should be open. ♦ TIC-1010, bypass of 102-C is fully open. ♦ TV-1011 to 103-C1 is open with TIC-1011 on manual. ♦ MOV-1007, 1008 inlet/outlet of the LTS 104-D2A/B are closed and blinds inserted for positive isolation. LTS reactors will be separately started up using 173-J. ♦ MOV-1009 LTS bypass valve is open. ♦ HIC-1021 and isolation valves are closed. ♦ PIC-1032 vent valve is closed and isolated. ♦ 143-C inlet and outlet cooling water isolation valves open ♦ FIC-1130A to automatic Flow path is: 101-BCF → 101-D → 108-DA/DB → 101-BCX → 101-B → 107-D → 103-D → 101C → 102-C → 104-D1 → 103-Cs → 104-D2A/B (if included) → 131-C → 105-C →106-C →142D1 → 143-C → 174-D → 102-J →101-BCF. Section 8 – Start-up Procedures

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CAUTION The LTS may still be warm at the onset of nitrogen circulation if the LTS was previously reduced or operated. Circulating nitrogen should not be sent to the LTS until the circulating nitrogen and LTS temperatures are equal. Flow through MOV-1009 bypass line.

•

Natural Gas may have been previous brought into the plant. Sample the nitrogen in the Feed Gas Knockout Drum, 174-D, on a regular basis to ensure that the isolation valves are not leaking.

8.1.5. •

Jacket Water

By this time, a flow of surface condenser condensate or demineralized water should be started to the water jacketing system and set up for automatic level control as follows: ♦ 107-D, Transfer line ♦ 103-D, Secondary Reformer ♦ The level alarms should all be verified in operation.

This system will remain in service from this point on. Maintain the water jackets full at all times during plant operation. WARNING It is imperative that water jackets be maintained full when heat is applied to the primary or secondary reformers. Failure to maintain adequate water levels in the water jackets could possibly lead to rupturing of the jacketing by uneven expansion or of the vessel by overheating. Loss of water flow to the jackets could cause undue stress in the transfer line piping to the secondary reformer. Starting a water flow to the jackets while they are hot can also result is serious damage. In the event of failure of the jacketing or loss of water, it is recommended that the reformers be taken out of service, until water jackets are again serviceable and water levels can be maintained.

•

Close all jacket drain valves to the sewer, place the following control valves and the controllers in automatic at their normal setpoints on: ♦ LIC-1142 to 103-D ♦ LIC-1143 to 107-D

Section 8 – Start-up Procedures

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Put PIC-1113 in manual and close the valve then open the isolation valves on PV-1113. Slowly open PIC-1113 manually and start filling the jackets with demineralized water. Once all jackets are full and the level is controlled by the valves, place PIC-1113 in automatic and set the setpoint at the current pressure to the jackets. Adjust the setpoint on each of the jacket LIC controllers to just a little below the overflow level.

8.1.6.

Fill 141-D

Establish a low working level in 141-D as follows: • Verify BFW to 123-Cs is isolated • Verify TV-1011 A/B to minimum opening • Verify FV-1072 A/B upstream of 103-C2 are closed • Lock open the isolation valve from 123-Cs to 141-D Use FIC-1072 manually to open the valve and fill 141-D to a low, normal level then close the valve. 8.1.7.

Nitrogen Circulation

The initial heating of the new catalyst in the reforming and CO shift conversion systems is accomplished using nitrogen as the heating medium. When the catalyst beds have been heated with nitrogen to a level above the condensation temperature of steam, steam will be substituted for the nitrogen. WARNING All the catalysts used in the ammonia unit function in the reduced state and must never be exposed to air or oxygen while in the reduced state except under carefully controlled conditions. Nickel reforming catalyst are not to be exposed to air (oxygen) at temperatures above 60°C while in the reduced state, except under carefully controlled conditions, as the heat released on oxidation of nickel may be sufficient to elevate temperatures which can fuse the catalyst and possibly damage tubes or vessels.

In the course of a normal shut down of the reforming system, the catalysts are oxidized by steaming at operating temperatures. This oxidation is sufficient for most shutdown purposes Section 8 – Start-up Procedures

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provided the catalyst is cooled to 200°C or lower before exposure to air. However, steam oxidation results in only about 80% oxidation of the catalyst. CAUTION Before and during nitrogen circulation, the circulating nitrogen must be analyzed to ensure hydrogen and carbon monoxide content is below 0.1 mole %.

High temperature shift conversion catalyst may be heated with nitrogen to a temperature no greater than 250°C at pressures no greater than 5.0 kg/cm2G (the temperature maximum decreases as pressure increases) to avoid methanation should H 2 or CO be present in the nitrogen. For the first start-up, the shift catalyst is new and oxidized. Therefore, it is heated with nitrogen to a temperature of 250°C before the heating medium is switched to steam. For subsequent startup, the catalyst should be kept warm, 250°C, with a warming nitrogen circulation during the shut down so that preliminary heating is not required. NOTE Subsequent start-ups will require nitrogen circulation only if the catalyst beds have cooled below the dew-point for the steam at start-up conditions. Short shutdowns do not require nitrogen circulation

CAUTION Wetting the catalyst may leach the binder and weaken the catalyst. This condition should be avoided in the interest of catalyst life.

Pressure the nitrogen circulation loop with nitrogen by opening the 1.5” isolation valve at 174-D inlet N1006, 102-J discharge N5000 1 ½” and inlet to 101-B radiant section line N1001-1.5”. N1002- 1½” can also be used if the LTS is in the circuit. Pressure the nitrogen circulation loop to the nitrogen header pressure, approximately 5.0 kg/cm2G, and leave the isolation valve full open. Start the Feed Gas Compressor 102-J following the vendor's instructions. 8.1.8.

Primary Reformer Warm-up / Dryout

Section 8 – Start-up Procedures

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Establish nitrogen circulation from the Feed Gas Compressor 102-J through the following: • Feed preheat Coil 101-BCF • Desulphurisers 101-D and 108-DA/ DB • Primary Reformer Mixed Feed Preheat Coils, 101-BCX • Primary Reformer Catalyst Tubes, 101-B • Transfer Line, 107-D • Secondary Reformer, 103-D. • Secondary Reformer Waste Heat Boiler, 101-C. • HP Steam Superheater, 102-C. • High Temperature Shift Converter, 104-D1. • HTS Effluent Steam Generator, 103-C1. • HTS Effluent BFW Preheater, 103-C2. • LTS Converter, 104-D2A/B (Initially bypassed until LTS catalyst bed temperatures are equal to the circulating nitrogen, if warmer to start.). • LTS Effluent / BFW Preheater 131-C • CO2 Stripper Reboiler 105-C • LTS Effluent / Demin Water Exchanger 106-C • Raw Gas Separator 142-D1 • Back to the 143-C, 174-D and Feed Gas Compressor 102-J suction. Increase the nitrogen circulation rate as high as possible. Ensure that there are no vents open in the circulation loop and the pressures are maintained and stabilized throughout the system. The Primary Reformer warm-up / dryout and steam system boilout can be carried out at the same time as the thermal curing of the Primary Reformer refractory, if not previously completed. Open to about 50% on all of the burner combustion air duct header dampers. Check out the instrumentation and shutdown circuits for the primary reformer fuel gas systems. After the induced draft fan has established reliability and the fuel gas systems checked out, arch burners in 101-B can be ignited, when required, for start-up. Start the Reformer Induced Draft Fan, 101-BJ/BJA as described in the vendor’s IOM instruction manual. Check adequate draft is available at about -15 mm H2O. Start 101-BJ1/BJ1A as per vendor instructions and maintain balanced draft at about -5mm H2O.

Section 8 – Start-up Procedures

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80. Commission 101-BJ/BJA, 101-BJ1/BJ1A - ID / FD Fans Start up the primary reformer ID (Induced Draft) and FD (Forced Draft) fans per the vendor's recommendations. Check out all instrumentation and shutdown circuits for the primary reformer fuel gas systems. After the fans and drivers have established reliability and the fuel gas systems are checked out, arch burners in 101-B can be ignited, when required, for start-up. CAUTION Do not run the ID or FD fan set with lubricating oil temperatures below the recommended minimum temperature or lack of good lubrication may cause severe equipment damage. • • • • • • • •

2

Set HIC-1019A and HIC-1119 to close the dampers at 101-BJ/BJA inlet to the minimum stop. Start 101-BJ/BJA and confirm all operating conditions are normal, including proper lube oil pressure and flows. Adjust HIC-1019A /1119 to maintain desired draft Match the set point on PIC-1019 to the actual draft in the furnace and put the controller on automatic. This will help avoid sudden changes in fan speeds. Set HIC-1855A/B to close the inlet dampers for 101-BJ1/BJ1A. Start 101-BJ1/BJ1A and confirm all operating conditions are normal, including proper lube oil pressure and flows. Adjust HIC-1855A/B to maintain desired combustion air pressure Match the set point on PIC-1855 to the actual combustion air pressure and put the controller on automatic. This will help avoid sudden changes in fan speeds.

Please refer to Vendor Installation and Operating Manual Doc. No. TBD. With the FD fan in service and combustion air pressure / flow controlled by PIC-1855 the draft must be monitored and PIC-1019 adjusted to maintain desired draft in reformer and convection section. Place PIC-1855 in automatic and balance the reformer draft with PIC-1019 8.1.9.

Commission Natural Gas

CAUTION It is assumed that the system has been precommissioned and nitrogen purged to an oxygen content of 0.5% or less before starting to bring gas into the system. It also assumes are vent and drains valves are isolated.

Section 8 – Start-up Procedures

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Align the front end gas section as follows: • Set PIC-4101A setpoint to ~5 kg/cm2G and place in automatic. • Close the inlet isolation valves to 174-D • Close the isolation valve to 101-B superheater and tunnel burners fully • Close isolation valve to start up heater 102-B fully • Close the isolation valves to PV-1002A/B fully • Set PIC-1001B setpoint to ~2 kg/cm2G and place in automatic. • At this time 102-J is being used for Nitrogen Circulation. Ensure, circulating nitrogen pressure is higher than NG pressure at PIC-4101A at all times. Open the 1” bypass around the battery limit Natural Gas isolation valve and pressure up the front end with gas. Walk around and check for leaks on all equipment and instrumentation connections. As the pressure reaches 2 kg/cm2G, PIC-1001B should close and as the pressure reaches 5 kg/cm2G PIC-4101A should close. 8.1.10.

101-B Arch Burners

Close PV-1002A/B with PIC-1002 in manual. Slowly open the isolation valves to PV-1002A then on line FG1002-10” and pressure the line to PV-1002A/B. Manually use PIC-1002 to pressure the line to XV-1220A to ~ 1.4 kg/cm2G. Place PIC-1019 in automatic and slowly adjust the setpoint to ~ –10 mmH 2O minimum, if not already so. Place PIC-1855 in automatic with the setpoint at the current exhaust pressure, if not already done. Slowly start opening the combustion air dampers to each row section of the burners. Adjust the setpoint on PIC-1855 to a higher value to force more combustion air to the burners if required. Use the individual combustion air header dampers to balance the combustion air flows. Initiate the purge sequence for the main 101-B burners as described in Section 7 of this manual. Light a limited number of small, equally spaced burners in the Primary Reformer, 101-B. Follow the Primary Reformer refractory curing procedure that is provided in Section 6, Unit Conditioning, of this manual if the dryout is to be completed at this time. All of the reformer convection coils have been designed to tolerate the low or no flow conditions encountered during Section 8 – Start-up Procedures

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lightoff and heating. Initially vent any generated steam to the atmosphere using the 141-D drum vent or HV-1048 on the HP steam header. Adjust the air flow to each of the burner rows as required using the manual dampers to maintain adequate combustion air flow to the burners. Watch the draft pressure in 101-B radiant box as burners are being lit so that high pressure does not trip the firing. CAUTION The heat up rate must be limited to 25°C /h until nitrogen heating has been completed. The maximum differential temperature between the heating medium and the catalyst inlet temperature is 100°C. The maximum temperature the primary and secondary reformer catalyst can be subjected to in the presence of nitrogen is 260°C with the limit on the HTS being 250°C.

8.1.11.

HP Steam Drum 141-D

When the process line warm-up temperature at TIC-1011, 103-C2 outlet, is about the same temperature, 130°C, as the boiler feed water, at 101-U on TW/TG-1772A, BFW flow to 141-D can be brought forward from 104-J to maintain a warm boiler feed water flow to 141-D to heat all steam generation equipment evenly. FV-1072B can be used manually for this until steam generation is high enough to allow use of FV-1072A as the flow path to maintain the level in 141D. The 101-C downcomer drain and 141-D blowdowns should be open to provide circulation. Bring the 101-B tunnel outlet temperatures to 125°C to 150°C at a rate of 15°C /h as a starting point for the heating program. Stabilize and hold this temperature for two hours. From this point on during heat-up periodically check piping, spring supports, spring hangers, and stops to ensure correct growth and support of piping. 8.1.12.

101-C Waste Heat Boiler Circulation

101-C has a provision for injection of MP steam on shell side, through MS5001-2”. The line should be commissioned for commencing heating of 101-C water in accordance with boiler start up manual. The heating should be started at a slow rate initially ensuring that ‘knocking’ doesn’t occur inside. Its a critical requirement to preheat the boiler water prior to introduction of process steam to 101-B in order to avoid thermal stresses on boiler tubes in case the shell side is not preSection 8 – Start-up Procedures

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heated. As the MP steam injection is direct enetering the water side, it is likely that the level in 141-D will ‘swell’ as the steam condenses. At some point in the heat up of 101-B, the 101-C waste heat boiler will begin circulation and steam generation. This will most likely be after process steam is introduced. As 141-D steam pressure increases to 3.5 to 5.0 kg/cm2G, start throttling the 141-D steam drum atmospheric manual vent to increase the pressure further. As 141-D pressure increase, use PIC-1036 to line up the steam to the HP header. The steam now produced can be vented manually through HV-1048 vent downstream of the superheater coil OR it can be pushed to the MP steam header if the pressure is adequate. The HP steam vent should be throttled to slowly increase the HP pressure while enough flow is continued to maintain coil temperatures below their maximums. Continue to maintain a continuous blowdown from the 141-D steam drum to 186-D, as required using SP-BDV141. As steam generation begins, continually drain the condensate out of the HP steam line, 102-C exchanger, and the superheater coil. The steam superheater coil is initially without flow during the Primary Reformer warm-up. Flow will begin when steam production starts in Steam Drum, 141-D. Steam can be vented at HV1048. Maintain the Primary Reformer Superheat Coil outlet temperature below the design temperature 510°C using TIC-1005 / TIC-1005A (TIC-1553) if required. Watch TI-1552 and TIC1553 to monitor the low temperature coil outlet as well. Increase and hold the Primary Reformer arch temperatures per the procedural steps and do not exceed the heat-up rate for the Primary Reformer transfer line, the Secondary Reformer catalyst / refractory and the Secondary Reformer Waste Heat Boiler as specified by the respective refractory and catalyst suppliers. 8.1.13.

2

Steam Drum Operating Parameters

PT PUSRI should contact their water treatment vendor for their chemistry and operating parameters but typically,The following parameters are generally accepted for high pressure boiler operations (ASME) and [formerly] Betz):) Boiler Feed Water • Dissolved O2 <0.007 mg / L Section 8 – Start-up Procedures

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Total Fe ≤ 0.01 mg / L Total Cu ≤ 0.01 mg / L Total Hardness = Not Detectable pH = 9.0 to 9.6 Non-volatile TOCs = as low as possible, <0.2 mg / L Oily Matter = as low as possible, <0.2 mg / L

Steam Drum Water • TDS < 100 ppm • SiO2 < 1.0 ppm • Specific Conductance ≤100 µmhos • PO4 = 4 to 10 ppm • pH = 8.9 to 9.8 • Free Hydroxide Alkalinity = Not Detectable 81. Introduction Of Steam When Primary Reformer tube exit circulating nitrogen temperature reaches 400-450oC and the 104-D1 HT shift catalyst bed temperature reaches 200°C and 103-D temperatures are in the range of 200°C to 250°C, process steam can be started and the nitrogen circulation will be stopped for Primary Reformer and downstream while continuing heating 101-D and 108-DA/DB. Prior to introducing steam to 101-B, bypass the LTS (if included in circulation) by first opening MOV-1009 on line PG1022 to 131-C then closing MOV-1008 inlet to the LTS and outlet MOV1007 on line PG1012. Open the 1.5” nitrogen valve on line N1002-1.5” (if not already open) and maintain the LTS under a nitrogen blanket. Ensure the MP steam line is hot by opening the 1” bypass valve of the 16” isolation valve on line MS1006-16” and heating the line prior to opening the 16” valve. Open all drain valves on the line to the primary reformer inlet and drain until no condensate is present at any of the drain valves. Place FIC-1002 in manual and close both FV-1002 A and B fully. Open the main isolation valve and close the bypass. Manually slowly start a flow of process steam to 101-B mixed-feed preheat coil through FV-1002A. Gradually increase process steam flow to ~11,500 kg/h (8.3% of design), while increasing reformer firing. Place FIC-1002 in automatic as soon as stable flow is attained. As soon as the process steam is introduced in 101-B, use of 102-J for nitrogen circulation will be Section 8 – Start-up Procedures

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restricted to heating 101-D and 108-DA/DB. Close nitrogen supply line N1001. At the same time make sure to close FV-1001, HV-1061, XV-1201 to 101-B. Open the bleed between XV-1201 and FV-1001. At this time the heating of 101-D and 108-DA/DB should be continue by opening HIC1107. Open PV-1032 isolation valve. Set PIC-1032 on automatic to maintain the backpressure at about 7.0 kg/cm2G and switch the vent to send the Process Steam out through PV-1032. CAUTION When increasing the system backpressure and introducing steam, do not come within 20°C of the saturation temperature with the backpressure - see the following chart.

Lock open the 10” isolation valves of FV-1044 in line MS1017-10” and establish a precautionary air sparger steam flow of ~2,000 kg/h through bypass of FV-1044. Put FIC-1044 into automatic mode.

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Section 8 – Start-up Procedures

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82. Commission Refrigeration System The refrigeration system was previously purged with inert gas to less than 0.5% oxygen and nitrogen pressured to approximately 0.5 kg/cm2G. 2 Start a SMALL flow of ammonia through piping NHL1034 and NHL1156 from Tie-in OEP to 149-

D. Do NOT open the valves fully until a level indication is seen in 149-D to avoid potential subcooling and damage to the vessel. The initial cool down of the NH3 system will be very slow as the metal temperatures are hot and the incoming liquid NH3 is at -33°C. Until 149-D starts to cool down there will be a lot of flashing from liquid to vapor and the pressure will increase rapidly. Watch the pressure at local PG-1648 and PIC-1109, on the vapor exit 149-D, and do not exceed 17 kg/cm2G to remain within design limits. As the pressure increases, unblock PV-1109 and set PIC-1109 on automatic at 3.5 kg/cm2G to vent to the NH3 flare header using PIC-1038 through PV-1038B. Ensure the LP scrubber 123-D is bypassed if not in service and only PV-1038B is in service. PIC-1038 should be in manual and fully open at this time. Some of the nitrogen atmosphere in the refrigeration system will be displaced by the incoming ammonia vapor by opening the relief valve bypass to the NH3 flare header on 120-Fs and venting 149-D. Nitrogen is heavier than ammonia and, because of this, the nitrogen will settle below the ammonia vapors and may not be fully vented until 105-J is started. When the nitrogen appears displaced, increase the setpoint of PIC-1109 to 15 kg/cm2G (up to 17 kg/cm2G is acceptable until 105-J is started) to avoid lifting the relief valves. The system pressure will be equal to the vapor pressure of liquid ammonia at the existing ambient / equipment temperature. When the nitrogen content has been reduced and the system is under pressure, a high liquid level of ammonia will be established in 149-D by sending ammonia through line NHL1156. After a high level has been established in 149-D, close the isolation block valves in the fill line NHL1156 and open the bleed valve contained between the block valves. 2

Commission 120-J  move to 8.22.10 Start the 120-J pump as follows: • Open the suction isolation valves to the pump. • Prime the pump if necessary by opening the bypass around PRV-120J • Isolate the following valves: Section 8 – Start-up Procedures

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NHL1147 to 124-C

• Open the discharge valve then start the pump. 2

Reforming Catalyst Reduction and Desulfurization Increase the process steam rate to about 33% of design or 45,500 kg/h on FIC-1002. Increase the firing of the 101-B reformer until an outlet temperature of 800ºC is reached on TIC-1314. Hold 101-B tube outlet temperature at 800ºC and the High Temperature Shift Converter inlet at about 345ºC or as high as possible for about 1 hour by opening TV-1004 fully and adjusting (closing) TV-1010. Then gradually increase ammonia injection to a steam / ammonia ratio of 20 / Reforming catalyst reduction/desulfurization takes between 12-24 hours for full reduction, but only partial desulfurization of the HT shift catalyst is achieved at this time. Upon completion of the reforming catalyst reduction and desulfurization, maintain the Primary Reformer outlet temperatures at 800ºC but reduce the HT shift inlet temperature to 315ºC to prevent the release of any more sulfur. While the front end desulfurization is in progress, set up the LTS effluent cooling section as described below.

83. Start OASE Solution Circulation Prior to introducing the high temperature shift effluent gas through the CO2 removal system, controlled circulation of OASE solution must be established above 60% of normal flow rates. If the instruments and alarms associated with the system were not commissioned during the earlier circulation, it should now be done. Initially, the rich OASE solution from the bottom of the absorber will be transferred to the stripper by employing the bypass valves around the hydraulic turbine and level control of the absorber will be by LIC-1004 through LV-1004A / B. The hydraulic turbine will eventually be put in service when the system is lined out. CAUTION Do not start Process Gas flowing through the LTS heat recovery system until OASE solution circulation is stable.

Section 8 – Start-up Procedures

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Levels of solution should have been established previously in the 121-D absorber and the 122D2 stripper after chemical cleaning. When purging and the system pressure have been confirmed ensure MOV-1011, its bypass valve and PIC-1005 are all closed. Set PIC-1104 on automatic at 0.8 kg/cm2G and verify that PV-1104A/B are fully closed. With process gas available, slowly open the bypass valve around MOV-1005 in line PG1015 and pressure the 121-D and its overhead piping with process gas until the pressure is equalized. If process gas is not yet available, nitrogen through line N1003 can be used. Start the Reflux Water System Ensure cooling water is flowing through 110-C CO2 Stripper Overhead Condenser. Establish a 50% level in 153-D, with Demineralized Water using FIC-1013 on manual. Start the 110-J pumps as follows: • Lock open the minimum flow lines from each 110-J pump to 153-D. • Open the suction isolation valves to the pump and vent the pumps until liquid flows from the vents to assure removal of all gases. • Isolate the following valves: o FV-1016 to 122-D1 o

FV-1018 to 121-D

o

FV-1030 to 163-D

o

XV-1117 to the pump seal flushes CAUTION Do not start Reflux Water System or overhead flushes until Process Gas is flowing through 121-D or the solution will be diluted.

• Start one pump and open the discharge valve as the motor comes to full speed. • Maintain the pump running on minimum flow to supply pump seal flush water through XV-1117 to all of the OASE pump seals. Before starting solution circulation: • Ensure that reflux condensate or OASE is flowing to the OASE seal flush system and that all pump seals have seal flush solution available.

Section 8 – Start-up Procedures

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• Lock open XV-1117 isolation valves then push the DCS handswitch HS-1117 to open XV-1117 to direct water to the pump seal flush system, if the valve is not already open. CAUTION Limit the use of water to flush the OASE circulation pump seals or the solution will be diluted. Bring 108-J / JA on line and use OASE solution to flush the seals of the other pumps as soon as possible.

• • • •

Ensure all alarms and shutdowns have been commissioned and tested. Pressure 163-D with nitrogen with PV-1039B isolated. This MAY require establishing a level in 163-D prior to starting the nitrogen pressuring Place LIC-1046 on 163-D in automatic at the normal operating level. 121-D is pressured up to 20 kg/cm2G to 22 kg/cm2G with process gas as described earlier. WARNING When pressurizing 121-D with either process gas or Nitrogen for circulation, a continuous nitrogen purge MUST be started on the CO2 stripper, 122-D2, using the nitrogen supply line N3410 or hose connections to the stripper. As OASE solution circulates, it will absorb gas from 121-D and significant concentrations of hydrogen or Natural Gas can collect in 122-D1 / D2 and create an explosion risk. The nitrogen purge will continue until a forward flow of process gas is started through 121-D. Stop nitrogen purge once CO2 is being produced by the stripper / LP flash column.

•

•

• •

Using 111-J, bring OASE solution from 114-F to 122-D1 through 104-L and establish a high level in the drum. Continue this transfer while establishing circulation in the system until all normal levels are established. Start a 117-J / JA pump per the procedure flowing through 112-C and establish a level in 122D2 on LIC-1042 using FIC-1017 with it closed to its minimum flow opening. This will have to be a batch procedure until circulation is established due to the minimum flow opening on FV1017. Start a flow of ~40 ton /h with 117-J / JA pump to 104-L back to 122-D1. Minimize the flow to 122-D2 through FIC-1017 to avoid over filling 122-D2 until a 108-J is in service. Once a high level is indicated in 122-D2, start pump 108-JA through FIC-1014 to 121-D with it closed to its minimum flow opening. This will have to be a batch procedure until circulation is established due to the minimum flow opening on FV-1014. Adjust the flow of OASE solution

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to 122-D2 through FIC-1017 to maintain the level in 122-D2 and 122-D1. Once a 108-J can be left on full time, switch the seal flush flow over to OASE from 108-J discharge and close XV-1117 by pressing HS-1117. Leave the valve setup for automatic functioning. Continue the import from 114-F to 122-D1 and the small flows as indicated above until a high level is seen in the bottom of 121-D. Put LIC-1004 in manual and set to close the valves. Reset HS-1052 to open the trip valve XV1052A and allow the level valves to be operated. Open the isolation valves on LV-1004A and B. Open LIC-1004 manually to establish a flow of OASE solution from 121-D to the HP Flash Column, 163-D through LV-1004A / B, bypassing 107-JAHT. Maintain LIC-1046 in automatic at a normal level to establish a flow of OASE solution from 163-D to 122-D1 as the level increases in 163-D. Continue this filling and circulation until normal levels are achieved and flows are stable after increasing to 60% of design. This will require batch operations starting and stopping the pumps. CAUTION Most of the large horsepower motors will have a limited number of starts per hour. Do not exceed the vendor’s recommended number or severe motor damage could result.

•

•

Once the lean solution flow is stable and the levels increase to slightly higher than normal, start 107-JC and establish a flow of semi-lean OASE solution to 121-D through FIC-1005 with it closed to its minimum flow opening. Increase all flows to ~60% of design in steps to attain stable conditions. o FIC-1017 = 410 ton/h o FIC-1014 = 380 ton/h o FIC-1005 = 1,870 ton/h o FI-1113A = 40 ton/hr

Initial start-up of a 117-J / JA pump should be carried out following the vendor’s instructions in their IOM manuals:

Section 8 – Start-up Procedures

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WARNING To avoid severe thermal shocks to the pump as a result of sudden liquid temperature changes, the 117-J pump may need to be preheated prior to operation. Preheating of a cold pump should be done at a rate acceptable by the pump vendor. Always leave the standby pump warm up line open during normal operation.

• • • • • •

• • • • • • • •

Fill the bearings with lubricating oil to an appropriate level. (Lubricate the pump with the designated oil without fail, since the oil has been drained before shipment.) Check connections of the cooling, flushing, or sealing pipes. Open the suction valve to the pump to warm and prime the pump. Check that all safety shutdown devices are in service and working properly Open the isolation valves inlet and outlet of 112-C. Fill inlet strainer and vent. Confirm that the suction valve is opened fully and the discharge valve is closed completely. Prime the pump by opening the suction isolation valve then vent the pump until all of the gases are vented and liquid flows from the vent Establish flushing flow to the seals of both pumps at a rate per the vendor’s instructions using reflux water from 110-Js until 108-J is in service then switch to OASE. Open warming lines around the discharge check valves for both pumps. Open the discharge valve. Start the motor and when the pump is up to speed, fully open the discharge valve. Do not let the pump run with discharge valve closed. Slowly increasing the flow to 410 ton /h (60% of design) to 122-D2. Monitor the level in 122D1 to ensure a constant suction to pump 117-J. The strainer in suction line must be checked periodically to prevent cavitation in the pump. Place spare 117-J pump in stand-by with suction, discharge and warming valves open. Place 104-L in normal service as filling from the 111-J is being done.

Initial start-up of a 108-J / JA pump should be carried out following the vendor’s instructions in their IOM manuals: WARNING To avoid severe thermal shocks to the pump as a result of sudden liquid temperature changes, the 108-J/JA pumps may need to be preheated prior to operation. Preheating of a cold pump should be done at a rate acceptable by the pump vendor. Always leave the standby pump warm up line open during normal operation.

Section 8 – Start-up Procedures

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Fill the bearings with lubricating oil to an appropriate level. (Lubricate the pump with the designated oil without fail, since the oil has been drained before shipment.) Check connections of the cooling, flushing, or sealing pipes. Lock open the suction valve to the pump to warm and prime the pump. WARNING The pump must not be run unless it is completely filled with liquid, as there is danger of injuring some of the parts of the pump which depend upon liquid for their lubrication. Air vent valve on top of the pump case should be opened during filling to allow the air to escape. Make sure the suction valve is wide open.

• • • • • •

• • •

•

•

Place the pump seal flush system in service by opening the seal flushing supply from the reflux condensate system as per vendor’s instructions. Lock open the pump discharge valve open warm up bypass valve around the discharge check valve. Open the cooling water supply and return to the mechanical seal coolers. Place FIC-1014 controller on manual and close to a minimum flow opening of 470.8 ton / hr. Set the local switch to “Hand” to start the motor unit. FIC-1014 will be open some for minimum flow needs and can be further opened gradually while monitoring the discharge pressure. Do not run the pump with no flow except for a very short time, it may cause the liquid temperature to rise in the pump to produce vapor or accelerate corrosion in case of chemical solutions. Be careful to maintain the flow above the minimum flow of 470.8 ton /h except during start-up. FV-1014 minimum opening should be set at this flow rate. Check the suction pressure, immediately after starting. Any unusual drop in pressure may indicate that the suction strainer should be cleaned. Set up the spare 108-J being sure that the warm up bypass valve is open around the discharge check valve. Control the flow rate on FIC-1014 at a low enough value so that a level is always apparent in the 122-D2 stripper bottom. Rates will have to be adjusted for maintenance of good levels in the stripper trapout pans and will eventually be controlled at 60% of normal design about 380 ton / hr. Make sure that pressure is maintained on the absorber sufficient to provide good transfer to 163-D and that the pressures in 163-D is adequate to maintain flow on to 122-D1. As the flow rate on FIC-1017 from the 117-J, is increased, the flow at FIC-1014 will need to be increased to maintain a normal level in 122-D2. Increase FIC-1014 setpoint as necessary. Establish seal flush flows from 108-J / JA discharge and discontinue the use of demineralized water as seal flush medium for 117-J / JA, 108-J / JA, 107-JAHT and 107-JA / Section 8 – Start-up Procedures

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JB / JC by opening the isolation valve from the 108-J discharge line to line MEA1064 and resetting solenoid XY-1117 using DCS handswitch HS-1117 , closing XV-1117, if not already done. When these circuits have been stabilized and 122-D1 has sufficient level on LI-1041, start a flow of semi-lean solution to 121-D with 107-JB or JC through FIC-1005 controlling FV-1005. CAUTION 107-JA can not be placed in service until the OASE circulation rate is 90% or greater. There is not enough horsepower developed by the hydraulic turbine at lower rates to keep adequate flow from the 107-JA pump. Be aware that any upset in the 121-D level that reduces the flow through this system below about 90% will also reduce the semi-lean flow through FIC-1005 as well causing the spare pump to auto-start.

• Place FIC-1005 controller on manual and close to the minimum flow opening. Please refer to Vendor Installation and Operating Manual Doc. No. TBD.

WARNING To avoid severe thermal shocks to the pump as a result of sudden liquid temperature changes, the 107-J pumps may need to be pre-heated prior to operation. Preheating of a cold pump should be done at a rate acceptable by the pump vendor. Always leave the standby pump warm up line open during normal operation.

Initial start-up of a 107-JB / JC pump should be carried out following the vendor’s instructions in their IOM manual. Control the flow rate on FIC-1005 at a low enough value so that a level is always apparent in the 122-D1. Rates will have to be adjusted for maintenance of good levels in the stripper trapout pans and will be controlled at 1,870 ton / hr, 60% of normal design. Make sure that pressure is maintained on the absorber sufficient to provide good transfer to the stripper. The normal split of flow is: • Semi-Lean - 83% of total circulation • Lean - 17% of total circulation Section 8 – Start-up Procedures

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These rates will be adjusted after process gas is directed through the 121-D absorber to effect stable operation and good CO2 removal. Switch the flush medium in the 117-J, 107-J and 108-J pumps over to OASE solution and isolate the reflux condensate flush. Place XV-1117 in standby mode by latching XY-1117 solenoid valve, if not already done. 84. Natural Gas Hydrogenation and Desulfurization CAUTION Carbon oxides present in nitrogen / hydrogen stream for desulfurization of the Natural Gas can provoke a "methanation" reaction on contact with the cobalt-molybdenum catalyst. Therefore, after the HT shift converter catalyst has been partially desulfurized, the effluent gas stream (steam, hydrogen and nitrogen) is routed through the LTS effluent cooling system, CO2 removal system and methanator to provide recycle hydrogen suitable for the hydrogenation and desulfurization of the feed gas.

Reformer / Converter Section : • Steam to 101-B Primary Reformer mixed feed coil, through reformer radiant section --> Secondary Reformer --> HT shift converter --> LT shift bypass --> LT shift effluent cooling system --> 142-D1 (Raw Gas Separator) --> vent at PIC-1040 CO2 Absorber inlet. • • • • • • • • • • • •

TIC-1010 set for 315ºC inlet the HTS MOV-1009 closed MOVs-1007 and 1008 closed TIC-1011 set for 190ºC and associate valves ready for service PIC-1032 controlling on automatic as described earlier PIC-1040 set for 9.5 kg/cm2G with valve ready for service OASE circulation established at 60% as described below 105-C bypass line open fully TI-1352 in manual with TV-1352 open fully 142-D1 level controls ready for service as described below 121-Js and minimum flow lines to 142-D1 isolated MOV-1005 and bypass closed and isolated to 121-D

Up to this point, steam has been venting at PIC-1032 holding a backpressure of 10 kg/cm2G. Slowly open MOV-1009 and start a flow of steam with hydrogen / nitrogen towards the LTS heat Section 8 – Start-up Procedures

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recovery system. Watch 142-D1 level and maintain a normal level draining to the offsites. When the pressure increases to near 9 kg/cm2G at PIC-1040, it will start to open to hold the pressure. PIC-1032 will close a little. There will be a lot of condensate and very little hydrogen gas in comparison. If the level valve becomes too far open, increase the backpressure on PIC-1032 / PIC-1040. Watch the lean OASE solution temperature and adjust 108-C cooling water accordingly.

2

Natural Gas Feed System: • From Battery Limits  to 174-D knockout drum  102-J  101-B Primary Reformer Feed Gas preheat coil (bypass CLOSED) --> through the 101-D Hydrogenator then desulfurizers • PIC-4101A in manual and closed with the bypass closed and the associated valves ready for service • Open 174-D OUTLET to lines NG1500 / NG1001 • Place TIC-1305 in automatic at 371ºC with associated valve ready for service • At this time, 102-J is circulating nitrogen across 108-DA/B in series flow operation • HIC-1108 closed with associated valve ready for service • HIC-1061 and FIC-1001 closed and downstream XV-1201 valve closed. Slowly pressurize Natural Gas to PV-4101A by slowly opening the 1” battery limit pressurizing bypass. Once the pressure is equalized, open the isolation valve and close the bypass.

2

Slowly pressurize Natural Gas to 102-J suction through 102-D by slowly opening PV-4101A. Slowly close HIC-1107. At this stage part flow will be diverted through FV-1130. However, prior to opening the Natural Gas to 102-J, confirm the 101-D and 108-DA/DB temperatures are above 350oC. As a minimum, 101-D and 108-DA should be above 350oC. Keeping a watch on 101-BCF temperatures, open HV-1108 if required. Adjust the Primary Reformer burners and Feed preheat coil bypasses to bring hydrogenator inlet temperature slowly up to approximately 371°C or as high as possible below this temperature. Recycle Hydrogen To Desulfurizer Section: Initial requirement of recycle hydrogen will be met by import from other plants. Recycle Gas composition from OSBL should be acceptable for injecting into the desulfurization system for hydrogenation purposes. The gas blend for 101-B after injection should have a CO2 Section 8 – Start-up Procedures

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content of less than 4% and a hydrogen content of 2% and at inlet of 100-C H2 content should be 2 dry mol%. If the H2 content is lower, increase the hydrogen gas flow. NOTE Preparation of the systems above and warm-up of the desulfurizer section with Natural Gas may be started during the steam heating of the reformer section.

Several days of on-stream time may be required to fully sulfide the cobalt molybdenum catalyst of the desulfurizer. However, whenever the 108-DB outlet sulfur content of the gas is less than 0.1 ppmv, by lab analysis, feed gas may be started to 101-B. This can be accomplished at lower temperatures than 360°C if process conditions do not allow higher temperatures at the time. Place AE-1107 sulfur analyzer into service on the outlet of 108-DB. Confirm the total sulfur from 108-DB is less than 0.1 ppmv. As the temperature increases at the outlet of 103-C2, on TIC-1011, high enough to prevent condensation, slowly increase the system back pressures to 10.2 Kg/cm2G by adjusting the PV1032 and PV-1040 to front end vent or increase the steam flow to 101-B if available. The temperature of the venting process steam should be 20°C or more above the calculated dew point - see the previous chart - to attain a good margin of superheat and avoid condensation on the catalyst. Do not allow the 104-D1 bed temperature to exceed 260°C until after feed gas introduced to the system to avoid the possibility of a methanation reaction Adjustments to TIC-1004 and TIC-1010 can be done to accomplish this. The differential between the temperature of the heating steam and the bed temperature limited to 100°C.

has been occurring. maximum should be

CAUTION Always avoid exceeding design pressure differentials when flowing through catalyst vessels at reduced pressures. Increase system pressures or reduce flows accordingly, with preference on increasing pressures toward design. The object is to ensure good velocity through the beds to avoid any channeling during the reduction step. ALWAYS COMMISSION PRESSURE DIFFERENTIAL INSTRUMENTS (PDIs) BEFORE STARTING FLOW THROUGH CATALYST VESSELS.

Section 8 – Start-up Procedures

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85. Start Feed Gas to the Primary Reformer

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Lock open the isolation valves of FV-1044 / and bypass in line MS-1017-10”/MS1021-3” and establish a precautionary air sparger steam flow of 2,000 kg/h through bypass of FV-1044. Put FI-1045 into automatic mode. This step should have been done earlier in the process as the primary reformer temperatures are increased. Once the sulfur exit 108-Ds is acceptable, increase process steam rate to 45,700 kg/h to 101-B, ~33% of design. The 101-B exit temperature at this time would be in the range of 750oC. Slowly start feed gas to 101-B reformer from 108-DB through line NG1007. Slowly open HV-1061 4” bypass valve increase feed gas flow to 3,350 kg/h, about 6.5% of design, as shown through FE-1201. Fully open the upstream and use the downstream gate valves to control the flow if required. Arch burner firing must be increased to maintain 101-B exit temperature. This should give about a 14 to 1 steam to carbon ratio. As feed gas is started and increased, increase the backpressure to 10 kg/cm2G at PV-1032 / PV1040, if not already done. NOTE The temperatures listed for the primary reformer and other catalyst containing vessels are based on design numbers that reflect End of Run condition - old catalyst. The actual temperature required to achieve the design reaction and process gas outlet analysis conditions and equilibrium will normally be lower than the temperatures shown. Temperatures can be slowly adjusted and analysis obtained to find the actual point for best catalyst reaction results. In many cases, temperatures that are too high may lead to somewhat reduced catalyst life and reactions that are away from equilibrium causing the conversions to be less than desired. Confirm with the catalyst vendor for optimum temperatures.

Since reforming Natural Gas is an endothermic process, additional burners will be required in the primary reformer to maintain an even temperature profile through all tubes and risers. As more burners are ignited and firing rate increased, ensure PIC-1019 maintains the furnace draft and PIC-1855 maintains the combustion air to the burner openings to maintain a uniform flame profile for the burners within the radiant section. Light burners following the burner lighting pattern to maintain an even distribution of heat. Section 8 – Start-up Procedures

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CAUTION After the steam is open to the jets on the inter and after-condenser, open the eductor line to the after-condenser jet FIRST then open the eductor line to the inter-condenser because the supply for the after-condenser jet is the exhaust of the inter-condenser jet. To take the jets out of service, reverse the order, inter first off, then after, then steam.

CAUTION Care must be used in lighting additional burners in the 101-B arch burner system. High or low fuel gas header pressure can trip the primary fuel gas system. Purging will be required before relighting the system.

86. Reduce and Desulfurize the Reformer and HT Shift Catalyst 2

2

Verify reduction procedures for the catalyst with the catalyst vendor prior to start of the reduction steps and to obtain their latest procedures. The primary and secondary reformers and high temperature shift converter catalysts usually contain sulfur, used in the catalyst binder, which must be removed prior to starting process flow of gas to the low temperature shift. Natural gas is ready for introduction as exit reformer tube temperature to 700 – 750 oC at a rate of 50 – 75 oC. Increase the feed gas flow to the primary reformer ~400 kg/h every 15 minutes until 6,500 kg/h rate has been achieved. This will result in a steam to carbon ratio of just under 7 to 1. Maintain 45,700 kg/h process steam rate and increase draft and firing to reach and maintain 750°C tube outlet temperatures. Hold these conditions for 8 hours to complete the reduction step, if reduction was not done before. Gas increases will be done by opening FV-1001 bypass line, HV-1061, until it is fully open then commission FIC-1001 and then slowly close HV-1061. Place FIC-1001 in automatic as soon as the bypass line is closed and the flow is stable. As the reduction period is being completed, the methane concentration of the gas exiting the reformer will drop due to the reforming reaction increasing. This will require more heat so firing and draft adjustments during the period will be required. After the reduction period has been completed, raise the feed gas rate to the reformer in 400 kg/h increments until 11,500 kg/h rate is reached. This will result is a steam to carbon ratio of about 4 to 1. Section 8 – Start-up Procedures

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Visually inspect the reformer tubes for hot spots, bands, or areas by looking through the provided “peep” doors in the sides of the furnace box. Isolated hot tube areas could mean that catalyst reduction is incomplete and a reduction of feed gas flow back to the 7 to 1 ratio, for four more hours is required. Place the on-stream methane analyzer, AE-1001, in service at the primary reformer outlet and AE-1030 inlet the High temperature Shift.

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For future reformer catalyst reduction, there is a hidrogen line facility SG-1024-2”-D1A2R with flow meter FIC-1025. 87. HP to MP Steam Letdown As the plant rate is being increased, at some point during the desulphurization process, the steam pressure at HV-1048 will be high enough to start letting it down to the MP header. This will require closing HV-1048 gradually while keeping a watch on the superheat coil temperatures. Place TIC-1005A in service with a setpoint of 510°C and place in automatic. Monitor the cold HP steam coil outlet temperature on TI-1552 and maintain below the normal design temperature of 449°C. Process flow through 102-C can be adjusted to maintain this temperature using TIC1004. As the need arises, superheat burners will need to be lighted for maintaining the steam temperatures using TIC-1005.

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Slowly close the HP steam vent HV-1048 to divert the steam from vent to let down system. Raise the pressure on the HP steam as the start up progresses. The above procedure should be carriedout in a step-by-step manner so that a cooling flow is always maintained through the coils and 102-C. Slowly increase the setpoint on PIC-1018 until the HP header pressure is near the normal 125.5 Kg/cm2G. 88. Start Air Injection to Secondary Reformer 103-D The 101-J air compressor may have already been started previously to supply air to the plant and in anticipation of air introduction to the secondary reformer. When the compressor is first started, air will be vented through the silencer SP-151. FIC-1004 will be in automatic to control FV-1004 to maintain the anti-surge air flow. When the catalyst temperatures of the secondary reformer, TI-1052 and TI-1053, are at 650°C, higher is preferred, air can be introduced to the secondary reformer. Before the air is started, confirm that the air line is free of condensate. Section 8 – Start-up Procedures

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The temperature increase for the Secondary Reformer reforming and the HTS converter catalysts must be kept below 50°C / hour or as specified by the individual catalyst vendors. Proceed with caution when introducing process air into the Secondary Reformer, once the Secondary Reformer catalyst has been heated above 200°C in a reducing atmosphere, it must not be contacted with free oxygen. This is to prevent fusing of the catalyst due to rapid oxidation. The secondary reformer catalyst is now partially activated. The process air flow controller, FIC-1003 should be in manual mode and speed should be increased as and when required while pushing air to 103-D. Confirm FV-1003 and its bypass are closed with isolation closed as well. XV-1212 should be confirmed to be in close position. FIC1004 controls the flow through the 101-J meeting anti-surge control requirements. Adjust the speed of 101-JT to ensure the pressure at PI-1023 is ~4-5 kg/cm2G above the pressure in 103-D. Determine that no process air is flowing to the Secondary Reformer, 103-D, by watching FIC-1003 and the temperature at TI-1052. Reset XV-1212 to open position. Open upstream gate valve on FV-1003 bypass line. Slowly open the globe valve on FV-1003 bypass line to start a small flow of process air to the secondary reformer. Monitor the process air flow rate on FI-3006. To confirm that the process air is present and is flowing, there should be a flow indication on FI3006 and a rapid increase in the temperatures in the Secondary Reformer. If the valve is open 25% to 50% and no flow or reaction is seen, close the valve fully and determine the reason before continuing. Ignition is indicated by a rapid temperature increase in the top section of the catalyst bed on TI-1052 and a slower increase on TI-1053 as the flow moves through the catalyst bed. Always introduce air to the secondary reformer slowly and in small increments. If ignition is not quickly verified by a temperature rise, the air flow should be stopped and not restarted for at least 10 minutes. Limit the Secondary Reformer temperature increase to 50°C / hr. It may be several seconds before the Secondary Reformer bed temperature increase becomes evident. Slowly increase the process air flow to about 20% rate, 28,500 kg/h, once ignition is verified. As the process air flow is being increased, the FV-1003 bypass line will reach its limit on capacity, also FI-3006 will approach its maximum range. Compare the flow rates on FI-3006 and FIC-1003 and the two Section 8 – Start-up Procedures

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should be in reasonably close proximity. At this stage, open isolation valves for FV-1003. Slowly start opening FV-1003 and closing the bypass globe valve. Ensure the air flow rate on FIC-1003 remains unchanged during this exercise. Once the bypass globe valve is fully closed, its upstream gate valve is to be car seal closed as well. If required, adjust 101-J speed while opening FV-1003 until its fully open and the Process Air flow rate is still maintained the same. Monitor the Secondary Reformer carefully during the introduction and each increase of the process air. The methane concentration in the Secondary Reformer effluent as indicated by AI1030 must be stable. Determine by laboratory analysis of the Secondary Reformer effluent and pressure temperature equilibrium as to the correctness of the process air flow rate as indicated by FIC-1003. At this time MP steam flow is already flowing at ~2000 kg/h to Secondary Reformer 103-D on FIC-1044. Initialy, control the speed of the Process Air Compressor Turbine manually to maintain the process air flow at FIC-1003. Use TIC-1312 cold air coil bypass valve on A5001-6” to maintain the outlet temperature of the hot air coil near the design temperature of 497oC. Be careful not to overheat to cold air coil by bypassing the air around it. CAUTION Whenever increasing ammonia plant rate, increase the process steam first, then the feed gas and then the process air last. Decrease the ammonia plant rate in the reverse order. The steam to gas and air to gas ratio LeadLag System will do this automatically provided that these functions are in automatic service.

Gradually increase the feed rates in 5% increments each for steam, gas, and air to achieve ~63% process steam, 87,500 kg/h; 40% process gas, 25,800 kg/h; and 40% process air, 57,100 kg/h. System back pressure should be gradually increased to 15.0 kg/cm2G by adjusting the PIC-1032 vent valve downstream of the 104-D1 High Temperature Shift and PIC-1040 vent valve downstream of 142-D1. Watch FIC-1001, FIC-1002 and FIC-1003 to ensure the 101-JT speed and discharge pressures are increased to maintain the flow rates and that the steam flow valve opens to maintain the set flow. Section 8 – Start-up Procedures

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Do not allow the 101-C inlet temperature to increase at a rate of more than 85°C /h while adding air and increasing rates. Close the 108-DB desulfurizer outlet vent HIC-1108, as feed gas is increased, if the preheat coil is cool and the valve is not already closed. At the above conditions, the steam to carbon ratio is about 3.4 to 1. WARNING Do not exceed the design 103-D outlet temperature of 900°C.

The HTS converter temperatures should be watched for excursions during stabilization reduction of the catalyst. If accelerated temperature differentials in excess of 38°C are noticed, stop air or reformer temperature increases until more stable conditions are observed. As the temperature at the outlet of the secondary reformer increases, adjust the 101-C and 102C bypasses to raise the HTS converter inlet temperature to 371°C at a 50ºC /h rate. Place TIC1010 on automatic control (Verify the start-of-run temperature conditions with catalyst vendor for maximum catalyst life and efficiency). A higher than normal temperature to the HTS, in the range of 400°C, will be required to remove all of the sulfur from the catalyst (dependent on catalyst vendor’s recommendations) then the inlet temperature will be lowered to the point of best CO conversion and longest catalyst life. Place TIC-1004 in service in automatic to limit the temperature of the HP steam exiting 102-C to 338°C. The above higher inlet temperature conditions will be maintained until the HTS converter effluent is sulfur free. Sulfur, as H2S, can be spot checked using lead acetate paper. When this test indicates the stream is free of sulfur, the gas stream should be sampled and verified by laboratory analysis. Monitor the BFW temperature exit 103-C1 on TI-1411 and keep it below the steam generation temperature of about 328°C (assuming design 141-D pressure). Adjust TIC-1011 to control at 200°C and place in automatic (Verify the start of run temperature conditions with the LTS catalyst vendor for maximum catalyst life and efficiency). Reduction And Desulfurization Precautions

Section 8 – Start-up Procedures

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Once feed gas enters the primary reformer, the catalysts in the primary reformer, secondary reformer, and HTS converter are to be regarded as fully reduced for safety purposes. Increases to reformer feed rates should always be made in small increments, spread over a period of time, such as, no more than 5% every ½ hour. When gas is introduced to primary reformer, the temperatures of the HTS Converter should be observed. The HTS converter catalyst should not be subjected to a temperature difference greater than 85°C. If this should occur, air and feed gas should be reduced so that the steam to carbon ratio is increased. 89. Complete Desulfurization of HT Shift Converter Effluent gas from the HTS converter will again be tested for sulfur by lab analysis. Total sulfur from primary and secondary reformers as well as the HTS catalysts will be detected, although sulfur in reformer catalysts is usually negligible. Increase the HTS converter inlet temperature to 371°C, or even higher to 400ºC, if possible. It is a good practice to increase the inlet temperature well above its normal operating temperature to assure complete desulfurization of the catalyst. If the catalyst is desulfurized at a temperature at or less than design, some additional sulfur will be removed when temperatures approach or exceed design conditions during plant transients. This sulfur release will permanently poison the 104-D2A/B LTS catalyst. To aid in complete desulfurization of the HT shift Converter catalyst the plant rate might need to be increased to ~75% with the back pressure to 26.0 to 28.0 kg/cm2G with PIC-1032 controlling the pressure. When the sulfur content of the HTS converter effluent is consistently less than 1.0 mg / m3, with several samples taken over a period of a few hours to verify complete desulfurization the process gas and air feed rates can be back reduced to ~50% of design to conserve Natural Gas, if desired. Maintain the process steam flow rate 10% of design higher than the feed rate percent of design. As rates are decreased, confirm that PIC-1032 adjusts to maintain the system backpressure at 17.5 to 19.5 kg/cm2G. This rate reduction will conserve feed and fuel during steam line blowing, completing the commissioning of the CO2 removal system and commissioning the methanator. 90. Steam Blow the HP Steam Line It is anticipated there will be sufficient steam available from OSBL Package Boiler before this time

Section 8 – Start-up Procedures

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to blow the HP steam lines to 103-JT and 105-JT. Steam blow the HP steam system piping until it is targeted clean and then reassemble the piping at 103-JT and 105-JT. The systems should be shocked, cooled, and heated several times to ensure all loose material is dislodged and blown clear. Follow the guidelines found in Section 6, Unit Conditioning, for blowing the lines and refer to the turbine vendor’s requirements. When the HP steam system is lined out and stable at 123.1 kg/cm2G as controlled on PIC-1018, prepare to verify the set pressures of the steam drum and HP system relief valves, if required. Gradually increase the pressure of the system sufficient to check each relief valve. The settings are as follows: • 141-D1 139.9 kg/cm2G • 141-D2 144.1 kg/cm2G If the relief valves are to be set by using a hydroset testing device, the pressures usually only need to be above 90% of design. However, the sub-contractor doing the setting will detail the actual procedures. PIC-1018 should be put on manual control during this testing period. PV-1018 should be used in manual during this time to control the main header pressures. The HP steam pressure will be increased and decreased to verify relief valves by manually venting steam using HV-1048 superheater vent under constant letdown flow. This method causes minimum pressure fluctuations to the HP and MP Systems. Verification of the steam relief valves should be done under the direct supervision of authorized persons, fully qualified, and according to established plant procedures and practices. Keep condensate drained at low spots. After verification of the safety relief valves, very slowly and gradually increase the flow of steam through PV-1018 while closing the HV-1048 vent. This will require a great deal of attention to balance the load while maintaining 123.1 kg/cm2G steam pressure on 141-D steam drum. Normal control of PIC-1018 may be switched to automatic when the pressure and level in the 141-D become stable. HV-1048 should be closed at this time. 91. Process Condensate Stripper Although the condensate stripper can be started at a later time, it is usually desirable to reduce the load as much as possible on the demineralizers. Placing the unit on-line at this point will have good quality water being produced for sending to Section 8 – Start-up Procedures

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the polishers before the steam loads reach their maximum peaks. A line BFW2202-3” for keeping flow to 130-D has been provided thus 130-D may need to be in partial service even before this. Process condensate will begin to accumulate in the Raw Gas Separator, 142-D1 as soon as flow is brought through the LTS effluent heat recovery section. Before putting the 130-D Process Condensate Stripper in service the valves should be aligned as follows: • PT-1069A and B commissioned and placed in service • FV-1019 closed. • Set 130-D LIC-1025 on automatic at normal level • Open isolation valves of LV-1025 • Close the downstream battery limit 6” isolation valves on line PC1012-6”. • Open 6” isolation valve to HIC-1118 on line PC1030-6” to OSBL • Close all drain valves • Ensure cooling water is commissioned through 174-C • Fully open the 3” vent valve to the atmosphere 130-D top vent, line V4035-3” • Put AIN-1017 Conductivity Analyzer on line • 142-D1 LIC-1003 on automatic at normal level • Reset the solenoid valve LY-1003A using DCS handswitch HS-1003 • Reset the solenoid valve XY-1003 using DCS handswitch HS-1203 • LV-1003B, in service draining 142-D1 condensate to OSBL. • Open the cooling water supply and return valves to the 121-J / JA pumps • Open the suction and discharge isolation valves of 121-J / JA pumps and vent the pumps to be sure they are liquid full • Open SP-ARV-121J / JA automatic recycle isolation valves and lock open • Open the warm-up valves around the automatic recycle check valves 130-D will have to be pressurized with medium pressure steam following the procedure listed below for normal operation. This pressure will give the necessary head required to drive the recovered BFW to the offsites. Normal Operation – Process Condensate Recovery Ensure the 121-J / JA pumps are hot and start 121-J or JA pump. Slowly open the isolation valve(s) of LV-1003A and condensate will start to flow to 130-D from 142-D1. The level in the Raw Gas Separator will be maintained by LV-1003A and LV-1003B will close. The Process Condensate will start flowing through tube side of 188-C3 / C2 / C1 to the 130-D packed sections, to the bottom section and out the bottom through the shell side of 188-C1 / C2 / Section 8 – Start-up Procedures

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C3 and through the shell side of 174-C with the bottoms level controlled by LIC-1025 to OSBL. This will require admitting some process steam to 130-D to add a driving force to remove the liquid. Once the circulation and a low levels are established slowly start opening the 2” bypass valve in the MP steam line around the block valve in line MS1005-10”, to the Process Condensate Stripper, 130-D. Slowly start heating the Process Condensate Stripper 130-D until the 2” bypass valve is fully open. After the 2” bypass valve is fully open, slowly start opening the MP steam 10” isolation valve on line MS1005-10”. Slowly increase the pressure of 130-D by closing the 3” atmospheric vent valve. When the pressure of 130-D has equalized with the MP steam system, slowly open the 10” isolation valve to the process steam header not upsetting the MP steam flow or pressure on FIC-1002. Open fully the inlet steam block valve to 130-D and close the 2” bypass and 3” atmospheric vent valves. With FIC-1019 on manual, slowly start opening open FIC-1019. Establish a small stripping steam flow of approximately 3,000 kg/h through the Process Condensate Stripper using FIC-1019. Do this very slowly so as not to upset the process steam flow and control on FIC-1002 to the 101-B. Set FIC-1019 for automatic operation as soon as the flow stabilizes. AIN-1017 will be the guide to steam / condensate ratio required in operation. The design steam to water ratio is 0.3 kgs steam per 1 kg water. It will be some time before the condensate is clean enough for use in the offsite polishers. At this time the steam flow can be increased or decreased to maintain the conductivity out of the 130-D bottoms. When the Process Condensate Stripper operation is stable, the process condensate is to be sent offsites and the valve to the condensate tank closed. The process steam flow to 101-B is designed to be split with about 20% passing through FIC1019 to 130-D stripper and 80% through control valve FV-1002B.

92. Start CO2 Absorption 2

Some of the steps below will already have been carried out during the ammonia cracking into Section 8 – Start-up Procedures

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hydrogen procedure and are stated here only as a reminder to verify. Ensure the methanator trip circuit is in the tripped position with: • XV-1211 inlet valve closed. • MOV-1011 inlet valve and its bypass valves both closed with the bleed valve open. Have 109-L anti-foam injection system commissioned, filled and ready to run, if required. Monitor PDI-1042A/B. Higher differentials may be indicative of flooding and / or foaming. Set PIC-1104, 153-D CO2 vent on automatic to control the 122-D1 overhead pressure at 0.8 kg/cm2G. While the HT shift converter desulfurization is progressing and after the OASE circulation has started, some of the gas venting at PIC-1032 will be moved forward to the vent PIC-1040 upstream of CO2 Absorber 121-D. When laboratory analysis indicates the sulfur content of the HT shift converter effluent is less than 1.0 mg/m3, the gas can be sent through the CO 2 absorber to the PIC-1005 vent upstream of the methanator, 106-D. Place TI-1352 exit 106-C in automatic at 70°C. This will close the 109-C bypass fully until the process gas temperature increases. Unblock and slowly open HIC-1021 bypass around MOV-1009 to pressure up the system to MOV-1005. Once the system pressure at PIC-1040 is equal to PIC-1032, open MOV-1009 and close HIC-1021. WARNING Do not bring process gas flows through the LTS effluent exchanger train unless minimum flows are established in the OASE system

CAUTION Before admitting gas to any system, it must first be purged with nitrogen if any chance of the presence of air exists.

Slowly open PIC-1040 to bring a flow of gas through to start heating the already circulating OASE solution in preparation of bringing gas through the CO2 removal system. PIC-1040 can be slowly opened fully and PIC-1032 will automatically close to maintain the system backpressure. Section 8 – Start-up Procedures

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Verify that the following temperatures are in line also to maintain as near design conditions as possible: • 131-C shell outlet - 167oC • 105-C to 122-D2 - 126°C • 106-C, Synthesis gas out - 70°C • 106-C, Demineralized Water Out - 120°C • 112-C to 122-D2 - 99°C CAUTION It is important that the temperatures of the process gas exiting 131-C, 105-C and 106-C be as close to design as possible. If the temperature exit 131-C is too high, the temperatures exit 105-C and 106-C may be too high causing excessive reboiling and / or additional water to be carried with the process gas into the OASE solution which will lead to solution dilution. 106-C must also be adjusted to control the exit temperature to design or slightly below.

105-C outlet temperature can be adjusted to some degree by adjusting the Process Gas bypass on PG2208-16”. Ensure cooling water is flowing through 110-C CO2 Stripper overhead condenser. Once the level in 153-D starts increasing as condensation occurs in 110-C, start flows to the wash sections of 121-D, 122-D1 and 163-D at the following rates: • 121-D - 3,500 kg/h on FIC-1018 • 122-D1 - 6,366 kg/h on FIC-1016 • 163-D - 1,100 kg/h on FIC-1030 Open FIC-1016, FIC-1018 and FIC-1030 controllers manually to get the above desired flow rate then place in automatic. CAUTION Have the lab check the OASE solution strengths and loading on a regular basis and often during start-up as solution dilution can easily occur under low heat loads.

FIC-1013 can be put in CASCADE automatic from LIC-1040 to maintain a 50% level in 153-D with make-up demineralized water to the wash water system from FIC-1013 as needed to Section 8 – Start-up Procedures

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maintain a 50% level on LIC-1040. CAUTION Always establish gas flow through 121-D slowly to avoid flooding the tower which could result in liquid carryover to 142-D2 and damage in the 121-D packed beds.

WARNING Never start / continue flowing process gas through 121-D if the OASE level is at or above the inlet gas sparger or foaming and severe carryover will likely result.

Set PIC-1039 on automatic at 7.3 kg/cm2a to vent HP Flash Gas to the hot vent through PV1039A with PV-1039B isolated. With the absorber and methanator inlet gas valves and PV-1005 closed. Set PIC-1005 front end vent upstream of 114-C on manual. Verify all the flows, levels, pressures and temperatures are stable, slowly open the 2” bypass valve in line PG1015 around MOV-1005 to 121-D. As the CO2 removal system pressure is increasing, monitor the levels, temperatures and pressures throughout the system and adjust flows as necessary to stabilize the process. When the 2” bypass valve is fully open slowly start opening MOV-1005. When MOV-1005 is fully open and pressure in 121-D is equal to the pressure at PIC-1040, close the 2” bypass of MOV-1005. Once the bypass is closed, slowly start opening PIC-1005 manually watching that PIC-1032 closes to maintain the pressure. When PIC-1032 is closed, put PIC-1005 on automatic at the current pressure then slowly close PIC-1040. When PIC-1040 is closed, increase the PIC-1005 set pressure to 22.0 kg/cm2G. Continuously watch the OASE flows and levels to be sure that they are being maintained. Place the analyzer AE-1023 system in service. Open the isolation valves on 142-D2 LV-1005 and place in service with LIC-1005 in automatic. Line Out The OASE System Open the globe valve to FI-1108 exit 121-D process gas wash nozzle. Section 8 – Start-up Procedures

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Adjust the 110-C and 112-C to bring 121-D Absorber and 122-D1/D2 stripper temperature profile to as near design conditions as possible. • 112-C to 122-D2 99°C • 112-C to 109-C 88°C • 109-C to 108-C 74°C • 108-C to 121-D 50°C Verify that the following temperatures are in line also to maintain as near design conditions as possible: • 131-C 167oC • 106-C, Synthesis gas out 70°C • 105-C to 122-D2 126°C • 106-C, Demineralized Water Out 120°C Ensure PIC-1104 is holding the 122-D1 stripper pressure at 0.8 kg/cm2G since this pressure affects the bottoms temperature. Approximately 30 minutes after gas has entered the absorber, start sampling the methanator inlet stream, and the circulating solution streams. Send them to the laboratory for full analysis. Readjust the system circulation rates and / or temperatures based on the results of the analysis. If PDI-1043, PDI-1042A/B indicate the system might be foaming, perform foam tests, both in the field and in the laboratory. If foaming is occurring, start injecting anti-foam solution using the shot pots then from 109-L to the appropriate location where foaming appears to be occurring. Align all standby pumps and set-up for automatic start, if not already done. Check the OASE system for concentration and CO2 loading. If possible, the OASE solution circulation should be increased to 60% to 75% rate using lower than design concentration with reduced process gas rates through the absorber. To do this, the second 107-J will need to be started because each 107-J pump is expected to have about 55% of total design flow capacity at design pressure. It is usually better to operate at lower solution concentration and higher circulation than vice-versa. Example:

At 50% gas flow rate and 60% to 75% circulation, the solution concentration could be in the 32% to 35% range. Although, with too much solution circulation rate compared to gas flow rate, there will be insufficient heat Section 8 – Start-up Procedures

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available to regenerate the rich solution. If more heat is required, the reformer steam to carbon ratio can be increased or 105-C process bypass line can be closed. Adjust the OASE system until stable conditions are obtained and design CO2 stripping is achieved, as verified by laboratory analysis. 93. LT Shift Catalyst Reduction and Activation Up until this point, the LT shift converter has been maintained with a nitrogen purge or blanket and is blind isolated at its inlet and outlet valves. Hydrogen gas is available from 142-D2 for the LTS catalyst reduction and nitrogen will be used as the carrier gas through the LTS during catalyst reduction.

8.1.14.

LTS Reduction Procedure

The following is a typical LTS catalyst reduction procedure, but it is not intended to replace the catalyst vendor's procedure. This procedure assumes 104-D2A/B will be reduced sequentially in series though it is possible to reduce either of the two reactors separately. Consult the catalyst vendor for their reduction procedure. Remove or open the blinds at: • The hydrogen line from 142-D2 PG1073-2” • Line SG1030-14” to 104-D2A • 104-D2B to 173-C line SG1019-14” • N1103-1.5” to PG1174-14” • N1002-1.5” to PG1012-30” • 173-J to 175-C, line SG1020-14” • Line MS1099-3” to the 175-C tube • Line up Cooling water inlet and outlet 173-C lines CWS3235-10” and CWR3235-10” • Opem block valve between 104-D2A and 104-D2B on line PG1019-30” Close the blinds / valves at: • V1007-6” to hot vent • V2510-1.5” to hot vent • MOV-1008 inlet to 104-D2A • Double isolate and open the bleed valve on MOV-1008 bypass • MOV-1007 and bypass outlet of 104-D2B • PG1012-30” exit the LTS to the mass spec. Section 8 – Start-up Procedures

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After these blinds have been changed, verify nitrogen purge of the system to an oxygen content below 0.5% has been completed before hydrogen rich gas flow is started. With all blinds in place, align the reduction system as follows: • Nitrogen header block valves in lines N1103 to PG1174-14”' / 173-J and N1002 to PG1012-30” open • 175-C inlet MP steam warming with the isolation valve closed outlet MP steam condensate line trap isolation valves open • 173-C inlet and outlet cooling water isolation valves open • 173-J open the gate valve fully in line SG1030 to 104-D2A and the butterfly valve 25% • FIC-1301 to automatic • Hydrogen supply isolation valve open, PG1073-2” • FI-1602 and 1603 isolation valves closed. • 104-D2B outlet valves (2) on line SG1019-14”, open to 173-C • AE-1031 switch to 104-D2 outlet upstream of MOV-1007 • PDT-1037A, PDT-1037B verify the transmitter is in service and reading Pressure 104-D2A/B reduction system with nitrogen, using line N1002-1.5” and N1103-1.5”, until the pressure is approximately 7.0 kg/cm2G as indicated on local PG-1614 at the 104-D2B outlet and local PG-1680 on the 173-J discharge. CAUTION The nitrogen gas to be used for purging or reduction of the LTS should be analyzed for oxygen prior to its use. Only trace amounts of oxides are acceptable - <20 mg / m3v total.

Establish a gas flow to 104-D2A/B by starting 173-J, LTS Start up Circulator, following the vendor’s recommended steps as found in the IOM. The normal, and preferred, flow path is: • 173-J → 175-C → 104-D2A/B → 173-C → 173-D → 173-J. Start to heat the 104-D2A/B catalyst by opening the butterfly valve and watch the flow on DCS FI1104. Increase the flow to at least the minimum required by the catalyst vendor for reduction. Slowly opening the globe valve on the inlet MP steam to the 175-C, LTS Start-Up Heater. Control Section 8 – Start-up Procedures

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the heat up rate of the nitrogen to 104-D2A/B by throttling the 3” globe valve on the MP steam line. When making these adjustments do not exceed a differential temperature of 50°C between the gas stream leaving 175-C, TW/TG-1604 and DCS T1-1306, and the catalyst hot spot temperature of 104-D2A TI-1346A/B through TI-1349A/B and TI-2446A/B through TI2449A/B for 104-D2B. The heat up rate of 104-D2A/B should be 10~30°C /h and not exceed 50°C / hr. When the catalyst temperature reaches 120°C, verify that the hydrogen flow meters FI-1602 and FI-1603 are working accurately and that the on-stream gas analyzer AE-1031 is also working correctly. Sample the offsite supplied hydrogen for purity using the battery limit drain as a sample point. Continue heating the catalyst bed to 180°C but do not allow the recycle stream temperature to exceed 210°C at TW/TG -1604 or T1-1306. When the top of the catalyst bed 104-D2A has reached 180°C and the flow and pressure are stable, introduce hydrogen to the system by opening the common isolation valve downstream of FI-1602 / FI-1603, the downstream isolation valve at FI-1602 and then partially opening the needle valve upstream of FI-1602. Analyze the gas stream entering 104-D2. The hydrogen content should be about 0.1~0.3 mol% but with a maximum of 0.5 mol%. Watch for an increase in catalyst bed temperatures and also analyze and compare the inlet and the outlet gas stream for any indication that hydrogen is being consumed. Reaction should now have started. Indication is a temperature rise in the catalyst bed and consumption of hydrogen. Maintain these conditions until the catalyst temperatures stabilize. Do not allow any temperature point to exceed 230°C. Reduce or stop the hydrogen flow to limit this temperature. Water formed as a part of the reduction reaction will be condensed in 173-C and removed in 173D. The accumulated water in 173-D will have to be manually blown down to the sewer. Throughout the remainder of the reduction operation, these precautions must be observed: • Observe all pertinent temperatures and pressures and record them every 15 minutes, or more often, to determine the temperature profile. • Analyze the 104-D2A/B feed and effluent gases for hydrogen content just prior to each increase in reducing gas flow. (Double check these analyses). • Do not increase the reducing hydrogen gas flow until the analysis indicates little or no hydrogen consumption. • Do not allow the catalyst temperature to exceed 230°C at any location. • Do not exceed 0.7 kg/cm2 differential pressure across the bed. Section 8 – Start-up Procedures

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Always be prepared to remove the hydrogen and reduce the circulating gas temperatures by stopping the steam to 175-C in case of runaway temperatures. When temperatures are under control, they may be re-established and hydrogen reintroduced cautiously. Watch the 173-D level and manually drain as required. WARNING Stop the hydrogen flow immediately if 173-J trips or the flow as indicated on FI-1104 becomes low.

By conforming to the above, the reduction will proceed with moderate, uniform reaction as the heat front passing through the catalyst bed is observed. Once reduction has started and a steady temperature profile has been established, the hydrogen concentration can be increased in small steps to 1.5 mol%. The peak bed temperature should still not be allowed to increase above 230°C. Adjust the hydrogen concentration accordingly to maintain this maximum. It is expected that each 1% of hydrogen in the feed gas will give about a 30°C temperature rise in the catalyst bed. When the reaction front has passed completely through the bed, slowly increase the bed temperatures to 200°C for one hour then slowly increase the hydrogen rate to 3.0 then to 5.0 mol % in small increments but do not allow the bed temperatures to increase above 230°C. FI-1603 will have to be used to get the higher percentage hydrogen. Confirm that there is no hydrogen consumption taking place in the catalyst bed indicating that the reduction is at or near completion. That is the H2 percentage at the 104-D2 inlet and outlet are equal and until analysis confirms that the hydrogen consumption is less than 0.2%. As a final test that reduction is complete, slowly increase the hydrogen content to 10.0% and hold for 30 minutes watching for the possibility of a temperature rise. Both rotameters will be used along with lab analysis. At each step watch for a temperature increase and hydrogen consumption. When the 10% hydrogen level, or as high as possible, has been reached, hold the system conditions for four hours. During this period, continue to monitor for an increase in temperatures and hydrogen consumption. When no further temperature rise or hydrogen consumption is indicated, the reduction is complete. CAUTION Hydrogen analysis is very important during the reduction period, therefore, duplication of sampling and analysis is recommended to verify the reproducibility of results.

Section 8 – Start-up Procedures

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Stop the hydrogen flow and isolate the hydrogen line by closing the block valves inlet and outlet of the rotameters and the combined flow downstream block valve. Depressure and nitrogen purge the hydrogen line downstream of and including the FI-1602 and FI-1603 flow meters. Stop the carrier gas by slowly closing the gate valve downstream of FI-1104. Shut down and isolate the 173-J circulator. Close the steam valve to 175-C. Depressure the LTS and place a nitrogen purge on the vessel in preparation for changing the blinds. Pressure purge the entire system with nitrogen to remove any hydrogen remaining after the reduction. Install the following system blinds in the position indicated: • Line PG1073-2” to line SG1030-14” (from FIs-1602 / 1603) • 173-J to 175-C, line SG1020-14” • Line SG1030-14” to 104-D2A from 175-C • Line SG1019-14” outlet 104-D2B to the 173-C cooler (LTS outlet blind only) Just prior to the LTS being placed in service, remove the blinds at: • V1007 to hot vent • V2510-1.5” to hot vent • MOV-1008 inlet to 104-D2A • Double isolate and open the bleed valve on MOV-1008 bypass • MOV-1007 and bypass outlet of 104-D2B • PG1012-30” exit the LTS to the mass spec. 8.1.15. Commission Low Temperature Shift Converter Depressurize the LTS to the atmosphere through the vessel vent valve. Nitrogen purge the 104D2A/B from MOV-1008 inlet to MOV-1007 outlet block valve using line V1007 valve. Purging of 104-D2A/B vessel should be continued only until an acceptable atmosphere has been obtained for removal of the inlet and outlet blinds. Excessive purging will tend to cool the catalyst. If trace amounts of oxygen are present in the nitrogen, partial oxidation of the catalyst could occur. CAUTION The vent header back pressure will not allow the LTS to depressed fully. This will have to be done using the 1½” vent on the inlet line, venting at a safe location, with V1007 tightly closed.

After removing the blinds at MOV-1008 and MOV-1007 outlet block valves the LTS may be Section 8 – Start-up Procedures

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placed on stream with gas from the HTS. If the catalyst bed temperatures are above the gas dew point, start a flow of gas through the 1” bypass line of MOV-1008 to pressure the LTS. When the pressure is equal to PIC-1032, slowly open the LTS outlet manual vent, V1007, maintaining the pressure around 23 kg/cm2G. Heat the catalyst bed at 50°C / hr. Make sure there is no possibility of water droplets reaching the catalyst bed in such situation. CAUTION The initial reaction temperatures should be held to maximum differential of 30°C. Should the temperature differential exceed this value, the normal feed gas should be stopped. The bed temperatures should then be cooled to 175°C to 190°C over 20 minute period before normal feed gas is reintroduced. Repeat this as many times as necessary until the initial flow of feed gas can be maintained without an excessive temperature rise.

Continue to open the MOV-1008 1” bypass until it is fully open. When the reactor temperatures are steady, without any temperature rise, slowly close the venting stream to increase the vessel pressure toward the existing system pressure at PIC-1032. Continually check the bed temperatures ensuring there is no unusual temperature rise. After the start-up vent is closed, and the pressure in 104-D2A/B is equal to PIC-1032, gradually open the MOV-1007 LTS outlet valve. When the outlet valve is fully open, gradually inch open MOV-1008 until it is fully open. Watch the bed for any unusual temperature increases and close MOV-1008 if any sudden temperature rise is indicated. When MOV-1008 is fully open, close its bypass valve. Once MOV-1008 is fully open and the LTS temperatures appear stable, close MOV-1009 gradually to push all the flow through the LTS beds. Watch the bed temperatures for unusual temperature increases. 8.1.16.

Start Methanation

Presently the primary reformer feed rates are at about 50%. The carbon monoxide content leaving the LT shift converter will be approximately 0.31 mol% (dry basis) or less. Total carbon oxides influence the temperature rise across the methanator. With this anticipated carbon monoxide content and assuming design carbon dioxide content, the temperature rise will be approximately 29°C. However, if the carbon dioxide content should increase, due to operational problems in the CO2 removal system, this temperature rise will be excessive and unacceptable. Therefore, the maximum allowable total carbon oxide is < 1.5 mol% (dry basis). Section 8 – Start-up Procedures

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CAUTION The temperature rise for 2.0 mol% of carbon oxides will be from 125°C to 145°C. If the inlet temperature is 315°C, the methanator will trip on high bed temperatures in both cases. If the inlet temperature remains fixed at about 315°C, the maximum total oxides allowable will be < 1.5 mol%.

WARNING As the methanator catalyst temperature is increased, there is a temperature range through which minute amounts of highly toxic nickel carbonyl is formed (38°C through 204°C), if CO is present. The presence of water vapor and / or the oxide coating on the catalyst suppresses this formation. Maintaining the methanator pressure as low as practicable during heat-up will also help in deterring the reaction rate during the carbonyl formation period as well as reduce any leakage that may be present. Once the methanator catalyst temperature has reached 205°C, the possibility of carbonyl formation is very remote. Therefore, the methanator should never be shutdown and isolated with a gaseous atmosphere containing carbon monoxide at temperatures below 205°C. All personnel should be aware of the above and stay clear of methanator effluent gases until the bed temperatures are above 205°C. Analyze the gas stream venting at PIC-1005. When laboratory analysis confirms the total carbon oxide content is less than 1.5 mol% (design is ~ 0.43 mol%), gas may be started to the methanator. The methanator 106-D is being maintained under a N2 gas pressure including its effluent system, 114-C, tube side, 115-C shell, 130-Cs tubes, 144-D, 109-Ds and up to the purifier. The nitrogen purge is entering the system through N1007-2” line on the 106-D outlet line. Discontinue the N2 purge at this time. The methanator catalyst will be heated with process gas taken from downstream of 114-C tube sides, line PG1018, and heated with saturated HP steam from 141-D, through line HS-1172, in 172-C, then routed through 106-D, 114-C shell sides, 115-C shell side, 130-Cs tube side and 144-D to vent at PIC-1084. Align the system as follows: • PIC-1084 Fully open ( should be closed ; and will open when the pressure almost same with PV-1005 ) • 115-C commission cooling water flow, if not already in service.

Section 8 – Start-up Procedures

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• • • • • •

TIC-1012 MOV-1011 XV-1211 172-C LIC-1010 LIC-1008

• •

MOV-1017 MOV-1018 PV-1049A PV-1049B 144-D 122-Js

• • • •

• 130-C1 / C2 • • • •

PIC-1114 AI-1002 AI-1003A/B PIC-1084

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114-C HP Steam / process gas bypass in automatic set at 300°C. 106-D inlet closed - bypasses closed and bleed open. 106-D inlet closed. ( should be open ) HP steam line warming to TV-1012B. condensate valve’s isolation valves open to 101-U isolation valves open and in automatic at normal level on 144-D with LV-1008 isolation valve open . 109-DA inlet is closed. 109-DB inlet is closed. 109-DA inlet bypass is isolated. 109-DB inlet bypass is isolated. Establish a normal level when process condensate appears. Open suction and discharge of 122-Js pumps and car seal open the minimum flow recycle line isolation valves through, SP-STR-122J and SP- STR-122JA to 144-D. Liquid level established if 105-J is in service with LIC-1009 and LIC1118 in automatic automatic and set at 3.7 kg/cm2G Placed in service Placed in service Manual with the upstream isolation valve open

Once a level is established in 144-D, start 122-J pump on recycle through SP-STR-122J with LIC-1008 closed. Energize the trip system associated with methanator using DCS handswitch HS-1211 to open XV-1211 then slowly close the bleed valve and open the bypass valves on MOV-1011 to pressure up and warm the system. Begin heating the 172-C with HP steam manually using TV-1012B. Raise the 106-D inlet temperature as rapidly as possible to 205°C, but do not exceed the 80°C /h maximum heat up rate. Keep backpressure low while bed temperatures are below 205ºC - See previous warning. Slowly inch open MOV-1011 until the pressure on PIC-1084 is about 3.0 kg/cm2G then maintain this pressure using PIC-1084 until the lowest bed temperature in 106-D reaches 205°C then slowly inch MOV-1011 fully open and increase the pressure using PIC-1084 and closing PIC-1005.

Section 8 – Start-up Procedures

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CAUTION Do not pressure 109-DA and 109-DB until the Methanator is on-line and CO + CO 2 downstream of 106-D is below 10 ppm and the temperature is near normal at 4°C.

Hold 21.0 kg/cm2G backpressure with PIC-1084 on automatic and PIC-1005 closed. Increase PIC-1005 setpoint to 22.5 kg/cm2G or 1.5 kg/cm2G above PIC-1084. As the level in 144-D increases, level can be initially maintained manually by draining to the sewer system. Verify that the level is steady then the pumps 122-Js can be started, if not already running on recycle, and condensate pumped to 142-D1. Reduction of the nickel oxide methanation catalyst to metallic nickel usually begins at approximately 200°C. The methanation reaction will begin when the inlet temperature is approximately 260°C. Maximum catalytic activity is normally attained with a bed temperature of 343°C (verify with vendor information). The catalytic activity will manifest by an immediate temperature rise across the bed. After reduction, the inlet temperature should be maintained as low as possible to attain an effluent gas with less than 10 mg / m3 maximum of total carbon oxides. Under no circumstances should the catalyst temperatures be allowed to approach or exceed the vessel design temperature of 454°C. When the differential temperature across the bed is proportional to the carbon monoxide in the gas, 1.0% CO causes about a 72°C rise and 1.0% CO2 causes about a 68ºC rise, the catalyst has reached full activity. Approximately six hours of operation at design temperature or higher is generally sufficient to fully activate the catalyst. As reduction proceeds, adjust the heat-up rate by placing TIC-1012 in auto and increasing the set point on the methanator inlet. TIC-1012 controls in the following manner: -

TIC-1012 100%)

-

TIC-1012 (50%)

-

TIC-1012 (0%)

-

TV1012B TV1012A TV1012B TV1012A TV1012B TV1012A

fully closed fully open fully closed fully closed fully opened fully closed

TV-1012B will have a minimum stop at 5% open to prevent cooling and thermal shock to 172-C. Section 8 – Start-up Procedures

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As the methanation catalyst is being activated, the analyzers at the synthesis gas outlet of 114-C shell, AE-1003A/B, and 144-D, AE-1002, should be activated to monitor the quality of gas. Analyzers AI-1003A/B record carbon monoxide and carbon dioxide, respectively. AI-1002A, records methane; AI-1002B, hydrogen; AI-1002C, nitrogen; and AI-1002D, argon contents. The methane content is expected to be approximately 2.20 mol% (dry basis) when in normal operation. If, after the LTS converter is in service, the temperature differential across the methanator is approximately normal at 29°C and the methane content is higher, then it is likely that a higher rate of reforming is required in the primary reformer or optimization of the CO2 removal system is needed. The hydrogen percentage of the stream leaving 144-D should range between 60% and 65%, depending primarily on the air introduced to the secondary reformer. Adjustment of the H2 percentage will be made by making small changes in the process air flow on FIC-1003. If the percent of H2 is too high, additional process air is required and vice versa. This will be automatically done by ratio controller FFIC-1003 receiving signals from FN-1001 and FN-1003, computing the ratio, and resetting the FIC-1003 setpoint, if that system is in automatic remote. Gas samples are to be taken for lab analysis to confirm the analyzers are operating correctly. Adjust TIC-1012, 114-C tube side and 172-C shell side bypass, and 172-C steam flow to obtain about 300°C at the methanator inlet. Have a gas analysis done by the lab to verify the oxide content of the synthesis gas. Adjust the 106-D inlet / outlet temperature, if required, to obtain the conversion needed. Once 106-D has been commissioned, open 2” block valve on SG1500 to start recycle gas flow to 102-J suction. Any condensate in the line should be drained prior to lining up the flow to 102-J. Maintain 2% dry mol hydrogen in process feed stream through FIC-1703. 94. Increase Feed Rates 8.1.17.

OASE System

Analyze the circulating solution concentration. It should be near or slightly less than normal. Adjust the solution content, if necessary. Gradually increase the system circulation rates to 95% as front end rates are increased with the solution circulation set about 10% above the front end rate with one 117-J pump, one 108-J pump and pumps 107-JB and 107-JC on-line. • Semi-Lean

FIC-1005

2,960 ton / hr

Section 8 – Start-up Procedures

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Semi-Lean Lean 122-D1 Wash Water 121-D Wash Water 163-D Wash Water

FIC-1017 FIC-1014 FIC-1016 FIC-1018 FIC-1030

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650 ton / hr 600 ton / hr 6,366 kg/h 3,500 kg/h 1,100 kg/h

CAUTION Have the lab check the OASE solution strengths and loading on a regular basis and often during start-up as solution dilution can easily occur under low heat loads.

As rates are being increased, observe PDI-1042A/B, PDI-1043, PDI-1064 and level indicators LIC-1004, LI-1045, LI-1041, and LIC-1042 to ascertain if any flooding and / or foaming is occurring in the stripper or absorber towers. Watch AI-1023 exit 142-D2 for an increase in CO 2, which could be caused by over circulation or under stripping. As circulating rates are increased and additional gas flows through 121-D, maintain the normal system temperatures by adjusting the 106-C bypass, cooling water to 110-C.

8.1.18.

Start the Hydraulic Turbine

After the process feed rate and backpressure are at 85% of design or higher and the OASE solution circulation at 90% or more, there should be sufficient flow to start the 107-JAHT hydraulic turbine as follows: • Open the 107-JA discharge valve and suction valve • Open the seal flush lines as per Vendor instruction • Open the discharge 1” bypass valve to warm 107-JA pump if not already open. • Open the exit block valve for the hydraulic turbine 107-JAHT. • Open the flush lines as per Vendor instruction to the hydraulic turbine. • Vent the pump casing and the hydraulic turbine casing until gases are removed. • Open HIC-1004 inlet 107-JAHT around 10%. • Open the 0.75” inlet bypass valves around inlet block valve to start warming 107-JAHT turbine per the vendor’s recommended procedure / rate. • When 107-JA pump and the hydraulic turbine are sufficiently warmed, slowly open the inlet block valve to hydraulic turbine. • Once inlet block valve is fully open, open HIC-1004 to increase the solution flow through the turbine. LV-1004B will close automatically as the 107-JAHT begins to let solution through and LV-1004A will come into control. Section 8 – Start-up Procedures

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CAUTION Placing 107-JAHT in service must be done with great care. The level in 121D must be maintained to achieve maximum flow through 107-JAHT. There is a possibility of CO2 break through to the methanator if OASE flow to 121-D is reduced excessively.

• As soon as the 107-JAHT turbine is up to speed, LV-1004B is closed, and LV-1004A is controlling the level in 121-D, 107-JA will be pumping solution to 121-D so 107-JB or JC will need to be stopped. • Place the spare 107-J pump in hot standby. Be sure the suction and discharge block valves and the warm up bypass are all open. • As the 107-JAHT turbine / 107-JA pump is placed in service, the levels of the 163-D, 121-D and 122-D1 will be disturbed. • Normally, after start-up is completed, 107-JC pump is in hot standby. Auto start-up of the spare pump is activated by FSL-1005 if LALL-1045 is not indicating a low-low level inhibit. • Check the OASE system for concentration and CO2 loading. • Allow system to stabilize while monitoring closely. Please refer to Vendor Installation and Operating Manual. 8.1.19.

Primary Reformer

Increase the process steam flow on FIC-1002 to 90% of normal, 124.6 MT / hr. Gradually increase the Natural Gas feed rate FIC-1001 ~90% of design – 46,400 kg/h. This rate will yield approximately 2.7 to 1 steam / carbon mol ratio for 101-B. Allow the system pressure at PIC-1084 to increase to 30.0 kg/cm2G during this time. Increase PIC-1005 setpoint to 31.5 kg/cm2G or 1.5 kg/cm2G above PIC-1084. Increase firing as needed to maintain the tube outlet temperatures. 8.1.20.

Secondary Reformer

After each incremental increase of FIC-1001, the process air rate FIC-1003 will be increased to maintain the hydrogen / nitrogen ratio in the area of 1.8 to 1 as analyzed at 144-D by AI-1002, and laboratory verification. At 90% rate, the airflow should be about 128,500 kg/h.

Section 8 – Start-up Procedures

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Desulfurizer

As Natural Gas feed rates are increased, ensure the temperature at the inlet of the 101-D hydrogenator is maintained at 371°C and the sulfur content of the effluent stream is less than 0.1 mg / m3. Adjust TIC-1305 around the Natural Gas preheat coil in 101-B convection section accordingly to maintain a temperature of 371°C. 2

8.1.22.

Shift Converter

When rates are increased, control of the LTS inlet temperature by TIC-1011 may become increasingly difficult as the steam generation and BFW demands increase. TV-1011A may close to its minimum opening of 10% and the inlet temperature to the LTS may continue to fall below the setpoint. Should that occur, unblock FV-1020, put FIC-1020 in automatic and increase the flow enough to regain control on TIC-1011. 8.1.23.

Steam Systems

As feed rates are increased to the primary and secondary reformers, additional steam will be generated and consumed. Gradually raise the pressure of the HP steam header to 123.1 kg/cm2G by adjusting PIC-1018, if not already done. Ensure the steam superheat temperature is maintained at 510°C by adjusting TIC-1005A or, if too cold, by firing the superheater burners and adjusting TIC-1005. Ensure the pressure and temperature of the MP steam system is being maintained at 46.9 kg/cm2G by PIC-1013, and the temperature at 386ºC by TIC-1116 and TIC-1216. Ensure the pressure of the LP steam system is being maintained at 3.5 kPag by PIC-1017A/B to vent, injection to 101-JT, or PIC-1016 and temperature is maintained at 228°C.

8.1.24.

Start the 105-J Refrigeration Compressor

105-JT driving the 105-J refrigeration compressor is an extraction or backpressure turbine letting HP steam down into the MP steam system. The refrigeration system was previously purged with inert gas to less than 0.5% oxygen and filled with ammonia for ammonia cracking in the reformer. Isolate the drain lines from the 120-CFs to NH3 storage tank and to the flare – line OW2101. Section 8 – Start-up Procedures

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Open all of the interconnecting drain line isolation valves from the four drums to OW2101. Start a SMALL backflow of ammonia through piping NHL1034, NHL1052 and NHL1036 to 120-CF1. The ammonia will fill all drums at the same time through line OW2101. Some drums may fill faster than others and their isolation valves can be closed when the level reaches normal or slightly higher than normal. Although an increase in pressure is not expected, watch the pressure at PIC-1109, on vapor exit 149-D, and do not exceed 17.5 kg/cm2G as most of the relief valves will lift at 17.5 kg/cm2G.

8.1.25.

Start-Up Refrigeration Compressor 105-J

127-C cooling water is assumed to be in service since all three surface condensers are required by this stage of the start-up and 127-C is their source. Start the 105-J / JT refrigeration compressor following the vendor’s instructions in their IOM manuals: This start-up sequence assumes that all instrumentation has been commissioned and is ready for service, that all electrical power is available, electrical switches are in the OFF position and that all other valves are closed unless specifically noted otherwise. 1. Place kickback valves FIC-1009, 1010, 1011 and 1012 in automatic. These kickback controllers are head / temperature / pressure compensated controllers to prevent compressor surge. The valves will go fully open. 2. Place the dry gas seal control system and seal gas booster compressor, if supplied, in service. 3. Start the lube oil system. 4. Warm up the steam lines by opening valves on the following then open the bypass valve around the inlet HP and MP steam isolation valves: a. Inlet HP steam line isolation valve b. MP steam from the header to the extraction isolation valve c. All other valves as per the vendor’s instructions 5. Inlet valve HP steam isolation valve should be closed. Extraction valve to the MP steam header should be fully open. 6. Open inlet HP steam valve and close the bypass valves. Open the valves in vent line HS1181-3” to SP-154. 7. Open the 105-JT casing drain to warm-up of main turbine till there is no liquid in the case, then

Section 8 – Start-up Procedures

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close. 8. When the HP steam temperature to 105-JT reaches adequate superheat, turn the trip and throttle valve handle until the spring is compressed and the lever is engaged. It is now ready to open and admit steam. 9. SLOWLY open the trip and throttle valve by turning the handle. 10. After starting the turbine on slow roll at the vendor's recommended speed of 1500 rpm open the seal steam isolation valve and put seal steam on the turbine seals. WARNING NEVER put seal steam on the rotor if it is not turning. The uneven heating can cause the rotor to bend (warp) requiring the rotor to be replaced.

11. Close the valves in vent line HS1181-3” to SP-154. 12. Slow roll the turbine for 60 minutes while watching for any unusual temperature rises in lubricating oils, bearings, unusual noises, etc. Manually trip the turbine to verify the trip valve operation. Close the T.T.V., reset the trip lever and bring the turbine back to 1500 rpm. 13. The cooling water of the lube oil cooler shall be totally opened in order to allow the proper cooling water flow as indicated in the relevant documentation. During the Start-Up the TCV located on the lube oil console should be sufficient to avoid overcooling of the oil. The compressor start up permissive for the minimum oil temperature is 35 °C. In steady state conditions the temperature is 50°C. 14. After slow roll, if everything is normal, ramp the turbine to its minimum governor speed. 15. After warming-up at 1500 rpm for 60 minutes, gradually open T.T.V. Bring unit to 9148 rpm per the start-up diagram so that the governor takes the control of the turbine at 9148 rpm. 16. When the governor has control of the speed completely open T.T.V. The handle of T.T.V. shall be turned by half turn in a closing direction to prevent T.T.V. from becoming stuck. 17. Bring the turbine up to minimum governor speed. 18. Verify the flow rate to each 105-J stage through FIC-1009, 1010, 1011 and 1012. NOTE PIC-1009, through SIC-1005, will control the HP steam governor valve after start-up of the turbine.

19. Close all vent and drain valves used for 105-JT warming up. 20. When 105-J is stable, switch seal gas to 105-J discharge ammonia gas and shut down the seal gas booster. This must be done as slowly as possible to prevent pressure upsets in the system. Section 8 – Start-up Procedures

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21. Watch PIC-1018 to be sure that it controls (closes) the HP / MP letdown valves as 105-JT is started. 22. As soon as minimum flow is attained, the anti-surge controllers will start closing the anti-surge valves to bring the compressor to the surge control setpoints. This will build some pressure on the machine discharge and reduce pressures in the flash drums. Please refer to Vendor Installation and Operating Manual Doc. No. S0K6757856. Non-condensables, mainly nitrogen from the purging, accumulating in 127-C and 149-D will be vented through PV-1109. Place PIC-1109 in “remote” control to control the pressure to the saturation temperature of the liquid in 149-D. If the pressure increases too rapidly due to nitrogen accumulation, open PV-1109 bypass valve fully. The 105-J compressor is now in service on total recycle. It is feasible to continue this type operation for an indefinite period of time. Be sure to maintain levels in all flash drums to serve as a recycle quench. If levels could not be established prior to starting 105-J, they MUST be quickly established now to cool the recycle gases otherwise the compressor will overheat. As soon as the 105-J compressor is in service, establish an ammonia liquid level in 130-Cs Chillers by unblocking LV-1009/LV-1118, and place LIC-1009/LIC-1118 in automatic at the normal setpoint. Place PIC-1114 in service set at 3.5 kg/cm2G as a beginning point then adjust it as required to get the 4°C temperature required on TI-1363 inlet 144-D. Once 105-J is stable at minimum governor, HV-1028 HP to MP letdown valve needs to be commissioned. Be sure the HIC-1028 output is set to keep the valve fully closed then unblock HV-1028. Unblock TV-1116 and set TIC-1116 min automatic at 386°C. Set XS-1128 to match the flow as indicated on FI-1125 (a valve opening versus flow table will need to be developed to determine the correct setpoint) 8.1.26. 2

Commission 120-J

Start the 120-J pump as follows: • Open the suction isolation valves to the pump. • Prime the pump if necessary by opening the bypass around PRV-120J • Isolate the following valves: o NHL1147 to 124-C • Open the discharge valve then start the pump. Section 8 – Start-up Procedures

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CAUTION 120-J is a positive displacement pump so do not run this pump without an open flow path to 124-C.

8.1.27.

Start-Up Synthesis Gas Driers 109-DA / DB

When analysis of the gas venting from 144-D is within specifications, for both gas composition and moisture content, the 109-DA / DB synthesis gas driers can be started. Prior to starting 109DA / DB, a leak check of the molecular sieves using nitrogen should be carried out and any leaks found should be repaired immediately. The gas composition is critical and should be as follows in dry mole%: • Hydrogen 64.94% • Nitrogen 32.47% • Methane 2.20% • Ar 0.39% • NH3 Trace maximum • Water 268 ppmv (490 maximum) Align the driers as follows: • Close MOV-1051 using DCS handswitch HS-1051 and 1½” bypass on line SG1009-24” to 132-C. • Open MOV-1052 using DCS handswitch HS-7815 132-C Purifier Bypass valve on line SG106514” to the 103-J suction. • Close MOV-1053 using DCS handswitch HS-1053 manual isolation valves and the 1.5” bypass valves on line SG1411-18” on the outlet of 132-C and the other to 103-J suction. • Close SG1414-8” synthesis gas regeneration source line. • Set PIC-1004 to manual with PV-1004 fully closed and the isolation valves locked open. • Open MP steam to 183-C tube side and place LIC-1050 in service to 101-U. • Manually open FIC-1046 on the shell side outlet of 183-C. • Set TIC-1040 to manual and fully close the valve. • Set PIC-1008 to manual with PV-1008 fully closed. • Confirm that PIC-1029 Secondary Fuel Gas Vent is in automatic mode with a setpoint of 1.0 kg/cm2G.

Section 8 – Start-up Procedures

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CAUTION This write-up assumes that 109-DA starts in service with 109-DB in stand-by or regeneration but either molecular sieve could be in any step position. The correct valves to be opened based on the current 109-Ds program step MUST be ascertained BEFORE pressurizing is started to avoid damage to the sieves and downstream equipment.

• Verify MOV-1015 is fully open. • Slowly open PV-1049A isolation valve to pressure 109-DA through to PV-1004, if PV-1049A is open. • After the pressure in 109-DA equals the pressure at PIC-1084, open MOV-1017 fully. If PV1049A is NOT open, slowly open MOV-1017 until a gas flow is heard then wait until the pressure equalizes before fully opening the MOV-1017 • Put PIC-1004 into automatic mode with the setpoint equal to the existing pressure. • Place HIC-1022 into manual mode with HV-1022 fully open, if the PLC does not already have it open on automatic remote. • Place HIC-1023 into manual mode with HV-1023 fully closed, if the PLC does not already have it open on automatic remote. • The Waste Gas Filter, 144-L, can be put in service with the bypass closed. The flow path through 144-L must be open. • The Molecular Sieve outlet Gas Filters, 154-LA/LB, can be put in service. The flow path through 154-Ls must be open. Slowly start closing vent valve PIC-1084 and start venting at PIC-1004. Close PIC-1084 fully. If PIC-1005 is still open, slowly increase the setpoint until all of the gas is venting at PIC-1004. Place analyzers AI-1014, H2O, and AI-1020, CO2, in service at 109-DA / DB exit. 2

Place AE-1029 analysis system in service at the purifier exit. Slowly open both 3” valves on line SG1414-8” to line SG1045-20” to start / continue a flow of process gas out through PV-1029. With FIC-1046 in manual mode, slowly increase the output of FIC-1046 to the setpoint from the PLC (the value to be determined in consultation with Mol Sieve supplier due to the gas molecular weight difference of the process gas being approximately onehalf of the normal Purifier Vent Gas) then place into automatic remote. Place PIC-1008 into automatic mode with a setpoint of 1.2 kg/cm2G. The valve will remain closed.

Section 8 – Start-up Procedures

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Regenerate the Molecular Sieve Dryers

The 109-DA / DB dryers can be regenerated as soon as a gas flow has started through 109-DA or DB to or bypassing 132-C to the Synthesis Gas Vent PIC-1004. The dryer desiccant is shipped in a dry state but, during loading, it will have absorbed some moisture. Therefore, the dryers should be regenerated a minimum of two cycles each before starting synthesis gas to the synthesis loop or the Purifier. Either dryer could be in the lead position but for this regeneration write-up we will assume that 109-DA is in service and 109-DB will be regenerated first and is at the first step. The sieves will pressure up and, with the following sequence, regeneration can be started with the following flow path. • Through MOV-1017 through 109-DA with MOV-1018 closed. • Outlet 109-DA through MOV-1015 with MOV-1016 closed. • Through 154-LA to 3” valves in line SG1414 and to PV-1004 bypassing the purifier. • To line SG1045 through FI-1075 to line SG1111 to 183-C. • TV-1040 closed on manual. • Through 183-C and FIC-1046, line SG1412 to 109-DB regeneration gas inlet • Through XV-1161 (XV-1160 closed) to bottom of 109-DB. • Back flow through 109-DB and through XV-1165 (XV-1164 closed) through HV-1022 to 144-L inlet. • Regeneration gas will vent through PIC-1029 after passing through 144-L. When the 109-DB bed outlet has reached a minimum 210°C, on TI-1043, the regeneration is deemed complete and the bed will be cooled down to the same temperature as indicated by TI1663, by logic timing. If the bed does not reach 210ºC, the operator can place HS-1014 in “Stop” to lengthen the heating time if required. CAUTION Lengthening the timing in this manner may lengthen the on-line time of the other dryer leading to saturation and break through of CO2 and water.

Section 8 – Start-up Procedures

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NOTE The dryer’s automatic logic control system will control the temperature ramping in both directions but the above conditions should be met for good dryer regeneration.

After 109-DB has been regenerated, it will be automatically switched to the lead position and 109-DA will be regenerated using the same general procedure as above. With both 109-DA / DB regenerated twice, the synthesis gas can be considered ready for forwarding to the synthesis loop and catalyst reduction if the outlet gas analysis meets or betters design conditions. Cool down of the Purifier can begin. Detailed operation and regeneration logic procedures can be found in Section 7 of this manual. 8.1.29.

Cryogenic Purifier Start-up

The Synthesis Gas Driers should be delivering Purifier Feed at a Temperature of 4°C with less than 1 ppmv of combined water, ammonia and carbon dioxide and a hydrogen / nitrogen ratio very close to 2 / 1. 8.1.30.

Cryogenic Purifier Dryout

The equipment will have been tested, purged, and blanketed with nitrogen prior to start-up. All traces of water in the system must be removed before the equipment is cooled down. This can be accomplished ahead of the initial start-up. If done prior to regeneration of the 109-Ds nitrogen heated up in the Mole Sieve Regeneration Heater, 183-C, must be used. Drying can be done when process gas is available during the initial start-up following the 109-Ds regeneration. Warm Nitrogen Dryout The Purifier MOVs, isolation valves and bypasses in lines SG1009-24” and SG1411-18” must be fully closed. The removable spools inlet the Purifier in line SG1009 must be installed. Install the removable spool in the Purifier deriming line, SG1049-3”. 131-JX expander outlet butterfly valve HV-1302 must be open.

Section 8 – Start-up Procedures

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Isolate the Mole Sieve Regeneration Heater, 183-C, by closing the valve in the outlet line, FV1046. The inlet line SG1111-14” must also be partially isolated by manually closing PIC1008. Commission MP steam to the Mole Sieve Regeneration Heater, 183-C. Line up nitrogen flow to the five deriming connections for the Purifier and fully open the globe valve in line SG1049. Start the flow of nitrogen from line N1254-2” and permit warm nitrogen (~35°C) to flow through the Purifier Feed / Effluents Exchangers, the Purifier Rectifier and the Purifier Rectifier Condenser to the cold vent header through lines V1100 and RV2410 (bypass of PRV-132C2) . Use TIC-1040 to control the temperature of the dryout nitrogen. Do not allow the nitrogen temperature to exceed 65°C. Permit warm nitrogen flow through the shell side of the Purifier Rectifier Condenser, 134-C, shell side by opening control valve AV-1029 and its bypass to send warm nitrogen through the exchanger the Purifier Feed / Effluents Exchangers to the vent header. Permit warm nitrogen flow through the purifier feed side of Purifier Feed Effluent Exchanger by opening the expander bypass valve, PDV-1022. Continue warm nitrogen flow until the effluent nitrogen sample has a dew point of -65°C. Block-in under 3.0 kg/cm2G of nitrogen pressure. 8.1.31.

Process Gas Dryout

This cannot be done until the front end is running and producing dry synthesis gas from the Synthesis Gas Driers, 109-Ds. While the Purifier is still bypassed, and deriming completed check that all warm-up connections in the system are closed. Remove the removable spool from deriming line, line SG1049-3” and install a blind flange with the correct piping class rating. Close inlet to the 131-JX Purifier Expander using HV-1111. Set PIC-1008 on automatic at 1.2 kg/cm2G. Open the expander isolation outlet valve HV-1302.

Section 8 – Start-up Procedures

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Put the purifier expander differential bypass controller, PDIC-1022, on manual with PDV-1022 open fully. Put AIC-1029 in manual and fully close. Open 1.5” bypass around MOV-1053 on the outlet of 132-C and slowly pressure up the purifier backwards. When the 1.5” bypass is fully open, open MOV-1053 to 103-J and close the 1.5” bypass valve. When the pressurizing of the Purifier is complete, open MOV-1051 to 132-C. Open the make-up hydrogen control valve, AV-1029 using AIC-1029. Using PDIC-1022 in manual, open PDV-1022 to pass approximately 15,000 kg/h of Purifier feed to the waste gas system. This flow will be indicated on FI-1075 and flow through PV-1008. Close the 3-inch ball valve to line SG1414-8” out of 109-DA / DB which has been used as a temporary regeneration gas for 109-DA / DB. Close and open AV-1029 and the ball valve in line SG1414-8” together to maintain the flow indicated at FI-1075 as constant as possible. After the 3-inch ball valve is closed then close the 3-inch isolation block valve. NOTE AV-1029 is sized for flashing liquid, it may not be possible to pass 15,000 kg/h of Process Gas. Open AV-1029 bypass to supplement the total flow.

8.1.32.

Purifier Cool Down

Verify MOV-1051 is open with the removable spool in place and MOV-1053 is open. Set PDIC-1022 on automatic and increase the setpoint to 2.0 kg/cm2G. PDV-1022 will be fully open until the system is reset on HS-1113A handswitch Slowly close MOV-1052. Put the Purifier Rectifier bottoms level controller, LIC-1034, in manual and adjust to zero percent output. Put HV-1111 in remote operation Start the Purifier Expander and generator, 131-JX / JG as following the vendor’s instructions in Section 8 – Start-up Procedures

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their IOM manual: 1. Fill the lube oil reservoir with oil. 2. Open isolating valve in SG1008-0.75” to supply seal gas to expander and set the flow rate to 185 Nm3/h. 3. Open the expander casing drain. After the expander case is dry, close the expander case drain valves. 4. The 131-JX IGVs do not fully close. If you reset the shutdown switch to open XV-1172, a large quantity of process gas starts flowing through 131-JX and upsets the front-end pressures. To prevent this type of upset close outlet butterfly valve HV-1302 from 131-JX then open XV-1172. 5. Open shutdown valve XV-1172 using handswitch HS-1113A. 6. Slowly open outlet butterfly valve fully HV-1302 to start 131-JX rolling then slowly open the Purifier Expander, 131-JX, inlet guide vanes by using HV-1111 until the Purifier Expander bypass differential pressure control valve, PDV-1022, is 0% to 5% open. 7. Close the expander bypass valve PDV-1022 by increasing the setpoint, if necessary, as it will close automatically to maintain 2.0 kg. 8. Open the expander IGVs to admit process gas to the expander so that it starts to rotate at about 1500 rpm by increasing HV-1111. Monitor all gauges and ensure that speeds stabilize, which may require five minutes or more. This should provide time to break in new seals and verify that lube oil to expander bearings are at the correct pressure. 9. Bring the expander up to respective design speeds by further opening the IGVs using HV-1111. The generator will energize at 95% synchronous speed, 2865 rpm. Once the generator is energized, increase the expander to full speed and power to load the generator. NOTE Avoid excessive IGV movement such as “hunting”, because the IGVs and linkage for the expanders are not lubricated.

10. Check seal gas system pressure gauges. Observe that the supply pressure is normal which is between 0 and 35.7 kg/cm2G and seal gas flow of 185 Nm3 /h is obtained. 11. After the expander reaches its normal speed, close the expander bypass valve PDV-1022 tightly by increasing the setpoint on PDIC-1022. Please refer to Vendor Installation and Operating Manual Doc No TBD. Increase the pressure drop across the Purifier Expander, 131-JX, by closing the inlet guide vanes and lowering the setpoint of the Synthesis gas Compressor suction vent pressure controller, PIC1004, to compensate for the increase in the differential pressure of the Purifier Expander, 131-JX. Increase the setpoint of the Purifier Expander bypass differential pressure controller, PDIC-1022, Section 8 – Start-up Procedures

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to maintain the position of PDV-1022 between 0% to 5% open during the Cryogenic Purifier cool down period. Allow the Cryogenic Purifier to cool down at a maximum rate of about 25°C / hr. Do not exceed a temperature difference of 50°C between the Purifier Expander outlet and Purifier Rectifier inlet by adjusting the Purifier Expander, 131-JX, differential pressure. To cool down the Purifier Rectifier at a similar rate as the Purifier Expander, bypass a portion of the Purifier Expander discharge directly into the Purifier Rectifier, 137-D. Use the 2-inch deriming line SG1082 from the Purifier Expander discharge line, SG1049-3”, to the Purifier Rectifier inlet line. Separation will occur near the end of cool down. AIC-1029 will indicate a steady increase in hydrogen concentration in the make-up gas. The differential pressure of the Purifier Expander, 131-JX, should at this time be between 2.0 and 3.0 kg (but can be as high as 5.0 kg) , however, when the liquid comes, it comes quickly. Cool down of the Purifier is faster with this method, but it can lead to upsets when the pressure drop must be reduced quickly as liquid level appears in the bottom of 137-D. If 103-J has been started, it will be better to use a lower 131-JX pressure drop and take longer to cool. CAUTION BE PATIENT: Let the Cryogenic Purifier remain in the above condition. The liquid will come. If the liquid level is not detected by LIC-1034A within two hours after achieving the separation temperature of -178.6 °C, check the calibration of LT-1034B to determine if it is adjusted and / or operating correctly. The Purifier Rectifier differential pressure gauge line, from LT1034A to PDT-1879, has a tap to bleed gas from 137-D to determine if liquid is above the upper level transmitter tap.

When liquid in the bottom of the Purifier Rectifier, 137-D, is indicated by LIC-1034, the liquid level will rise quickly. Open the inlet guide vanes for the Purifier Expander, 131-JX. Increase the setpoint of the Synthesis Gas Compressor suction vent pressure controller, PIC-1004, to compensate for the decrease in the differential pressure of the Purifier Expander, 131-JX. After the Purifier Rectifier, 137-D, bottoms liquid level is stable, adjust make-up gas hydrogen content by changing the amount of liquid taken from the Purifier Rectifier bottoms through AV1029. Line out the Cryogenic Purifier system to produce make-up gas with a 3 to 1 hydrogen to nitrogen ratio.

Section 8 – Start-up Procedures

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Start-Up Synthesis Gas Compressor 103-J

The 103-J / JT compressor train can be started on total kickback in preparation for admitting synthesis gas to the synthesis loop while the 137-L Purifier is being started or bypassed. This start-up sequence assumes that all instrumentation has been commissioned and is ready for service, that all electrical power is available, electrical switches are in the OFF position and that all other valves are closed unless specifically noted otherwise. All purging and pressure testing are complete. It is assumed that the 103-JT overspeed trip test has been completed and accepted and that all couplings are installed. Start the synthesis gas compressor following the vendor’s instructions found in their IOM manuals: 1. Depressure the compressor synthesis gas system to approximately 1.5 kg/cm2G by blowing down through low points. 2. Confirm cooling water flow through 116-C tubes and 124-C tubes. 3. The surface condenser, 103-JTC, is already in service. 4. Confirm that all instruments are in service. 5. Commission the dry gas seal controls system and seal gas booster compressor, if provided. WARNING The main Lube Oil pump shall be started only after checking from the operator of all the permissive as indicated in the functional description (N2 on the compressor barrier seals, proper Oil Level in the tank, proper oil temperature in the tank). 6. Regularly check the following operating conditions: a. Primary seal gas o Filter differential pressure o Seal gas differential pressure o Seal gas flow b. Primary leak-off line o Leak off flow c. Verify that there is no liquid accumulation in gas seal filter. 7. Verify that all of the steam inlet and extraction isolation valves and bypasses are closed. 8. Open the drains on steam supply and extraction lines. Blow until dry. 9. Verify that T.T.V. / G.V. /seal steam valves are closed. 10. Open the turbine and T.T.V. drains. 11. Slowly open the small bypass around inlet HP Steam block valve and vent through warm up line HS-1180-3” to SP-154 to warm the HP steam supply line. Section 8 – Start-up Procedures

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12. Verify the valve is closed then start a small flow of condensate to PRV-103JTC to establish a seal on the valve seat. 13. Slowly open the small bypass around block valve to warm the steam extraction line and the turbine casing. Vent through all casing / piping drains. 14. Verify correct flow / pressure of lube oil to all bearings. Verify correct control pressure is available. While the turbine and steam piping are heating the following items can be accomplished on the compressor. 1. Lock open the isolation valve in the recycle line SG1018-20”. 2. Confirm that the anti-surge valves FIC-1007, FIC-1008, and FIC-1059 are in automatic and fully open. 3. HIC-1101 to 121-C is fully closed with bypasses closed. 4. HIC-1033 exit 121-C shell is fully closed with bypasses closed. 5. Line up as follows for 103-J startup on recycle: (some tasks were previously done) a. Close the isolation valves inlet and outlet of 124-D HP Ammonia Absorber. b. Close the upstream isolation valves of PV-1033A going to 130-C1 and FV-1029 to 101-B Fuel. ( @ 124-D ) c. Open the upstream isolation valve of PV-1033B to Ammonia Vent and place PIC-1033 on automatic set at 40.0 kg/cm2G. d. Open the 3” bypass valve of 124-D, line SG1029-3”. e. Open the upstream and downstream isolation valves of FV-1024, place FIC-1024 on manual and close the valve. 6. Close all drains on 103-JT casing and the extraction steam line. 7. Check that the 103-JT exhaust vacuum is at 77.6 mmHga or better. WARNING Do not attempt to start the 103-JT if the vacuum is less than recommended as the turbine will overheat and serious damage could result. 8. Open block valve on extraction steam line and close both bypass valves. 9. Open HP steam isolation valve and XV-6410 in accordance with vendor guidelines. 10. Begin the rolling warm-up of 103-JT following the steps in the IOM: a. Turn the trip and throttle valve handle until the spring is compressed and the lever is engaged. It is now ready to open and admit steam. b. SLOWLY open the trip and throttle valve by turning the handle counter-clockwise. As the turbine starts to roll confirm that the turning gear disengaged. Turn the turning gear motor off.

Section 8 – Start-up Procedures

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NOTE PIC-1013 will control the governor valve after start-up of the turbine. HIC1006 / PIC- 6569 will control the process gas pressure and vary the speed to control the pressure. 11. After starting the turbine on slow roll at 2000 rpm, open the sealing steam isolation valve and put sealing steam on the turbine seals at a pressure of 3.5 kg/cmG. WARNING NEVER put seal steam on the rotor if it is not turning. The uneven heating can cause the rotor to bend (warp) requiring the rotor to be replaced. 12. Slow roll the turbine for 90 minutes while watching for any unusual temperature rises in lubricating oils, bearings, unusual noises, etc. 13. Manually trip the turbine to ensure trip valve operation. Close the T.T.V. and reset all turbine trips as above. Bring speed back to 2000 rpm. 14. The cooling water of the lube oil cooler shall be totally opened in order to allow the proper cooling water flow as indicated in the relevant documentation. During the Start-Up the TCV located on the lube oil console should be sufficient to avoid overcooling of the oil. The compressor start up permissive for the minimum oil temperature is 35 °C. In steady state conditions the temperature is 50°C. After slow roll, if everything is normal, ramp the turbine to its minimum governor speed 9200 rpm. 15. After warming-up at 2000 rpm for about 90 minutes, gradually open T.T.V to increase speed to 9184 rpm. The governor will take the control of the turbine at 9184 rpm. 16. When the governor has control of the speed completely open T.T.V. 17. After the completion of warming-up at 2000 rpm for 90 minutes. Speed reference will be increased to minimum governor speed of 9184 rpm. 18. Close HP steam vents and drains. 19. Verify that the condenser vacuum remains at 88.3 mmHga or better Condenser vacuum shall be kept constant, observing pressure gauge and turbine speed. 20. The critical speed passing band is from 4200 rpm to 4700 rpm. 21. The turbine normally ramps up to the minimum governor speed at 600 rpm / min ithrough the critical speed bands. speeds are: 22. While passing through the critical speed band, observe the turbine vibration carefully. If necessary due to increased vibrations, slow down to approximately 2000 rpm for an extended warm-up period. As soon as minimum flow is attained, the anti-surge controllers FIC-1007, FIC-1008, and Section 8 – Start-up Procedures

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FIC-1059 will start closing the anti-surge valves FV-1007, FV-1008, and FV-1059 to bring the compressor to the surge control setpoints. This will build some pressure on the machine discharge. Please refer to Vendor Installation and Operating Manual Doc. No.S0K6757855 .

8.1.34.

Pressure Testing of the Synthesis Loop

The synthesis section will be pressure tested at 70.0 kg/cm2G, using synthesis gas as follows: The pressure test will include 103-J discharge and the entire synthesis loop. The initial alignments are: • HV-1101

Close

- 2” bypass closed ( bypass will be opened to check the “hot” loop)

• • • • • • •

Closed Open Closed Closed Open Closed Open

-

HV-1033 HIC-1044 HIC-1046 HIC-1025 HCV-1047 HIC-1019 FIC-1059

exit 121-C shell. 105-D inlet. 105-D Cold Shot 105-D Cold Shot 102-B inlet loop vent controlling the required 103-J recycle flow

Leak testing consists of seal wrapping every visible non-welded joint. The seal wrap is punctured with a single 2 mm or 3 mm hole. Leakage is detected by bubble testing the hole with a soap solution or a gas detector. A thorough leak inspection is made on each joint at each incremental pressure level. The pressure test entails gradual incremental pressure increases of 17.5 kg/cm2G per increment, inspecting for leaks and tightening where necessary. Checking the “cold” loop in this manner will involve holding 103-J speed at some intermediate levels until checking is completed. The loop will be at some starting pressure when 103-J reaches minimum governor with FIC-1059 in automatic controlling the flow. This will be the initial testing pressure. If leakage is found at any pressure level, take the necessary corrective action. It is usually easier to stop flange leaks by reducing the pressure to the previous level or lower, tightening the flange (repairing the leak), and then increasing the pressure to its original level for retesting. 103-J speed will be increased to check the next level, When testing is complete at 70.0 kg/cm2G, the system pressure will be reduced in preparation Section 8 – Start-up Procedures

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for catalyst reduction. Pressure the “hot” loop by opening the bypass valve around HV-1101 until 17.5 kg/cm2G is attained on PG-1632 or PG-1633 then perform a leak check. If the check reveals no leaks, increase the pressure an additional 17.5 kg/cm2G and check again. Continue increasing until 70.0 kg/cm2G is reached and all leaks are repaired. It will be necessary to open HV-1101 and / or speed up the 103-J to attain the required pressure. 95. Synthesis Converter Catalyst Reduction 8.1.35.

General

This procedure assumes that the following steps have been completed: • Loading of the converter catalyst as described in the catalyst loading procedure. • Synthesis loop equipment, instruments and controls have been checked out for operability. • The front end or purifier is lined out to supply 3 to 1 Hydrogen : Nitrogen ratio. • The converter steam generators 123-C1 and 123-C2 are ready for service. • Pressure testing of the ammonia synthesis loop has been completed. 8.1.36.

Water Content

The primary control for the reduction of the converter catalyst and the rate of heat-up is the water evolution from the catalyst. It is very important that the converter effluent should never contain more than 2,500 ppmv of water (or whatever maximum the catalyst vendor requires). Water analysis of the converter effluent should be done at least once every two hours, preferably every hour during the later period of the catalyst reduction. The water content in the converter catalyst effluent can also be checked by keeping a record of the water accumulation in 147-D Ammonia Letdown Drum. 8.1.37.

Refrigeration System

Ammonia synthesis will occur simultaneously with catalyst reduction at the latter part of the reduction program. The ammonia refrigeration compressor, 105-J, is in operation and the chillers are in service. Adjust the speed of the Ammonia Refrigeration Compressor to maintain the temperature of the Chiller, 120-CF1, shell side above 0°C to prevent freezing of water in the tubes.

Section 8 – Start-up Procedures

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In order to accomplish this, it will be necessary to empty the levels in 120-CF2 and 120-CF1 flashdrums by pumping the ammonia to 149-D from 120-CF1 using 113-Js through line NHL1156. This can also be done by placing the level controllers LIC-1022 and LIC-1023 in manual and closed then increasing the levels in 149-D, 120-CF3 and 120-CF4 to accommodate the level from the other two. It MAY be possible to only have to empty 120-CF1 based on recycle temperature to 146-D. In order to maintain cooling for the kickback stream to 105-J from the empty flashdrums, ammonia from 120-CF4 must be injected into the 120-CF2 and 120-CF1 kickback gas streams using line NHV1110-3”. Open and adjust the globe valves in the kickback lines from FV-1011 and FV-1012 to control the temperatures to 105-J. An additional protection to prevent freezing in the 120-CF tubes is to inject ammonia into the gas stream to lower the freezing point of any water formed during catalyst reduction. This is accomplished using 120-J from 149-D. Place 120-J in service as outlined before and open line NHL1147 to inject ammonia into the 124-C inlet line. This injection should continue until the ammonia concentration in the gas steam is high enough so that the aqua ammonia formed will not freeze then 120-J injection can be stopped. 8.1.38.

Catalyst Poisons

Sulfur, halogen compounds and phosphorus are permanent poisons to the catalyst. Exposure to oxygen, water, carbon monoxide and carbon dioxide impairs the activity of the catalyst. NOTE If this typical procedure conflicts with procedure or method presented by the catalyst manufacturer, then the catalyst manufacturer’s procedure will take precedence.

8.1.39.

Synthesis Loop Reduction Alignment

The 103-J compressor should be operating on total recycle cold loop circulation, at a speed that is developing enough discharge pressure to maintain 85.0 kg/cm2G in the synthesis loop. The synthesis loop will then be aligned as follows: • Place analyzer AE-1029 in service • Place LIC-1013 in automatic at its normal level setpoint and unblock LV-1013 • Place PIC-1108, at 147-D, in automatic at a setpoint of 17.0 kg/cm2G with PV-1108 isolation valves open. Section 8 – Start-up Procedures

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Be sure the 123-D is isolated and bypassed if not in service with PIC-1038 set at 14.5 kg/cm2G. PV-1038A should be isolated and PV-1038B line up to vent to the flare. Fully open HCV-1047 in line SG1026-12” inlet of 102-B heater. After the above valve is fully opened, close HIC-1046 and HIC-1025, if they are open. Open HIC-1044 to 25% as a starting point – this will be adjusted later as required for flow balancing Unblock HV-1019 but have the valve fully closed on HIC-1019 controller.

Prepare 102-B fuel gas system for burner firing: • Open the burner dampers in the bottom of 102-B. 2 • Purge 102-B with steam for at least 15 minutes before lighting a burner. • Check for the absence of combustible gas in the furnace chamber of 102-B by means of the flammable gas detector through the observation ports. • Open HV-1101 2” bypass and pressure up the “hot” loop. • Set HIC-1101 to zero then relatch solenoid valve HY-1101 using DCS reset handswitch HS1101, if not already done. Once the pressure is equalized, slowly open HIC-1101 until HV-1101 is fully open, close its 2” bypass valves.

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Slowly open HIC-1033 sufficiently to establish a flow through 102-B of about 30,000 kg/h on FI1257B. Slowly adjust HIC-1044 and establish a flow through 105-D annular space by balancing with the FI-1257B flow. Continue to increase the annular flow until the flow on FI-1257A through the heater and through the converter annular space FI-1105 are approximately equal by opening HIC-1044. FIC-1059 will start closing automatically to establish circulation through the synthesis loop. It is expected, the following flows can be achieved through the start-up heater and through the converter annular space. • FI-1257B : 30,000 kg/h • FI-1105 : 30,000 kg/h

CAUTION Local flow indication FI-1257A is not corrected for pressure and temperature deviations and will read considerably different than FI-1257B which is corrected.

Section 8 – Start-up Procedures

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The 105-D ammonia converter shell is limited to a 55°C temperature differential from top to bottom. To achieve this it will be necessary to establish a high flow rate through the 105-D annular space. Adequate opening of HIC-1044 will be required to do this. Purge and ignite burners in 102-B as described in Section 7 of this manual to start heating the process stream at a rate of 15°C / hr. Light the pilots first then light small flames on every other burner until all burners are lit while maintaining the heating rate. CAUTION During the initial start-up the Start-up Heater firing increase will be limited initially by the 102-B refractory dryout schedule, if not dried out before. See Section 6 of this manual.

8.1.40.

Ammonia Converter Catalyst Reduction

Reduction of non-pre-reduced catalyst normally starts at about 360°C. The space velocity should be kept as high as possible consistent with the size of the start-up heater. The heating rate should be adjusted to limit the water content in the reactor effluent to a maximum of 2,500 ppm or whatever the catalyst vendor has directed. The average temperature increase is normally 10°C to 15°C / hr. The minimum reduction time is ~5 days. The pressure should be kept at 85.0 kg/cm2G. Higher pressure during reduction makes the controlling the temperature increase in the final stage of reduction much more difficult. Activation of pre-reduced catalyst can start at about 200°C although it is usually closer to 250°C. Normal average heating rate is 10°C to 15°C / hr. Otherwise, the conditions with regard to gas flow and pressure are the same for reduction and activation. The minimum activation time is ~1½ days. The catalyst reduction procedure is divided into three periods or phases. They are as follows:

Temp. Phase (Hot Spot) (0C) 1 Amb - 343 2 343 - 427 3 Heater is taken off

Rate of Temp. Increase (0C/hr) 10 to 15 2 to 6

Pressure Increase (kghr/step) 3.5 3.5

Section 8 – Start-up Procedures

Approximate Length of Periods (hrs) 30 60 40

Pressure (kg/cm2G) 85.0 8.00 85.0 to 157.0

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The above numbers are estimated and should be adjusted based on catalyst used and instructions of the vendor's service representative. 8.1.41.

Phase 1: Inlet Temperature to 343°C

Many things will have to be adjusted during this period and it is impossible to outline every step in its proper time sequence. What will be presented is a broad outline with emphasis on the overall procedure and how it is to be accomplished. With the start-up heater fired and gas flow established through the converter, the basic objective is to heat the catalyst in Bed No. 1 to a bed temperature of 343°C over a period of about 30 hours, raising the temperature at 10°C to 15°C per hour. As the 343°C temperature is approached, slow the heat up rate to 2°C to 6°C / hr. The following operating conditions should be maintained: • Loop pressure should be held at 85.0 kg/cm2G. • Rate of temperature rise should be held at 2°C to 6°C / hr. as indicated by the hot spot temperature in the top bed. • Flow through the converter annular space should be maintained as high as possible to limit the 105-D top and bottom shell temperature differential to 55°C maximum. 8.1.42.

Start-Up Heater Precautions

NOTE Low synthesis gas flow through 102-B is detected by FT-1257 which trips the fuel gas trip system (XV-1250A / B / C) and pilot gas (XV-1255A / B / C). If the synthesis compressor has to be shut down or trips during the reduction procedure, the first step is to verify the shutoff of the fires to the start-up heater and continue a flow of gas through the heater and converter until the 105-D catalyst temperatures have been reduced approximately 50°C below the existing reduction temperature. If synthesis gas pressure is totally lost in the loop for any reason, the loop must be kept under a positive nitrogen pressure. As flow and temperature are increased, the 102-B heater will approach its design combustion rates. If additional temperature is required, flow through the heater coils can be reduced, but never to a point where overheating of the coil could occur. The design temperature for the 102-B transition cone of 538°C at TI-1397 shall not be exceeded. The heater coils are protected from over-temperature by TI-1396 which will trip the burners if a Section 8 – Start-up Procedures

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high-high temperature is reached. Overheating of the startup heater coils is prevented only by the flow of gas through the coils to remove the heat from the burners. If for any reason the synthesis compressor is shut down the fires in the heater go out by action of FALL-1257. The fuel gas to 102-B can also be stopped by action of hand switches HS-1257 in the control room or HS-1257A locally. WARNING Be sure to operate the 102-B process outlet within the design pressure / temperature limitations. As the pressure increases, the maximum allowable temperature decreases significantly and not linearly. It is unlikely that the heater coil will need any cooling flow after the loop pressure has dropped to a level approaching that of the compressor suction. Under these reduced flow conditions, the temperature of the gas leaving the heater will rise sharply, but the heat absorbing capacity of the piping, the converter baskets, and the catalyst beds will prevent any appreciable temperature rise in the catalyst bed itself. Pay careful attention to start-up heater pressure and temperature limitations, maximum coil outlet temperature, maximum stack temperature, and draft. Adjustment of flow will mainly be accomplished by using the 121-C shell outlet valve HIC1033, but flow changes may also require adjustments to the 103-J compressor operation and may require an adjustment to the flow balance on the 105-D shell and inlet from 102-B. Water formation may start at a relatively low temperature, approximately 200°C although it is usually higher. The converter effluent gas should be sampled and checked at the outlet of 121-C exchanger shell for water content. The rate of temperature increase should be reduced if the water content exceeds 2,500 ppm during the early part of reduction. The ammonia / water vapor being produced will be condensed in 120-C, recovered in 146-D and let down to 147-D. This condensate can be manually drained for disposal or sent to the cold ammonia storage tanks. This should be done as soon as practicable. Place LV-1012A in service to supply ammonia from 147-D to 120-CF1 and then pumped to ammonia storage by 124-Js. Flow changes in the heater and converter will require balancing adjustments on the synthesis gas compressor. Speed must be varied, as required, to maintain stable conditions. If during heat up and reduction the 105-D shell temperature difference exceeds 55°C, the synthesis loop must be Section 8 – Start-up Procedures

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adjusted on recycle operations to obtain enough flow through the converter annulus to limit this critical difference. The 105-D bed temperature is raised at a rate of 10-15°C / hr. observing a maximum temperature difference between the coil outlet temperature of 102-B (TI-1396) and the outlet temperature of 105-D (TI-1374) of 200°C. Also, during the first part of the heating-up, when the catalyst temperatures are low, the outlet temperature of 102-B (TI-1396) should preferably be kept not more than 125 to 175°C above the highest temperature in the catalyst bed. If the temperature in the catalyst bed is erratic and tends to stick at approximately 100°C, purge the thermowell with the nitrogen as this may be an indication of moisture in the well. NOTE HIC-1025 cold gas quench use should be restricted when the 102-B is being fired. This stream and the 102-B use a common line to the converter; therefore, opening of HIC-1025 could cause thermal shocking of the line. The first bed temperature will be adjusted by controlling the firing of the 102-B start-up heater. 8.1.43.

Phase 2: First Bed Activated - Hot Spot From 343°C to 427°C

After the 400°C hot spot temperature is reached in the first bed, it will be necessary to reduce the temperature increase rate to approximately 2°C to 6°C or less per hour to maintain the converter effluent water content at 2,500 ppm maximum. The first bed hot spot will be allowed to increase at this rate to 427°C and then be maintained by adjusting 102-B firing. The temperature of the downstream beds will be held at 416°C by adjusting 102-B firing and using HIC-1046 until the first bed is fully reduced at 427°C. The 2nd bed will be raised to 427°C, while the 3A bed is held at 400°C to 416°C. Finally the 3B bed will be raised to 427°C. Observe the temperature (TG-1624 and TI-1366) at the inlet of the 103-J recycle section. This temperature should not be allowed to decrease below 25°C. The 105-J compressor interstage pressures are to be adjusted to control the temperature of the synthesis stream leaving 120-C to 146-D above 0ºC on TI-1080 by adjusting the speed With recycle operation and the ammonia catalyst reduction progressing, more synthesis gas will be converted to ammonia, producing more aqueous ammonia that will be recovered in 146-D. When the ammonia concentration reaches 1% exit the converter or 9% aqua solution in 147-D, the 105-J compressor must be adjusted (speed and recycle) to bring the machine to its normal suction pressure and temperature. Section 8 – Start-up Procedures

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As the temperature exit 105-D increases, the gas temperature exit 121-C tubes to 105-D will also increase by heat exchange. Adjust FIC-1020 to maintain about 170°C exit 121-C tube sides. As the 105-D exit temperature increases, more gas flow will need to be put through 123-Cs. Set FIC-1020 to maintain about 190°C inlet temperature to 121-C shells. BFW to 123-Cs must be adjusted so that steam generation does not start in 123-C1 until the 105D is stable. Keep a watch on the vapourisation calculation. Adjust FIC-1020 flow to remain within permissible vaporization regime. The discharge pressure of the 103-J compressor will be maintained by adjusting the speed using HIC-1006. The suction pressure of 103-J will automatically be maintained by PIC-1004 vent controller. As the level builds in 147-D, the aqua ammonia will be disposed of under level control LV-1012A to 120-CF1. Commission 124-Js, LV-1024 and FE-1061 and open the battery limit block valve to send the ammonia to storage. 8.1.44.

Phase 3: Heater Shutdown

As the reaction accelerates and more heat is generated, it will be necessary to cut the firing on the start-up heater. As this occurs, the pressure can be gradually increased at about 3.5 kg/cm2G per hour to improve the stability of the reaction. This increase should be taken in steps allowing time between each step to stabilize conditions. Observe the 102-B temperature / pressure limitations. As the temperatures have a tendency to increase during this transition period, the flow through HV-1044 can be increased as the heater firing is reduced. As this continues to happen, eventually the heater exit gas will be cooler than the gas that has flowed through the annular space and can act as a quench for the first bed. After the flow is stopped through the heater and the outlet line temperature is near the converter inlet temperature of 170°C, HIC-1025 can be used as quench for No.1 bed inlet and HV-1046 used to control beds 2 through 3B temperatures. It is desirable to reduce the heater over a period of 3 to 4 hours so that the temperature of the refractory is reduced to a point where flow through the heater can be stopped soon after the fires are extinguished. Prior to stopping the synthesis gas flow through the heater confirm that the burners are off and fuel gas is isolated. Section 8 – Start-up Procedures

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Over the next few hours of operation, the converter conditions should be moved toward normal design figures. The first converter bed inlet temperatures should be somewhere between 350°C to 370°C. The hot spot temperature of the 2nd bed should be quench controlled in the range of 400°C. Converter pressure should be allowed to seek its own level, i.e., the pressure developed with normal temperature conditions, recycle rate and a purge rate adequate to maintain the design level of inerts in the recycle gas, 5 mol%. Purge flow from the loop is initially started using HV-1019. HV-1019 allows for a large flow of purge gas to remove water and inerts from the synthesis gas. With new catalyst, even at design throughput, the expected pressure on the converter will be somewhat less than the 157 kg/cm2G design pressure. During the first days of operation with new catalyst, it is always desirable to keep the operating temperatures relatively low. Holding the temperature down for the first few days will limit production, but is expected to achieve optimum catalyst activation. The catalyst is fully reduced when the water content of the converter outlet becomes nil at any condition of operation. During this phase, the aqua ammonia concentration being level controlled into 147-D will gradually reach 95% ammonia. At this point, the liquid will be let down to the refrigeration system instead of being pumped to the ammonia storage tanks. Open the upstream and downstream block valves of LV-1012B to send the ammonia in 147-D to 120-CF4 through 149-D, set level controller LIC-1012 at normal level. As the ammonia production increases, the purge rate on HIC-1019 should be adjusted to maintain the inert gas content of the converter feed stream to about 3.50 mole% until FIC-1024 is placed in service. Feed flow to the converter should be increased at a rate proportional to the limit of available synthesis gas and steam to drive 103-JT and 105-JT. As recycle gas flow through the synthesis loop increases, additional heat exchange will develop in BFW preheater 123-Cs, resulting in additional steam production at 141-D. FIC-1020 can be adjusted to maintain the normal 105-D inlet temperature of 168°C.

Section 8 – Start-up Procedures

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NOTE At this point upsets of the 123-Cs will cause level swings in 141-D steam drum. FIC-1020 should not have big moves made to them. A low-low level LALL-1223 in the 141-D steam drum trips Primary Reformer feed, the air to the Secondary Reformer 103-D and burners to the Primary Reformer 101-B along with 103-J trip

As converter conditions stabilize, the 124-D High Pressure Ammonia Absorber and 125-D Ammonia Distillation Column should be put in service and ammonia venting at PV-1033B terminated. This procedure is described later in this section. Prior to commissioning 125-D, 113- J / JA will need to be commissioned. For this, open the suction, discharge and lock open the minimum flow lines for 113-J / JA pumps. Vent the pumps to the ammonia vent header to be sure they are liquid full. Align one pump for standby service. Start up a warm ammonia pump 113-J or JA, circulating through the recycle line back to 149-D. Line up to 125- D as required. 96. Trim Unit Conditions And Stabilize Ammonia Production The feed rate to the converter will be increased to bring plant production to 100% and close PIC1004 vent. 103-JT speed and load will have to be increased to flow more make-up gas to the synthesis loop. PIC-1006 can be placed in automatic when the system is stable. With the system in automatic, pressure controller PIC-1013 will manipulate the governor valves on 103-JT to maintain the MP steam header pressure. Route ammonia letdown from 147-D through normal letdown to refrigerant drums and then to storage. Adjust refrigeration and synthesis loop routings so that the optimum amount of ammonia is recovered from the recycle stream. 97. Cryogenic Purifier Bypass Operation Mode Even though such situations are expected to be rare in occurance, it is possible to operate Ammonia Plant at ~60-65% Ammonia production rate in case of a situation leading to requirement of bypassing the Purifier. Following guidelines are suggested to be followed, with PUSRI writing up detailed procedure to implement these guidelines: - Carefully reduce Process Air to Secondary Reformer 103-D towards a ratio required for conventional Ammonia Plant operation producing a H2/N2 ratio of 3:1 exit Methanator 106- D - Increase Primary Reformer firing making sure all the critical parameters like tube wall temperatures are within permissible limits of design of tubes and the Convection Section coils. Primary Reformer exit temperature can be increased to about 760-770 deg C. Section 8 – Start-up Procedures

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Depending upon steam availability increase steam to carbon ratio to 3.3 mol/mol. Reduction in Process Air Flow to 103-D will lead to drop in Steam generation from 101-C and the Steam System will need to be managed very carefully by adjusting MP Steam export in co-ordination with Urea Plant Maximise the HP Purge from Synthesis Loop in order to maintain H2/N2 ratio inlet 105-D as near to normal as possible. If the system requires, HIC-1019 and HP Ammonia Scrubber 124-D bypass can be used. The Purge Gas will need to be sent to NH3 Flare through PV1033B and flow to 130-C1/C2 will be stopped. Carefully monitor the reaction profile in 105-D making sure the reaction is sustaining and stable. Keep a watch on Synthesis Loop pressure.

It is expected that after adjustment of parameters as above, the plant can still produce upto 12001300 MTPD Ammonia. There might be situations in the plant when the Purifier Expander trips and there is no other reason to stop the Purifier. Under such situation, the Ammonia Plant and the Cryogenic Purifier can continue operating normally for a period of about an hour after a trip of the Purifier Expander, 131-JX; however, the liquid level in the bottom of the Purifier Rectifier Column, 137- D, will be lost if the Purifier Expander, 131-JX, is not restarted. During the period of time when the Purifier Expander, 131-JX, is not operating, AV-1029, is to be operated normally to maintain the hydrogen to nitrogen ratio in the Ammonia Synthesis Loop. Do not close AV-1029 to conserve liquid level in the bottom of the Purifier Rectifier, 137-D, as the separation of hydrogen and nitrogen will stop when AV-1029 is closed. The Synthesis Make-up Gas composition will change to the composition of the Purifier Feed Gas if the Purifier Expander, 131-JX is not restarted within the estimated one hour period. The reason for the trip of the Purifier Expander, 131-JX, must be resolved and the shut down trip input must be cleared. The Purifier Expander, 131-JX, can then be restarted. 98. Start The Purge Gas Recovery System / Ammonia Stripping System 8.1.45.

Place Ammonia Recovery In Service (2160MTPD Case)

Placing the purge recovery in service is the next step and will allow automatic control of the purge gas flows and recovery of the ammonia in the purge gas stream as well as allowing the recovered purge gas to be reintroduced into the process for recovery. It is assumed that the 124-D and 125-D with associated piping have been nitrogen purged to Section 8 – Start-up Procedures

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0.5% or less oxygen content. The following preparatory steps should be done prior to introduction of gas into the system: (some of these steps were previously done for ammonia cracking and starting refrigeration) • Open the isolation valves on PV-1033B and put the controller in automatic at 7.0 kg/cm2G. • Close the inlet and outlet valves and open the bypass valve to 124-D. • Place FIC-1024 in manual and fully close FV-1024, then open the isolation valves on FV-1024 and reset solenoid valve FY-1024 using DCS handswitch HS-1814. CAUTION Do not open the isolation valves or start a flow through FV-1024 without first opening the bypass valve around 124-D or the 124-D inlet and outlet valves and having PV-1033B in service and on automatic otherwise PRV124D will open due to higher than design pressure on line SG1120 • Slowly open FIC-1024 to start a flow of purge gas from the synthesis loop to PIC-1033B. Increase the flow as required to maintain the loop inert concentration. HIC-1019 can be closed when control is established using FIC-1024. • Slowly increase PIC-1033 to hold 40.0 kg/cm2G at 124-D. • Set PIC-1108 on automatic at 17.0 kg/cm2G on 147-D and open the isolation valves for PV1108, if not already done. When ammonia in the Purge Gas flowing through the 124-D, HP ammonia scrubber, bypass line reaches 2%, the Purge Gas recovery system should be put in service. Before initiating gas flow to the 124-D, HP ammonia scrubber, several preparation steps must be completed: • Establish Water Levels in 123-D, 124-D and 125-D by initially adding boiler feedwater in 125-D bottoms from 104-Js, then pump water to 124-D by using 161-Js. • Open the suction and discharge valves of the 161-J pumps. Vent the pumps until all air is out and the pumps are full of liquid 8.1.46.

Start Circulation

Before starting circulation of the system, the valves should be aligned as follows: • PIC-1034 On automatic, with a set point of 19.0 kg/cm2G. Close the downstream isolation valve and open the 2” vent valve to the NH3 flare system and the upstream isolation valve. • TIC-1414 Section 8 – Start-up Procedures

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In manual and closed with TV-1414 isolation valves open. FIC-1027 MP steam line MS1016-3” hot, FV-1027 closed with the isolation valves open and the controller on manual. 161-J / JA Ready for service. 124-D Ammonia Absorber inlet closed, blinds removed and overhead outlet bypass open. PV-1033A Fully isolated. PV-1033B Ready for Service FIC-1029 In manual with zero output and FV-1029 isolated PIC-1033 In automatic holding 40.0 kg/cm2G. LIC-1026 In manual with the output set to close LV-1026. LV-1026 Unblocked, closed, and bypass closed. FIC-1064 In manual with the output set to minimum pump stroke / flow 160-C LIC-1049 on automatic with the normal level as a setpoint. LV-1049 isolation valves open. 160-J / JA Ready for service. LIC-1028 In manual with the output set to minimum pump stroke / flow FIC-1039 in manual with zero output to close FV-1039

Slowly open the 124-D inlet gas valve bypasses on line SG1120-3” to pressure 124-D. Open the outlet valve and then the inlet valve fully followed by closing the inlet valve bypasses. Close the bypass line SG1029-3”. This will establish the flow through 124-D. Monitor the level closely in 124-D during this time. Start a 161-J pump and use FIC-1064 to start a low flow rate to the 124-D scrubber overhead by manually controlling the 161-J pump stroke. If required, make-up water will be added to 125-D by LIC-1027. Section 8 – Start-up Procedures

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Using LIC-1026 in manual, start a small return flow from 124-D bottom to the 125-D midsection through 161-C shell. As conditions permit, increase and stabilize the flow between 124-D and 125-D at 1221 kg/h. Using FIC-1027 in manual, start a small flow of MP steam to 160-C with the condensate initially going to the drain. Establish condensate flow through the LV-1049 on the 160-C shell outlet to the 101-U, deaerator, when the condensate quality is acceptable. Using FIC-1027, slowly increase the steam-flow, as needed, to build about 19.0 kg/cm2G in the 125-D. The 125-D pressure control valve PIC-1034 will be closed and set at 19.0 kg/cm2G. The valve will open automatically to vent to the NH3 flare system, as set up by the operator as the pressure increases. Place FIC-1027 in automatic as soon as the steam flow is stable. Sample the stripped water at the outlet of 125-D to be sure adequate stripping is occurring. Monitor the stripped water for ammonia concentration and adjust the stripping steam to the Ammoni Distillation Column, 125-D, as required. Adjust FIC-1027 to get an ammonia concentration of less than 1 ppm ammonia exit 161-C tubes. Once the system is stable, PIC-1034 can be directed to 127-C and the vent line closed. Put LIC-1026 in service on automatic as conditions permit on 124-D. Put FIC-1064 in automatic as soon as conditions permit to 124-D. Determine the ammonia content of the aqua ammonia solution of the 124-D bottom. Adjust the water flow rate as measured at FIC-1064, to obtain about 20 mol % ammonia strength in the 124D bottom. Start 113-J / JA as described earlier, if not already running, and start ammonia flow to the top section of 125-D using TIC-1414 for control. Adjust this flow to maintain 65°C on the overhead effluent, placing TIC-1414 on automatic as soon as the temperature is stable. Obtain an analysis of the 125-D overhead effluent gas. Adjust the ammonia flow from 113-J / JA, as required, to obtain 99.85% or higher ammonia in the vapor to 127-C. Open the PV-1034 downstream isolation valve and close the vents on the 125-D stripper overhead line, allowing the pressure to rise sufficiently to create a flow to the 127-C refrigeration condenser. Put PIC-1034 on automatic to control the 125-D pressure.

Section 8 – Start-up Procedures

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Once circulation is stable in 124-D, start circulation in 123-D. Slowly open the 123-D inlet gas valve on line NHV1040-2” to pressure 123-D. Open the outlet valve and then the inlet valve fully followed by closing the bypass line NHV1023-2”. This will establish the flow through 123-D. Monitor the level closely in 123-D during this time. Open FIC-1039 to a flow of 963 kg/h to 123-D. Start a 160-J pump and use LIC-1028 to control the level sending water to the 125-D distillation column overhead by manually controlling the 160-J pump stroke. If required, make-up water will be added to 125-D by LIC-1027. Place LIC-1028 in automatic at normal level as soon as stable circulation is attained. 99. Commission Purge Gas To The Process Or Fuel Gas System The Purge Gas from the ammonia recovery section in being vented from PIC-1033 to the NH3 flare vent. It can be put to the 130-Cs for recovery when the recovery system is stable. This can be done as soon as the ammonia concentration exit 124-D overhead is 200 ppm or less. Slowly open the upstream and downstream isolation valves of PV-1033A and place into service to 130Cs and at this point PV-1033B should go fully closed. A system for putting the purge gas to the fuel system has also been included for times when the purifier is out of service or 124-D exit ammonia is too high. FIC-1029 can be used to send purge gas to fuel, but this is normally used to reduce Argon or suspected Helium in the ammonia synthesis loop gas. It may not be a good idea to use purge gas with high concentrations of ammonia as fuel for the Primary Reformer the result will be increased NOx concentrations in 101B flue gas. Putting the purge gas to the fuel system is accomplished by opening the PV-1029 isolation valves and manually, SLOWLY opening FV-1029, located downstream of the PIC-1033 vent line tie-in. As purge gas goes into the fuel system, it will raise the pressure of the header and this may open PIC-1029 to vent excess gas to the vent. As FIC-1029 is opened to the 101-B fuel gas system, the 124-D overhead pressure will decrease and PV-1033B will start to close. The 123-D overhead gases can also be put to the fuel gas system. Slowly open the upstream and downstream isolation valves of PV-1038A and place into service to fuel gas header and at this point PV-1038B should go fully closed. This must be done very slowly to avoid upsetting the pressure of the fuel gas header and the temperatures of the reformer. High-high pressure in the header will trip the waste / purge gas to Section 8 – Start-up Procedures

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fuel system causing an upset in the reformer draft and loss of heat. Successful addition of waste / purge gas to the fuel gas system will increase heat in the reformer, require additional draft and require additional combustion air. 100. Secondary Burner Firing Prepare and purge the secondary fuel gas system as described in Section 7 of this manual. Start adding the secondary fuel to the already lit burners by slowly opening the valves to each burner, one by one, until all are in service following the same chart as used for lighting the arch burners. As the additional fuel is added to the burners, PIC-1029 will start to close. Closely monitor the radiant box draft and temperatures as the secondary fuel system will add both heat and a large volume of gas into the box. PIC-1855 may have to be adjusted to provide more combustion air. 101.

Startup After Emergency Shutdown

8.1.47.

Package Boiler Trip / Loss Of Import Steam

Under normal operating conditions, the ammonia plant exports medium pressure steam and there is no steam import and thus a trip of the package boiler will not have a direct and immediate effect. 8.1.48. • • • • • • • • •

Synthesis Gas Machine Trip

Synthesis Loop Trips and Isolates with HIC-1101 / HV-1033 Synthesis Loop Steam Generation Stops FIC-1020 Flow Ramps to 5MTon/h 105-J goes on Full Recycle or is Shutdown Purge Gas Ammonia Recovery Ceases Purge Gas to 130-Cs Recovery Ceases Process Gas Vents at PV-1004 Process Gas Vents at PV-1005 if 105-J is Shutdown Import Steam from the Offsite Package Boiler / OEP will be required WARNING The pressure in the hot loop should be lowered to 100 kg/cm2G before isolation. Lower the pressure in the cold loop to the pressure at HIC-1019 / FIC-1024. 105-D shell is not designed for the high temperatures that exist in the catalyst bed at higher pressures. Section 8 – Start-up Procedures

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The restart from this trip will be similar to start of the synthesis loop in a planned start-up. Steam availability may be tight and many steam driven pumps may need to be switched to motor driven spares to conserve steam. Following a short shutdown during which the converter magnetite catalyst temperatures remain above 370°C, it is usually possible to regain the synthesis reaction without using the start-up heater. Synthesis gas is introduced very slowly through the normal inlets. The circulation rate is held very low at first by keeping HIC-1033 mostly closed and is increased as rapidly as the reaction will allow without lowering the converter temperatures. High converter pressure will aid in regaining the synthesis reaction. When the converter temperatures begin to increase as a result of the heat of reaction, the feed inlet flow may be adjusted, as required, to develop a normal temperature profile through the converter. BFW flow through FIC-1020 will need to be increased to maintain normal converter temperatures. Additional synthesis gas flow should be added to the system as required, to develop normal operating pressure. The converter may then be adjusted to normal operating conditions at feed rates compatible with the synthesis gas supply. 8.1.49. 2

• • • • • • • • • •

105-J Refrigeration Machine Trip

Synthesis Loop Trips and Isolates on HIC-1101 / HV-1033 Closing Synthesis Loop Steam Generation Stops 103-J goes on Full Recycle or is Shutdown FIC-1020 goes to Minimum Value if 103-J Shutdown Purge Gas Ammonia Recovery Ceases Purge Gas Recovery to 130-Cs is Stopped and purge gas is vented Process Gas Vents at PV-1005 Waste Gas to Secondary Fuel Gas System Reduces Significantly Reformer Heat Release Reduced, Firing And Draft Changes Are Required,outlet temperatures increased Import Steam from the Offsite Package Boiler / OEP will be required

If 105-J is immediately restarted the ammonia plant should only be mildly upset. Steam availability will be tight even for a short duration outage. If the trip is longer than a few minutes, all process gas must be vented PV-1005 to avoid saturation of the molecular sieves since 130-C1/C2 chillers will be out of service. Section 8 – Start-up Procedures

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Synthesis Loop Inert Concentration / Composition Changes Significantly 103-J Compressor May Surge / Trip On Sudden Gas Composition Change Synthesis Loop Purge is Increased Significantly using HIC-1019 / FIC-1024 and 124-D bypass if required Purge Gas to Ammonia Recovery Increases Significantly Purge Gas Recovery to 130-Cs is Stopped and purge gas is vented Waste Gas to Secondary Fuel gas System Reduces Significantly Significant Process Air Adjustment Required (Reduction to Raise H2 / N2 Ratio) Reformer Heat Release Reduced, Firing and Draft Changes are Required, outlet temperatures increased Front End Rate Reduction may be Required HP Steam Generation is reduced when Process Air is Reduced

This will most likely be caused by a trip of the expander. Plugging of the purifier passes can also be a cause but that is usually not instantaneous although the end results will be the same when deriming has to be done. The synthesis loop can be operated with the Purifier bypassed but the purge rate will have to be significantly increased since methane is no longer being removed in the purifier. Significant front end rate adjustments will have to be made to the process air and primary reformer firing. Steam balance will require critical attention. 8.1.51.

2

• • • • • • • • • • • •

Methanator Trip

Synthesis Loop Trips and Isolates on HV-1101 / HV-1033 closing Synthesis Loop Steam Generation Stops 103-J Goes on Full Recycle FIC-1020 Flow goes to 5 MTon/h Purge Gas to Ammonia Recovery Ceases Purge Gas Recovery to 130-Cs Ceases Recycle Gas from 144-D is no more available Process Gas Vents at PV-1005 Waste / Purge Gas to Fuel is Tripped or Shutdown Purifier Expander is Shutdown and Purification Stops Reformer Heat Release Reduced, Firing and Draft Changes are Required OASE Circulation is Reduced or Stopped, (if Cause of the Methanator Trip) Section 8 – Start-up Procedures

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• Gas Vents at PV-1032 if OASE Circulation Stops • 104-D2 LTS Tripped if venting at PIC-1032 • Import Steam from the Package Boiler / OEP will be required Malfunction of either the CO shift reactors or the CO2 removal system will cause the 106-D, methanator, to trip out on high temperature or low solution flow rates and the process gas being vented at PV-1005. During this emergency, the OASE system continues to circulate at reduced rates, assuming the front end rates are reduced, and the process gas is bypassing the LTS (if CO shift problems were the cause) continuing through the 121-D, absorber, and on through the PIC-1005 vent. After the cause of the emergency has been corrected, the LTS converter will be returned to service venting at PIC-1005, upstream of the methanator. When the process gas exiting the 121-D, absorber, contains less than 1.0% carbon oxides as indicated on analyzers AI-1023 outlet 142-D2 and confirmed by lab analysis, the 106-D methanator can be returned to service. During this emergency, the 103-J and 105-J compressor trains may remain on line on total kickback, if steam is available though that’s an unlikely scenario. When the synthesis gas composition is near design at AI-1002 exit the 144-D, the 103-J and the molecular sieve dryers, 109-DA / DB, can be placed in service and synthesis gas started to the synthesis loop. Start 105-J on recycle if stopped. Start -up the Purifier and place into service. Hydrogen from 144-D to FV-1703 can be placed in service. CAUTION The pressure in the hot loop should be lowered to 10,000 kPag before isolation. Lower the pressure in the hot loop before closing HIC-1101. 105D shell is not designed for the high temperatures that exist in the catalyst bed at normal loop pressure. Following a short shutdown during which the converter magnetite catalyst temperatures remain above 370°C, it is usually possible to regain the synthesis reaction without using the start-up heater. Synthesis gas is introduced very slowly through the normal inlets. The circulation rate is Section 8 – Start-up Procedures

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held very low at first and is increased as rapidly as the reaction will allow without lowering the converter temperatures. High converter pressure will aid in regaining the synthesis reaction. When the ammonia converter temperatures begin to increase as a result of the heat of reaction, the feed inlet flow may be adjusted, as required, to develop a normal temperature profile through the converter. Additional synthesis gas flow should be added to the system as required, to develop normal operating pressure. The converter may then be adjusted to normal operating conditions at feed rates compatible with the synthesis gas supply. When the PIC-1004, venting at 103-J, is almost closed the front end feed gas rates can be returned to normal. As the synthesis loop is brought on line, the 103-J and 105-J will return to normal operation by automatic action of the various automatic controllers. Since the 124-D and 125-D ammonia recovery system remained on circulation, with steam discontinued to 160-C, during this brief emergency shutdown, restart of the purge gas absorption will require only restart of the purge gas flows to the absorption towers and restart of steam to the 160-C reboiler. When the concentration of ammonia in the purge gas from 124-D is below 200 ppm, the purge gas can be recycled to the Methanator effluent through PV-1033A 8.1.52.

OASE Solution Circulation Failure

If the circulation or level is lost, it is important to quickly get the process venting at PV-1032 and stop all forward flow through the LTS effluent exchanger train. Failure to do this quickly could lead to a severe fouling in the shell side of 105-C. • • • • • • • • • •

Synthesis Loop Trips and Isolates Synthesis Loop Steam Generation Stops FIC-1020 Flow goes to Minimum Value if 103-J Shutdown Purge Gas to Ammonia Recovery Ceases Purge Gas Recovery to 130-Cs Ceases Recycle Gas from 144-D is no more available Waste / Purge Gas to Fuel is Tripped or Shutdown Purifier Expander is Shutdown and Purification Stops Reformer Heat Release Reduced, Firing and Draft Changes are Required OASE Circulation is Reduced or Stopped

Section 8 – Start-up Procedures

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Methanator Trips Low Temperature Shift is Bypassed and Isolated Process Gas Vents at PV-1032 Import Steam from the Package Boiler / OEP Starts

Restart after resumption of OASE circulation can be undertaken when carbon oxides in the process gas stream has been lowered to below 1%-v as indicated on AI-1023.

Shift Converters The result of this emergency was: • • • • • • • • • • • • • • •

Synthesis Loop Trips and Isolates Synthesis Loop Steam Generation Stops FIC-1020 Flow goes to Minimum Value on 103-J Shutdown Purge Gas to Ammonia Recovery Ceases Purge Gas Recovery To 130-Cs Ceases Recycle Gas from 144-D is no more available Waste / Purge Gas to Fuel is Tripped or Shutdown Purifier Expander is Shutdown and Purification Stops Reformer Heat Release Reduced, Firing and Draft Changes are Required Process Gas Vents at PV-1005 Methanator Trips or is Shutdown OASE Circulation is Reduced or Stopped Low Temperature Shift is Bypassed and Isolated Process Gas Vents at PV-1032 Import Steam from the Package Boiler / OEP Starts

The front end of the plant rates should be reduced to around 85% with a higher than normal Steam to Carbon ratio, while the problem with the shift converter section is corrected. During this emergency, the OASE system continues to circulate at reduced rates, assuming the front end rates are reduced, and the process gas is bypassing the LTS continuing through the 121-D, absorber, and on through the PIC-1005 vent. After the cause of the emergency has been corrected, the LTS converter will be returned to service venting at PIC-1005, upstream of the methanator.

Section 8 – Start-up Procedures

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When the process gas exiting the 121-D, absorber, contains less than 1.0%-v carbon oxides as indicated on analyzers AI-1023 outlet 142-D2, the 106-D methanator can be returned to service. During this emergency, the 103-J and 105-J compressor trains may remain on line on total kickback, if steam is available, though it is an unlikely scenario. CAUTION The pressure in the hot loop should be lowered to 10,000 kPag before isolation. Lower the pressure in the hot loop before closing HIC-1101. 105D shell is not designed for the high temperatures that exist in the catalyst bed at normal loop pressure. When the synthesis gas composition is near design at AI-1002 exit the 144-D, the 103-J and the molecular sieve dryers, 109-DA / DB, can be placed in service and synthesis gas started to the synthesis loop. Start -up the Purifier and place into service. Hydrogen from 144-D can be placed in service and 175-J stopped. When the PIC-1004, venting at 103-J, is almost closed the front end feed gas rates can be returned to normal. As the synthesis loop is brought on line, the 103-J and 105-J will return to normal operation by automatic action of the various automatic controllers. Since the 124-D and 125-D ammonia recovery system remained on circulation, with steam discontinued to 160-C, during this brief emergency shutdown, restart of the Purge Gas absorption will require only restart of the Purge gas flows to the absorption tower and restart of steam to the 160-C reboiler. When the concentration of ammonia in the purge gas from 124-D is below 200 ppm, the purge gas can be recycled to the Methanator effluent through PV-1033A. 8.1.53. Loss of Process Air • • • • • • • •

Synthesis Loop Trips and Isolates Synthesis Loop Steam Generation Stops 103-J trips Recycle Gas from 144-D is no more available FIC-1020 Flow goes to Minimum Value Purge Gas to Ammonia Recovery Ceases Purge Gas Recovery to 130-Cs Ceases Waste / Purge Gas to Fuel is Tripped or Shutdown Section 8 – Start-up Procedures

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Purifier Expander is Shutdown And Purification Stops Reformer firing reduced to minimum, Firing and Draft Changes are Required Feed Gas to 101-B close on FV-1001 Process Gas Vents at PV-1005 Methanator Trips OASE Circulation is Reduced or Stopped Low Temperature Shift is Bypassed and Isolated Process Gas Vents at PV-1032 Process Air is Tripped Steam Flows to the 103-D Steam Generation from 101-C and 103-Cs is Reduced Significantly Switch to Motor Driven HP BFW Pump and also Lean and Semi Lean pumps depending upon power situation Import Steam From the Package Boiler / OEP Starts 101-J Air Compressor Train may be Tripped Primary Reformer goes to minimum firing Offsite Plant / Instrument Air must be Placed in Service, if 101-J is Tripped

Steam balance will need to be reviewed critically. To save steam, steam turbine driven pumps should be switched to motor driven spares. A normal startup will be undertaken from the point of restarting 101-J and process to 103-D, secondary reformer through HTS, LTS, OASE restart, 106-D, 109-Ds, Purifier, 103-J, 105-J, synthesis loop and on to the ammonia recovery as previously described. 8.1.54. • • • • • • • • • • •

Loss of Feed Gas

Synthesis Loop Trips and Isolates Synthesis Loop Steam Generation Stops Recycle Gas from 144-D is no more available FIC-1020 Flow goes to Minimum Value on 103-J Shutdown Purge Gas to Ammonia Recovery Ceases Purge Gas Recovery to 130-Cs Ceases Waste / Purge Gas to Fuel is Tripped or Shutdown Purifier Expander is Shutdown and Purification Stops Reformer Heat Release Reduced, Firing and Draft Changes are Required Process Vents at PV-1005 HV-1108 opens bto a preset value

Section 8 – Start-up Procedures

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Methanator Trips or is Shutdown OASE Circulation is Reduced or Stopped Low Temperature Shift is Bypassed and Isolated Process Gas Vents at PV-1032. Reduce system pressure Process Air is Tripped Steam Flows to the 103-D Steam Generation from 101-C and 103-Cs is Reduced Significantly Switch to Motor Driven HP BFW, Lean and Semi-Lean Pump Import Steam From The Package Boiler / OEP Starts 101-J Air Compressor Train Have Tripped Feed Gas Flow is Tripped Main Fuel Gas to be adjusted Offsite Plant / Instrument Air must be Placed in Service

The fuel gas is affected and reduced to minimum firing. The process steam at reduced rates, will continue through the reformers and HTS to PV-1032. Restart from this point forward will be as described under Normal Startup Procedure in this section. 8.1.55. • • • • • • • • • • • • • • • • • •

Loss of Process Steam

Synthesis Loop Trips and Isolates Synthesis Loop Steam Generation Stops Recycle Gas is not available from 144-D FIC-1020 Flow goes to Minimum Value on 103-J Shutdown Purge Gas to Ammonia Recovery Ceases Purge Gas Recovery to 130-Cs Ceases Waste / Purge Gas to Fuel is Tripped or Shutdown Purifier Expander is Shutdown and Purification Stops Reformer Heat Release Reduced, Firing and Draft Changes are Required Process Vents at PV-1005 Methanator Trips or is Shutdown OASE Circulation is Reduced or Stopped Low Temperature Shift is Bypassed and Isolated Process Gas Vents at PV-1032. Reduce system pressure to ~5 kg/cm2 or less Process Air is Tripped HV-1108 opens to a preset value Steam Flows to the 103-D Steam Generation from 101-C and 103-Cs is Reduced Significantly

Section 8 – Start-up Procedures

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Switch to Motor Driven HP BFW, Leam and Semi Lean Pumps Import Steam From The Package Boiler / OEP Starts 101-J Air Compressor Train May Have Tripped Feed Gas Flow is Tripped Main Fuel Gas is Tripped to Minimum Firing Offsite Plant / Instrument Air must be Placed in Service Steam Flow to 101-B is Reduced to Avoid Thermal Shock to the Tubes

The result of this emergency will be shutdown of the entire ammonia unit. Restart will be similar to Normal Startup. 8.1.56.

Loss of Boiler Feedwater

This emergency will result in an immediate and almost total shutdown of the ammonia plant equipment, if the loss of boiler feedwater causes low level trip from the 141-D, steam drum. • Synthesis Loop Trips and Isolates • Synthesis Loop Steam Generation Stops • Reccyle gas from 144-D is no more available • FIC-1020 Flow goes to Minimum Value on 103-J Shutdown • Purge Gas to Ammonia Recovery Ceases • Purge Gas Recovery to 130-Cs Ceases • Waste / Purge Gas to Fuel is Tripped or Shutdown • Purifier Expander is Shutdown and Purification Stops • Reformer Heat Release Reduced, Firing and Draft Changes are Required • Process Vents at PV-1005 • Methanator Trips or is Shutdown • OASE Circulation is Reduced or Stopped • Low Temperature Shift is Bypassed and Isolated • Process Gas Vents at PV-1032. Reduce system pressure to ~5 kg/cm2 or less • Steam Flows to the 103-D • Process Air is Tripped by Panel Operator • Steam Flows to the 103-D Air Line • Steam Generation from 101-C and 103-Cs is Reduced Significantly • Switch to Motor Driven HP BFW, Lean and Semi Lean Pumps • Import Steam From The Package Boiler / OEP Starts • Process Gas trips or is Tripped by Panel Operator • Main Fuel Gas is Tripped to Minimum Firing • 101-J Air Compressor Train may be Tripped

Section 8 – Start-up Procedures

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Offsite Plant / Instrument Air must be Placed in Service Main Fuel Gas is Tripped by Panel Operator Process Steam Flow is Reduced / Stopped by Panel Operator after the Reformer refractory heat poses no danger to catalyst tubes

If the steam drum level recovers quickly, the reformers and HTS catalysts temperatures remain above the saturation point of the system pressure and the primary reformer burners can be relit, steam from offsite can be imported for flowing through the 101-B venting at PV-1032 if level in 141-D is maintained. If the catalysts are too cool the normal startup will prevail. WARNING If the steam drum level does not recover, the flow of Process Steam must be stopped or dramatically reduced. The vent at PIC-1032 must be closed to prevent heat from being carried to the 101-C tubes causing severe overheating and possible failure. 8.1.57.

Loss of Power

This emergency will result in an immediate total shutdown of the ammonia plant and is nearly identical to the Boiler Feed Water failure. The concern here is controlled cooling of the Primary Reformer and the 141-D Steam Drum level control. All of the warnings for the steam drum level as shown in the previous failure scenario MUST be followed here as well. • • • • • • • • • • • • • • • •

Synthesis Loop Trips and Isolates Synthesis Loop Steam Generation Stops 103-J and 105-Js are Shutdown FIC-1020 Flow goes to Minimum Value on 103-J Shutdown Purge Gas to Ammonia Recovery Ceases Purge Gas Recovery to 130-Cs Ceases Waste / Purge Gas to Fuel is Tripped or Shutdown Purifier Expander is Shutdown and Purification Stops Reformer Heat Release Reduced, Firing and Draft Changes are Required Process Vents at PV-1005 Methanator is Shutdown OASE Circulation is Reduced or Stopped Low Temperature Shift is Bypassed and Isolated Process Gas Vents at PV-1032. Reduce system pressure to ~5 kg/cm2 or less Process Air is Tripped Steam Flows to the 103-D Air Line Section 8 – Start-up Procedures

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Steam Generation from 101-C and 103-Cs is Reduced Significantly Switch to Motor Driven HP BFW, Lean and Semi Lean Pumps Import Steam From The Package Boiler / OEP Starts Process Gas is Tripped Main Fuel Gas is Tripped to Minimum Firing Offsite Plant / Instrument Air must be Placed in Service Process Steam is Stopped

A small flow of process steam should be continued to slowly cool the tubes as long as steam is available and 141-D level is adequate. 102. Normal Start-Up Of The Ammonia Plant The normal start-up of the ammonia plant will follow the previously described start-up steps but with the following changes / additions: • No air blowing or dusting should be done unless ALL front end catalyst has been replaced with new, oxidized charges. • No HP BFW or HP steam system chemical cleaning needs to be done unless a large section of piping or coils were replaced with new materials. Chemical cleaning may then best be done BEFORE the new pieces are installed rather than clean the entire system. • The heat up rates for the 108-Ds, 101-B, 103-D, and 104-Ds can be at 50°C /h instead of 20°C / hr. • 101-B, 103-D and 102-B refractory dry out steps can be skipped if no major refractory repairs were done during a shutdown preceding the start-up. • 101-B, 103-D, and 104-D1 desulfurization steps can be skipped if the catalyst has not been changed. Keeping the 103-Cs below the steam generation temperature until stable operation is attained should still be done. • The emphasis during normal start-up is to maximize steam production before attaining maximum steam superheat. Therefore, TIC-1004 should be set to control the valve at minimum opening while maintaining at least 20°C of superheat exiting 102-C. This will also mean adjustments to TIC-1010 and TIC-1004 to maintain the HTS inlet temperature while maximizing steam production. • Another emphasis during start-up is to minimize steam usage as much as possible until steam generation is adequate for the process. To accomplish this, the motor driven pumps should be placed in service first with the steam driven pumps warmed and ready for standby operation until steam supplies are plentiful. • 104-D2A/B reduction steps can be skipped if the catalyst has not been changed. • Operator pressure testing steps can be skipped if major repairs in which vessels and lines were opened / removed have not taken place. • OASE chemical cleaning / degreasing steps do not have to be done unless there has been a complete change of internals, packing, piping, etc. Chemical cleaning may then best be done BEFORE the new pieces are installed rather than as an entire system. Section 8 – Start-up Procedures

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HP steam relief valve testing steps can be skipped if the valves were not removed / opened / adjusted during a shutdown 106-D catalyst does not have to be reduced unless a new catalyst charge has been installed, THE WARNING CONCERNING NICKEL CARBONYL MUST BE ADHERED TO IN EVERY START-UP. The heat-up rate can be done at 50°C / hour after 205°C is attained. If the 106-D inlet temperatures or reaction temperatures can not be attained, most likely due to new LTS catalyst being installed, it may be necessary to slowly open in a step-by-step manner the HIC-1021 valve and bypass a small amount of process gas around the LTS. The 109-Ds do not have to be regenerated twice before going forward unless they have been opened to the atmosphere or new desiccant installed The purifier does not need to be dried out or derimed unless there are signs of high exchanger differential pressures or flow restrictions. Always pressure the purifier in a reverse flow direction. The high pressure operator leak test does not have to be performed unless there were significant openings of equipment or piping during a turnaround that would make performing the test the prudent and safe thing to consider. 105-D catalyst does not have to be reduced unless a new catalyst charge has been installed and the heat–up rate can be done at 50°C / hr. Keeping the 123-Cs vapourisation below recommended limits is important

It will not be necessary to nitrogen purge and refill the ammonia refrigeration system unless the system was drained and then opened to the atmosphere for repairs and / or inspections. The system can be shutdown and remain with ammonia inventory if no work is to be done in the system.

Section 8 – Start-up Procedures

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9. Shutdown Procedures 103.

Normal Shutdown Procedure

9.1.1.

Introduction

The procedures presented here apply to pre-determined situations where the element of urgency is not a factor, for example, a scheduled unit shutdown for turnaround. Other types of shutdowns, whether partial or complete, due to utility or equipment emergencies present their own particular problems. In most cases, portions of the normal shutdown procedure will apply, but the particular situation will determine the shutdown course to follow. Where and when possible in any circumstances, the equipment should be shutdown expeditiously, but safely, to avoid personnel injury and equipment damage. For convenience of presentation, the shutdown is described by unit sections, but it must be recognized that the sectional shutdowns will overlap. Therefore, some items must be performed simultaneously. Most instrumentation, if properly tuned, will remain stable in the automatic position during the course of a shutdown, but it may be necessary to place some instruments in the manual position, compressor speed controllers, steam generation controllers, ratio controllers, etc. Experience gained during shutdowns will determine the preference. Prior to and during any scheduled shutdown, or, if time permits during the emergency, the offsite areas servicing or being serviced by, or providing service to, the ammonia unit should be notified so that they can be prepared to supply the ammonia unit with steam, instrument air, large quantities of nitrogen, demineralized water, etc. If the planned or scheduled shutdown requires oxidation of catalyst so that it may be salvaged and reused the catalyst manufacturer should be contacted ahead of time so that current procedures for oxidation may be developed. 9.1.2.

Reducing Unit Throughput CAUTION When reducing unit throughput, the process air rate is always decreased first, followed by the decrease in process gas, and lastly by the decrease in process steam flow.

Plant gas feed rates are reduced stepwise to a minimum rate that is compatible with overall stable unit operation. The minimum rate for complete operation, including a stable synthesis Section 9 – Shutdown Procedures

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loop, is expected to be about 60 percent of design flow. As feed gas is reduced, the primary reformer tube outlet temperatures should be maintained at their normal values by reducing burner firing by gradually reducing the set point on the fuel gas pressure controller, PIC-1002. Process air will be reduced prior and proportionally to the feed gas, but the hydrogen to nitrogen ratio analyzed at 144-D and in the synthesis loop circulating stream, is the determining factor. This will be automatically done at the purifier 137-L if the ratio control system, AIC-1029, is in automatic but must be watched closely as feed rates are reduced. At air flows greater than 40 percent of design, the steam to the secondary reformer air line should remain at normal design flow. If the temperature of the air preheat coils becomes too hot, BFW may be injected through SP-DH-211, controlled by TIC-1044 or additional steam can be added through FV-1044. This must be done in a controlled manner to avoid upsetting the process by reducing the air to the secondary reformer. Excess oxygen content of the reformer flue gases should be maintained at ~ 2% (wet basis) exit the radiant section. Excessive oxygen / air in the flue gas will lead to overheating of the convection section coils while the opposite will lead to incomplete combustion at the burners, after-burning in the convection section and substantial temperature upsets. The operators must carefully monitor the PIC-1855 combustion air and PIC-1019 radiant box pressures along with AI-1010A/B (arch burners), AI-1021 A/B (tunnel burners) and AI-1033A/B (superheat burners). As feed gas is reduced, the 101-D and 108-DA/DB, Hydrotreater and Desulfurizers, should be maintained at normal temperatures. The hydrogen flow rate to the Hydrotreater should be reduced proportionally to the feed gas to maintain the 2% hydrogen content. Line up supplemental hydrogen for use and start 175-J just prior to the 103-J shutdown. Hydrogen is maintained at 2% to convert the organic sulfur to hydrogen sulfide. The process steam rate should not be reduced proportionally to the Natural Gas feed rate once the feed rates are below 60% of design throughput. Generally, it is desirable to operate at a higher than normal steam to gas ratio when at reduced throughput. Therefore, a minimum of 4 to1 steam to gas weight ratio should be maintained when operating below 60% of design Natural Gas feed rates. The inlet temperatures to the high temperature shift, low temperature shift, Methanator, and ammonia converter should be maintained at their normal values to maintain normal outlet gas compositions. OASE system circulation rates should also not be reduced in proportion to unit feed rates, but maintained as high as heat availability permits. This will ensure adequate contact of gas with Section 9 – Shutdown Procedures

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solution for good absorption. As the system circulation rate is reduced below 90%, the hydraulic turbine driven semi-lean OASE solution pump should be taken off the line, substituting the standby pump. All process temperature controllers must be monitored and throttling valves adjusted so that they remain on control. The synthesis gas compressor, at reduced speed, will require a small amount of recirculation by the anti-surge valves through the case with about 75% of normal make up gas. The anti-surge controllers should automatically control this flow as required. The synthesis loop purge gas rate should be decreased. The amount of decrease is determined by the inert gas content as indicated on the gas mass spectrometer analyzer and can be reduced by the same percentage as the recycle stream flow as a starting point. Since the ammonia refrigeration system is basically a closed system, compressor duty will decrease, but power requirements will remain relatively the same beginning around 75% because the anti-surge valves will open automatically to maintain compressor stability. Since the main refrigeration compressor turbine is a backpressure turbine, close monitoring of the medium pressure steam system will be required. With reduction of front end feed rates, steam production from process equipment will decrease, but steam requirements will not decrease proportionally. The package boiler firing and steam import will be increased to make up the loss of production due to the reduction of feed gas rates. Arrangements must be made with the operators for increasing MP steam import from the package boiler. Switching pump and fan drivers to motor driven spares may also become necessary to preserve steam but this must be done very carefully to avoid trips and upsets. Adjustments to and the isolation of individual reformer burners purge gas supplies will be required as convection coil duties are reduced to avoid overheating the coils. 104. 9.1.3.

Plant Shutdown Normal Shutdown

The following procedure should be followed if the plant is to be shutdown after a period of normal running. 9.1.4.

Purge Gas Ammonia Recovery System Shutdown

Prior to shutdown of the purge gas recovery unit, any purge to the fuel gas system from FIC-1029 should be taken out of service and purge gas vented to the atmosphere through PVSection 9 – Shutdown Procedures

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1033B/1038B. FIC-1029 setpoint should be set to ‘0’ or the controller placed in manual and closed if open. Normally, purge gas will be flowing through PV-1033A to 130-Cs inlet. If the plant shutdown is to include the purifier, now may be a good time to remove all secondary fuel gas firing by closing off the purge gas to the individual burners while controlling the reformer radiant box and gas exit temperatures. Secondary Fuel gas will vent at PIC-1029. Activate HS1225A/1225 manual shutdown for the Purge gas to the Arch Burners, this will close isolation valves XV-1222A/B and open the vent valve XV-1222-C. FIC-1024 setpoint should be slowly reduced to ‘0’ flow. Continue to vent purge gas from 147-D and 149-D through PV-1038B. Once the loop purges from FIC-1024, the refrigeration machine, and the synthesis loop are stopped, the ammonia recovery system can be shutdown. Continue normal circulation of the system until all of the ammonia has been scrubbed and returned to the refrigeration system. This can be determined by lab analysis. Reduce and stop the steam flow to 160-C by reducing and closing FIC-1027 to cool 125-D and the circulating water. The reflux ammonia flow will reduce as the temperature on TIC-1414 cools. Place TIC-1414 in manual and closed then stop the 113-J ammonia pumps. The pressure on PIC-1034 will also reduce as the steam is reduced to the 160-C and ammonia flashing is completed. Isolate the line to 127-C and open the line to the ammonia vent system if required. Once the water has cooled, circulation can be stopped by shutting down the 161-J pumps. Levels can be maintained in the vessels, if desired, unless the system or individual vessels need to be drained or transferred for maintenance purposes. 9.1.5.

Synthesis Section Shutdown

Reduce Synthesis Section Feed As the purge gas to 130-Cs and the feed gas rates are reduced in the reforming section, synthesis loop fresh feed rate will be reduced automatically by the action of the synthesis gas compressor suction pressure controller slowing down the compressor. The rate of reduction in the Natural Gas feed rates must be controlled so that the synthesis section suffers no large temperature and / or pressure fluctuations. When fresh synthesis gas rate reduction begins, there will be less heat of reaction in the synthesis converter and adjustment of the converter and bed inlet temperatures will be required Section 9 – Shutdown Procedures

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to maintain normal temperature profiles using HIC-1025 and HIC-1046. The total recycle rate will decrease as the compressor speed is reduced and the converter bypass flow, FIC-1059, may need to be adjusted (opened) on manual to ensure the rate of temperature decrease in 105-D is not too rapid, i.e. >50°C / hr, while protecting the 103-J recycle case from surge. While reducing the feed rates, adjustments will be required at the synthesis gas compressor. With a reduction in feed, the suction pressure of the compressor will tend to drop. The suction pressure controller PIC-1006 will compensate by decreasing the compressor speed. If the front end feed gas rate is 80%, the PIC-1006 and PIC-1004 pressures should be slowly reduced to about 80% to maintain the process gas velocities through the equipment. As 103-JT speed is reduced the steam generation from back end of the plant is also reduced and the refrigeration load is reduced, the MP steam extraction from 103-JT and 105-JT may not be enough. As MP export steam decreases, the offsites package boiler should begin to increase steam production to satisfy offsite steam demands. At some point in the shutdown, import steam will be required to maintain the steam requirements. BFW preheat in the 123-Cs will decrease rapidly as synthesis loop circulation is stopped. HP steam production will decline rapidly. When loss of boiling in the 123-Cs occurs, there may be a sudden but short surge of BFW due to the collapsing of steam in the piping until the piping refills with water again. There may also be a sudden drop of the level in 141-D due to the collapse of steam bubbles in the system. Process Gas flow around 123-C2 on HIC-1032 and FIC-1020 BFW flow should be reduced to maintain 105-D inlet temperatures and keep LIC-1001B in control and to avoid sudden cooling in the 123-Cs. TIC-1415 must remain in automatic to avoid over-boiling in 123-C1 during these transients. Careful attention must be paid to both FV-1072 and TIC-1011 valves at this time to avoid sudden cooling of the LTS and potential uncontrolled shutdown of the Methanator and downstream plant sections. TV-1011 valve should be controlled so as not to close to less than 20% open. FV-1020 can be isolated if adequate level control using LIC-1001B and good control on TIC-1011 can be achieved otherwise some flow through FIC-1020 may have to be maintained to keep the other valves in controlling ranges. PIC-1009, through SIC-1005, will control the 105-JT speed as the load of the refrigeration system requires. As the 105-JT speed is reduced, the MP extraction flow will also be reduced and letdown from the HP steam system through PV-1018 may commence. Verify that the anti-surge valves on 105-J, FIC-1009, FIC-1010, FIC-1011, and FIC-1012 are Section 9 – Shutdown Procedures

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opening as required to keep the refrigeration compressor out of surge. Confirm that the anti-surge flow controllers FIC-1007, FIC-1008, and FIC-1059 are open enough to keep the 103-J compressor out of surge at the reduced speed. Ultimately, the compressor will reach minimum governor speed and the discharge and loop pressure will decline as the recirculation gas stream is reduced. Continued reduction of flow, pressure, and temperature in the synthesis converter will ultimately lead to loss of reaction. When this occurs, the temperature profile of the converter will turn rapidly downward. Continue recycle operation until the bed exit temperatures are the same range as the 105-D shell. Circulation through the converter should then be reduced quickly and terminated unless it is desired to cool down the ammonia converter. Isolate 103-J compressor from the synthesis loop by closing HIC-1033 and HIC-1101, with anti-surge valve FIC-1059 open on automatic, or fully open on manual, and FIC-1007 and FIC-1008 open on automatic to prevent surge of 103-J compressor. This action places the synthesis gas compressor on total recirculation and stopping the flow through the 105-D converter will slow down the rate of temperature decrease. The converter may be cooled further by continuing circulation of synthesis gas, if desired. Usually for long shutdowns the converter is cooled to 250°C average temperature then maintained under synthesis gas pressure. For very brief shutdowns, every effort is usually made to conserve heat in order to expedite the restart. In this instance, the recycle gas circulation is discontinued as soon as possible to conserve the heat. Purge gas flow on FIC-1024 and vent HIC-1019, if open, should be discontinued when 103-J is isolated from the loop, unless the loop is to be depressured for maintenance reasons, if not already stopped as indicated before. Synthesis loop pressure can be maintained, but will decrease some as the converter temperatures decrease. CAUTION If the converter shutdown extends over a long period, and shell metal temperatures decrease to –6°C, the converter must be depressured to 700 kPag or lower.

Transfer the remaining liquid ammonia from 146-D to 147-D and 147-D to 149-D or 120-CF1 for pumping to storage using pumps 124-J/JA. Empty 149-D to 120-CF4. Close the isolation valves for level controllers LIC-1013, LIC-1012, LV-1016 and LIC-1021.

Section 9 – Shutdown Procedures

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CAUTION Care must be used when emptying 146-D to 147-D to avoid blowing high pressure gas through and lifting PRV-147D1/D2. Isolate ammonia flow from 147-D, through HV-1026, to the 149-D flash gas ammonia recovery column. 9.1.6.

Synthesis Gas Compressor Shutdown

The speed of the 103-J compressor should be reduced to minimum governor with PIC-1006. FIC-1007, FIC-1008 and FIC-1059 will be open on automatic control before the machine is shutdown. The machine can be stopped or tripped by actuating switch HS-3211B. When this switch is used, HP steam letdown valve HIC-1028 causes HV-1028 to open flowing HP steam to the MP steam header at a preset position. Therefore, the MP steam system pressure must be observed. HIC-1028 can then be slowly closed manually allowing PIC-1018 control valves to regulate the MP system pressure. When a compressor is shutdown, the machine manufacturer’s instructions and procedures should be followed. These include oil circulation for an extended period, slow rolling the machine, maintaining / switching seal gas sources, putting the machine on a turning gear, and other precautions. These detailed procedures are contained in the Installation, Maintenance, and Operation Instruction Manual prepared by the vendor. After shutting down the machine, the compressor suction line should be closed on 103-J. The machine can then be depressured and purged free of synthesis gas with nitrogen. In addition, the isolation valves in the HP steam inlet line and MP extraction line should be closed. Process will automatically vent at PIC-1004 as 103-J is stopped maintaining the backpressure.

9.1.7.

Depressure and Nitrogen Purge the Synthesis Converter

If it is desired to clear the synthesis converter of synthesis gas for maintenance requirements, the following procedure is recommended: • Continue recycle of gas circulation until the converter has cooled to less than 65°C. This can only be accomplished by closing FIC-1020 BFW to 123-C2, paying careful attention to the FV1072 and TIC-1011 controls, so that large quantities of heat will not be transferred from the boiler feedwater to the converter via the circulating gas. • Isolate the hot loop by closing HV-1101 and HV-1033. • Isolate the manual locked open recycle isolation valve the slowly depressure the synthesis loop and converter to about 0.35 to 0.7 kg/cm2(g) after shutting down the 103-J compressor.

Section 9 – Shutdown Procedures

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Isolate the system for nitrogen purge in the same manner employed in the start-up procedure. The usual purging method is to depressure the section to approximately 0.35 kg/cm2(g) and pressure to 3.5 kg/cm2(g) with nitrogen. Repeat as necessary, to remove combustible material to the level dictated by safety regulations. Usually, three pressure purges are enough to accomplish this. At the completion of the nitrogen purge, maintain a positive nitrogen atmosphere on the system.

Normally, maintenance work required on the converter can be accomplished by maintaining a sufficient flow of nitrogen over the catalyst to ensure exclusion of air. The catalyst must be removed if major work on the converter is anticipated. 9.1.8.

Ammonia Refrigeration System Shutdown

As synthesis loop circulation is stopped, the duty of the ammonia refrigeration system decreases. The compressor will slow down to minimum governor speed by the action of PIC1009 through SIC-1005. Anti-surge valves FIC-1009, FIC-1010, FIC-1011, and FIC-1012 will open. At this point the compressor discharge temperature must be monitored. The 105-J will remain in service to maintain differential pressure in the flash drums, so that most of the ammonia can be removed, if desired. During the time 105-J are still in service, maintain enough ammonia in 120-CFs to provide direct contact recycle cooling and to supply ammonia to the 130-Cs chiller which is still in service upstream of the molecular sieve driers. Levels can be lowered to avoid having to pump out the ammonia after the shutdown, if desired. As soon as 105-J are shutdown, pump out the remaining ammonia in the flash drums through the respective pump out lines. In pumping out 120-CFs, the pump should be continuously monitored locally and run until it loses suction and then stopped. If the shutdown is of short duration, liquid can be stored in 149-D and 120-CF drums. If a long shutdown is anticipated, 149-D liquid level should be reduced to as low a level as possible by letting down to 120-CF4 before 105-J is stopped. Ammonia from letdown drum 147-D will be level controlled to the 120-CF1 and pumped out by 124-J/JA to storage. After the compressor is shutdown and liquid removed, the system can be depressured by venting then nitrogen purged, if necessary. If the shutdown duration is of short term, the system may remain under the ammonia vapor atmosphere. If vessel entry is required, the system should be purged with dry air after it has been nitrogen purged.

Section 9 – Shutdown Procedures

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105-J Ammonia Compressor Shutdown

The speed of the 105-J compressor should be reduced to minimum governor with PIC-1009 (through SIC-1005). FIC-1009, FIC-1010, FIC-1011 and FIC-1012 should be verified open before the machine is shutdown. The machine can be stopped or tripped by activating switch HS3111B. This will also activate XS-1128 HP to MP steam letdown through HIC-1028 to a preset position. Careful attention must be paid to the steam systems during this operation to avoid an upset to the MP steam system that could lead to an uncontrolled front end shutdown on low steam to carbon ratio. When a compressor is shutdown, the manufacturer’s procedures should be followed. These include oil circulation for an extended period, slow rolling the machine, putting the machine on a turning gear, switching to a higher pressure seal gas supply system and other precautions. These procedures are usually contained in the Installation, Maintenance, and Operation Instruction Manual prepared by the vendor. 9.1.10.

Purifier Shutdown

Steam demand and generation will determine the front end plant rates. Once 103-JT and 105-JT are shutdown, the steam generation will drop but so will the demand. Front end rates can be reduced if import steam is not too high. Lower the system backpressure to mach the front end rates percentage of normal. If the front end rate is 75% of design the backpressure at the current vent should be 75% of normal as well to maintain plant system velocities. Slowly isolate all secondary fuel gas to the primary reformer burners and vent the purge gas at PIC-1029, if this has not already been done, while monitoring and controlling the reformer outlet and radiant box temperatures. Activate HS-1225 manual shutdown for the purge gas to the arch burners, this will close isolation valves XV-1222A/B and open the vent valve XV-1222C. This action may be done during the shut down of the ammonia recovery system. Activate the Purifier Expander manual shutdown switch, HS-1213B. This will: Close the expander inlet (XV-6100) and outlet valves (HV-1302) and disengage power from the generator. Observe the expander speed to determine that rotation has stopped. WARNING Do not disengage switch gear manually.

Section 9 – Shutdown Procedures

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NOTE It may be preferable to leave 131-JX nozzles open when shut down. Slight leakage from the shut down valves has fewer tendencies to cause the expander to rotate when the nozzles are open. If the temperature is to be kept low for a short term shutdown then stop the flow through the purifier by switching the gas to the PIC-1084 vent by lowering the setpoint on PIC-1084 to just below PIC-1004 setpoint and the valves will switch with PIC-1084 opening and PIC-1004 closing. The purifier inlet and outlet isolation valves can then be closed to maintain the cold box temperatures for as long as possible. Forward gas flow to PIC-1004 can be continued, if desired, by opening the process gas bypass line around the purifier (MOV-1052) then isolating the purifier inlet (MOV-1051) and outlet (MOV1053) isolation valves. PIC-1029 will nearly completely close as soon as the reject gas flow from the purifier stops and only the reject gas flow from 163-D will be venting at this point. Synthesis gas will have to be switched to and used if molecular sieves regeneration is to continue. 9.1.11.

Methanator Shutdown

Time permitting, switch the vent to PIC-1005 and close PIC-1084 by placing PIC-1084 on manual and slowly closing the valve and PIC-1005 will open as the system pressure increases, then trip 106-D. Actuate HS-1253. This will automatically close XV-1211 and MOV-1011 valves at the inlet to 114-C tubes. As MOV-1011 and XV-1211 close, PIC-1005 will open to maintain the unit pressure and PIC-1084 will close. HS-1253 also closes MOV-1017 and MOV-1018 inlet to the 109-Ds and stops the regeneration sequence timer. The medium pressure steam supply to 183-C can now be isolated. To avoid temperature and pressure cycling of 183-C, if the shutdown is for a short duration, maintain the MP steam supply to 183-C. The Methanator may remain under raw synthesis gas pressure if the shutdown is for a short duration. If the vessel temperatures decrease below the 200°C and carbon monoxide is present in the gas in the Methanator, or if the shutdown is of long duration, the catalyst should be purged free of CO to reduce the likelihood of hazardous nickel carbonyl formation. The vessel can be depressured through the vent line at 106-D inlet. The 106-D, 144-D and the equipment and piping in between should then be pressure purged with nitrogen and maintained under positive nitrogen pressure.

Section 9 – Shutdown Procedures

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Isolate the HP steam valves to TV-1012B. Once PIC-1084 is closed and all of the gas is venting at PIC-1005, no more condensate will condense and be collected in 144-D. LIC-1008 will close and 122-J will go on minimum flow recycle. It should be shutdown using the local HOA switch and isolated. 130-Cs will no longer have gas flow to chill and LIC-1009 and LIC-1118 should go closed as the level increases in the shells. Isolate the level control valves. 130-Cs level can be sent to 120CF1 and pumped to storage, if desired.

9.1.12.

Low Temperature Shift Converter Shutdown

During a normal shutdown, the Methanator is always removed from service before the LTS converters are shutdown. Activate HS-1004. The action of this switch will open the LTS bypass valve, MOV-1009, before closing the LTS 104-D2A inlet valve, MOV-1008 and LTS 104-D2B outlet valve MOV-1007. Effluent gas will continue to flow through the 121-D absorber to vent through PIC-1005. HIC-1021 bypass should also be closed and isolated at this time. Confirm that the bypass valves are closed around MOV-1007 and MOV-1008. For a shutdown of short duration, a few hours, the vessels can remain hot and pressured. If the shutdown is long term, the vessels should be depressured and nitrogen purged to displace the process gas atmosphere to avoid condensation of the steam which can damage the catalyst. Then they are maintained under positive nitrogen pressure. 9.1.13.

OASE System Shutdown

It is assumed at this point that CO2 is venting at PIC-1104. Gradually open PIC-1040, in automatic or manual, located at 142-D1 exit to vent header. Maintain the system pressure at 21 kg/cm2(g) on PG-1692. As PIC-1040 is opened, PIC-1005 will close but may not fully close. PIC-1032 exit the HTS may need to be opened some to fully close PIC-1005. PIC-1005 can be placed on manual and slowly closed with PIC-1032 in automatic to switch the vents. PIC-1032 may be used initially instead of PIC-1040, if desired and if heat to 105-C is not required for OASE solution regeneration. After PIC-1005 is closed, MOV-1005 and bypass to 121-D can be closed or left open to provide pressure for the solution circulation until solution regeneration is completed. Section 9 – Shutdown Procedures

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Close FIC-1018 wash water flow from the 110-Js and isolate the valve. FIC-1030 wash flow to 163-D can be reduced and stopped once the flash gas has stopped. This is indicated by the closing of PIC-1039. Continue solution circulation until analysis indicates the rich solution has been stripped of CO2. By venting at PIC-1040, reboiler heat from 105-C continues to be supplied by the HTS effluent stream. If the process gas pressure falls and additional pressure for circulation is required, the NG pressuring line, NG2515 can be opened once the pressure approaches 12 kg/cm2(g). During the solution regeneration phase, the seal flush source for the 117-J, 107-J and 108-J solution pumps and the hydraulic turbine should be OASE to prevent potential solution dilution. When the circulating solution has been stripped for about 4 hours and shows to be CO2 free, change the process gas venting point from PIC-1040 at 142-D1 to the vent PIC-1032 at the 103C2 outlet. PIC-1032 will automatically open while closing the 142-D1 vent, PIC-1040, controlling the front end backpressure. Maintain the backpressure while switching vents by lowering PIC1032 setpoint to match the current pressure before starting to switch, if required. MOV-1005 and its bypass inlet to 121-D should be closed, if they are still open. WARNING Throughout the circulation for regeneration as mentioned here, it is extremely important that nitrogen purges be opened up to 122-D2 as OASE solution will pick up and release synthesis gases from 121-D and significant concentrations of hydrogen can collect in 122-D1 and downstream piping and equipment. If this hydrogen is mixed with air and finds an ignition source, an explosion can result. Begin a nitrogen purge immediately after the process gas forward flow through 121-D has stopped. The wash water circulation pump 110-J / JA should be kept on recycle to maintain a seal flush backup. There must be no make-up water flowing through FIC-1013 or else solution dilution will occur. Place 107-JC semi-lean pump in service, if not already in service, and shut down the hydraulic turbine. This will have to be done at about 90% circulation rate to avoid a low flow through 107JA. Reduce FIC-1014 flow to about 145,000 kg/h, FIC-1017 will have to be lowered a proportional value to compensate for this flow change and this will be done automatically by LIC-1042 if FIC1017 is in remote setpoint mode. Section 9 – Shutdown Procedures

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Reduce FIC-1005 flow to the capacity of one 107-J, about 1275,000 kg/h and stop 107-JB. Watch the levels in the 122-D1 / D2 stripper towers and 163-D HP flash column while reducing and stopping the solution circulation pumps to avoid losing levels in either the semi-lean or lean solution sections. Shutdown and isolate the remaining 107-J. FIC-1005 can be placed in manual and closed to the minimum stop, if desired, as the 107-Js are being shutdown to better control the system levels. Shutdown the 108-J pump followed by the 117-J pump at nearly the same time and isolate. Depending on the duration of the shutdown, and whether or not maintenance work is contemplated, the inventory may be left in the system. In the event the system is to be emptied, the OASE solution will be pressure transferred from absorber 121-D to 163-D, then moved to 122-D1, pumped in to 122-D2 using 117-J pump, and finally pumped to 114-F for storage using the 108-J pumps. It is also possible to store the solution in one of the towers, stripper or absorber, so that work can be done in the other tower. 110-J / JA can be shutdown and isolated as soon as water is no longer required for FIC-1018 and as back-up for the OASE pump seal flushing supply. Isolate FV-1013 when it is no longer required. 153-D can be drained to the sump through the 110-Js suction line drain if required. The 114-F storage tank is designed to hold all of the solution at its maximum liquid level. Therefore, if the entire inventory is to be transferred to 114-F, 114-F must start at a low level. It must always be determined beforehand that there is enough room in 114-F for the system inventory. For a complete pump-out, the exchangers, lines and vessels should be drained to the sump tank 115-F then transferred from 115-F to 114-F for storage. Depending upon the duration of the shutdown and if maintenance is required, the vessels may remain under pressure. If they are depressured, they must be purged of gas with nitrogen and then maintained under a positive nitrogen pressure to avoid the entrance of air. CAUTION If a vessel or any equipment is to be entered for inspection and / or maintenance the nitrogen must be purged from the equipment or vessel with air prior to entry. When air purging is not desired proper air supply must be supplied for personnel entering the equipment or vessel. Section 9 – Shutdown Procedures

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NOTE When shutting down the OASE system, or any system, if time permits, it is always wise to test the emergency shutdowns and auto-start circuits, to ensure their operability. This should also be done during start ups. 9.1.14.

High Pressure Condensate Stripper Shutdown

When venting is switched to PIC-1032, process condensate from 142-D1 to 130-D will cease.130-D can be taken out of service at this time. Open AV-1017 to send condensate to check pit. Reduce the level in 130-D to 25% by lowering the setpoint on LIC-1025 then place LIC-1025 in manual, close the valve then isolate it. Be sure the level does not go low in the bottom of the 130-D during this time to avoid blowing MP steam through to the drain. CAUTION The 188-Cs and 174-Cs exchangers are NOT designed for the medium pressure steam temperatures so significant damage can occur if a steam blow through is allowed.

Stop the 121-J pumps and isolate. Condensate from 142-D1, if any, will be directed to check pit through LV-1003B. Slowly reduce the setpoint on FIC-1019 while watching the flow on FIC-1002. The FIC-1002 flow should continue to control at the setpoint as FIC-1019 is reduced. Isolate FV-1019 once it is fully closed. Close the inlet MP steam valve and bypass.

9.1.15.

High Temperature Shift Converter Shutdown

With the OASE system and the H. P. condensate stripper shutdown, the front end rates can probably be reduced to 50 to 60% of design at the associated backpressure. When process air is stopped to the secondary reformer, the inlet temperature of the HT shift converter will decrease and the reaction will cease. Flow through the vessel will be stopped Section 9 – Shutdown Procedures

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when feed gas and process steam to the primary reformer are stopped. The process air rate to the secondary reformer is incrementally reduced so that its temperature will decrease at a 50°C /h rate. With TIC-1010 on automatic, 102-C bypass will start to open to maintain the HT shift inlet temperature. This should be adjusted either in automatic or manual so that the HT shift temperature decreases at a 50°C /h rate. The feed gas rate to the primary reformer is then incrementally reduced. Simultaneously, PIC-1032 at 103-C2 outlet can be slowly adjusted to reduce and maintain the system back pressure at 10 kg/cm2(g). When the feed gas flow is finally stopped, PIC-1032 will be partially open at the HTS outlet to vent the process steam flow and maintain approximately 7 kg/cm2(g) back pressure on primary and secondary reformers. For a shutdown of short duration (a few hours) the vessel can remain hot and pressurized. If the shutdown is long term, the vessel should be depressured and nitrogen purged to displace the process gas atmosphere to avoid condensation of the steam which can damage the catalyst. Then it is to be maintained under positive nitrogen pressure. Steam generation will again drop significantly during the HTS shutdown but the demand will not reduce at the same rate. Import steam flow will increase through PV-1015. BFW preheat in the 103-Cs will decrease rapidly as the HTS reaction is stopped. When loss of boiling in the 103-Cs occurs, there may be a sudden but short surge of BFW due to the collapsing of steam in the piping until the piping refills with water again. There may also be a sudden drop of the level in 141-D due to the collapse of steam bubbles in the system.

Section 9 – Shutdown Procedures

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Reforming Section Shutdown

NOTE The following procedure assumes the primary and secondary reformer catalyst will not be exposed to an air atmosphere during the shutdown period. If vessel entry or the entrance of air is anticipated, the catalyst will require oxidation. A steam oxidizing procedure follows this shutdown procedure. Secondary Reformer After the synthesis section, Methanator, and LTS converter have been shutdown, process air is not required for process conditions. However, it enhances steam generation and is the primary source of instrument air for the complex. Therefore process air will be removed from 103-D just prior to feed gas to the primary reformer being removed. Gradually decrease FIC-1003 so that the 103-D temperature decrease is no greater than 50°C / hr. As FIC-1003 flow is decreased, 101-JT speed will reduce and FIC-1004, atmospheric vent will open. Monitor the temperature of the air exit the preheat coils and if it becomes too hot, BFW can be injected through SP-DH-211, controlled by TIC-1044, to control the temperature of the hot coil and / or steam can be added by FIC-1044 to the cold coil inlet. When FIC-1003 flow is terminated FV-1003 must be closed immediately. FIC-1004 (FV-1004) will be controlling the air to vent at SP-151, then 101-JT speed can be reduced to minimum governor speed, if it is not already there. The 101-J Air compressor can be operated on vent FIC-1004 (FV-1004) supplying air to the Plant Air / Instrument Air headers unless a shutdown is needed or steam supply is limited. If it is determined to shut down the 101-J an alternate source should make instrument air available. This should only be done after natural gas and steam are removed from 101-B and the primary reformer temperature has been decreased. After the air is removed from 103-D, high pressure steam header pressure from 101-C will decrease rapidly. The offsites package boiler must be prepared for the rapid loss of steam production and pressure. The HP steam header pressure can be lowered to the medium pressure 4,690 kPag range. The package boiler firing will be increased to compensate as required. Steam for the plant is expected to be very tight at this time and all measures necessary to conserve steam will be required. After natural gas and steam feeds are removed from 101-B and the primary reformer temperature decreased, the steam flow to the secondary reformer through FV-1044 should be closed.

Section 9 – Shutdown Procedures

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Steam and gas flow through the primary reformer is replaced with a nitrogen flow to sweep the vessels of the steam atmosphere. The reformers are then maintained under nitrogen pressure. Remove condensate by periodically opening low point drains. Lower the pressure in the primary and secondary reformers and add nitrogen. Continue to remove condensate until the system is dry and cooled down. Primary Reformer Shutdown After process air to 103-D is discontinued, gradually decrease the Natural Gas flow on FIC-1001 to the primary reformer. As each incremental decrease is made, the burner firing of the primary reformer will require adjustments to maintain the same temperature profile. HIC-1108 vent exit the 108-DA/DB can be opened to maintain enough cooling gas flow through the feed gas preheat coil, if necessary. While decreasing Natural Gas flow and burner firing, the temperature of the 101-D hydrotreater, TIC-1305 will require adjustment. The steam rate to the primary reformer should be maintained at a minimum of 4 to 1 steam to gas ratio while Natural Gas is being decreased. It should not be lowered to less than 30% of normal flow until feed gas is discontinued and reformer temperatures are being decreased. During this period, reduce then continue to maintain the system backpressure at 7 kg/cm2(g) by adjusting the vent valve, PIC-1032. Stop all Natural Gas feed to 101-B as the 101-B outlet temperature reaches about 700°C. When process gas flow is stopped, watch the reformer temperatures closely and shut off burners as required to maintain the temperature profiles. After Natural Gas flow is discontinued, FIC-1001, HIC-1061 and XV-1201 are closed by activating HS-1251, start lowering the primary reformer temperatures at a rate not greater than 50°C /h until temperatures reach 400°C by reducing firing and burners. Burners should be taken off-line in the reverse order as they were fired in order to maintain an even heating pattern. Reformer Catalyst Oxidation (Steaming Method) If the shutdown of the primary and secondary reformers is to be of long duration, or if the catalyst is to be exposed to an air atmosphere, then it must be oxidized before exposure. The following steaming method of oxidation can be used. Flow steam through the primary and secondary reformers at 50% rate minimum with a backpressure of not less than 7 kg/cm2(g) for even flow distribution. Maintain tube wall temperatures below the maximum design values and / or a minimum of Section 9 – Shutdown Procedures

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760°C catalyst temperature for 101-B. WARNING Monitor carefully and do not exceed maximum tube wall temperatures at the hottest tube wall spot. Steam will react with the reduced nickel catalyst, forming nickel oxide, giving off hydrogen. Continue to flow steam at the previously described flow and temperature for 6 to 8 hours or until no non-condensable gas is found at the exit stream from the secondary reformer. When these conditions exist, it is safe to assume that most of the reduced nickel in the catalyst has been oxidized. When it is determined that oxidation by steaming is finished, the temperatures of the primary and secondary reformers can be reduced at a rate no greater than 50°C / hour. When temperatures are below 400°C, steam flow may be discontinued and burner firing stopped. Continued cooling should be by flowing nitrogen through the reformers. NOTE If the secondary reformer temperatures cannot be maintained at minimum of 760°C, even though the primary reformer tube wall metal temperatures have been elevated to their maximum allowable of temperature, steaming for 8 to 12 hours at the maximum possible steam rate will usually oxidize the catalyst to 80% oxidized. During the steam oxidizing exercise, a cooling steam flow is also required through the process air preheat coil and possibly gas flow through the preheat coils in the 101-B convection section. The secondary reformer effluent will be venting through PIC-1032. Start a flow of nitrogen at XV-1201 downstream to the 101-B mixed feed coil to displace residual steam from the primary reformer tubes and into the secondary reformer, 101-C, 102-C, 104-D1, 103-C1, 103-C2 and out through the PIC-1032 vent as described earlier. When the equipment has been swept with nitrogen, the vent valve to the front end vent header, PIC-1032, will be closed off and a positive pressure of nitrogen maintained on the entire system. Allow the equipment to cool down slowly and remove all accumulated condensate periodically through low point drains. 9.1.17.

Shut down 103-JTC

When the steam from 103-JT is no longer flowing to the 103-JTC, the condenser can be shutdown.

Section 9 – Shutdown Procedures

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1. Stop the hogging jet (if in service). Open the drain valve upstream of the motive steam block partly, then close the motive steam isolating valve in LS2217-3”. 2. Switch the HOA switch of the spare 123-J to the “OFF” position. 3. Close the air block valve in the inlet of First Stage Ejector and close the steam block valve in the inlet of First Stage Ejector. 4. Close the air block valve in the inlet of Second Stage Ejector and close the steam block valve in the inlet of Second Stage Ejector. 5. Stop the sealing water supply to PRV-103JTC. 6. Close the block valve in the make-up water line DM1085-2”, if open. 7. Place LIC-1018 in manual and close then isolate the valve. Maintain a normal level in the hotwell if the shutdown is not to be long term. 8. Shutdown 123-J, close the block valves at the discharge of 123-Js. Follow similar steps with relevant valves, machines for shut down of 101-JTC / 102-JTC. 9.1.18.

Shut Down and Secure the Steam System

As the process air and feed gas are being removed and all steam users have been shut down, the 141-D steam drum will produce less steam and the Steam system will eventually be supported by the Offsite Package Boiler through PV-1015 or by OEP through PV-1075. The imported package boiler steam will help maintain the MP steam header and there will be no requirement of HP steam. Monitor the HP steam superheater coil temperatures to ensure they do not exceed design. When a shutdown of the 141-D is required, close and isolate the BFW manual isolation valves to the HP Desuperheaters TV-1553. Also close and isolate any steam traps. As the 141-D steam drum and HP steam system cools all of the low point drains in the steam distribution piping should be continuously checked and drained of condensate. Stop phosphate injection to the drum. When a shutdown for the entire HP / MP steam system is required, close and isolate all the BFW manual isolation valves to the multiple desuperheater valves. As the steam systems cool, all of the low point drains should be continuously checked and drained of condensate. If the shutdown is of short duration and maintenance to the steam drum or steam system is not required, the 141-D drum can retain a low level and a nitrogen blanket of 0.35 to 0.7 kg/cm2(g) put in the drum and steam system. If the shutdown is of long duration and maintenance is not required, the steam drum can be laid up either wet or dry. Wet lay up entails flooding the drums with BFW containing an excess of oxygen scavenger until water overflows the drum vent valve. Then, place a nitrogen blanket on Section 9 – Shutdown Procedures

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the system. Dry lay up entails draining all of the steam generating equipment of water and pressuring the entire system with nitrogen to approximately 0.35 to 0.7 kg/cm2(g). 9.1.19.

Shut down 104-Js

Shut down the turbine driven pump first. (Steam supply will be very tight. The motor driven BFW pump should be used.) CAUTION Before shutting down the turbine verify that the governor system and trip system are in proper working order. If the operational integrity is uncertain shut off the main steam isolation valve to stop the turbine. Reduce the turbine speed to a minimum rpm. Shut down the turbine using hand switch. Observe the action of the trip valve and linkage. Close the main steam isolation valve and its bypass valve in MS1101-6”. NOTE Isolation valves located in the turbine inlet steam piping must be closed after the trip valve has closed. Do not use the trip valve as a long term shut off valve. Close the exhaust butterfly valve and its bypass valve in VE1010-30”. Close the sealing steam shut-off valve. Open the turbine casing drains to remove any condensate in casing. CAUTION Do not apply seal steam to the packing cases for more than xx minutes while the turbine rotor is idle. This condition will cause uneven heating of the turbine rotor and casing which may result in a distorted casing, bowed rotor shaft or other related problem. Allow the rotor to come to a complete stop and cool down for approximately x hours before turning off the cooling water and stopping the lube oil circulation.

Section 9 – Shutdown Procedures

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Isolate the turbine casing condensate ejector SP-104JT from the turbine first then the LP motive steam and outlet isolation valves. First close pump discharge isolation valve and SP-ARV-104J bypass valve. Close the isolating valve in the kickback line BFW1051 only if the pump is to be drained or opened. Then close the suction valve. Close cooling water supply and return valves. Open pump casing and piping drains if maintenance work or inspection is required on the pump. If 104-JA is in use, then close the discharge isolation valve then stop the pump using the local HOA switch. Close SP-ARV-104JA bypass valve. Close the isolating valve in the kickback line BFW1036 only if the pump is to be drained or opened. Then close the suction valve. Close cooling water supply and return valves. Open pump casing and piping drains if maintenance work or inspection is required on the pump. 9.1.20.

Shut down 101-JTC

When the steam from 101-JT is no longer flowing to the 101-JTC, the condenser can be shutdown. 1. Stop the hogging jet (if in service). Open the drain valve upstream of the motive steam block partly, then close the motive steam isolating valve. 2. Switch the HOA switch of the spare 118-J to the “OFF” position. 3. Close the air block valve in the inlet of First Stage Ejector and close the steam block valve in the inlet of First Stage Ejector. 4. Close the air block valve in the inlet of Second Stage Ejector and close the steam block valve in the inlet of Second Stage Ejector. 5. Stop the sealing water supply to PRV-101JTC. 6. Close the block valve in the make-up water line DM4085-2” if open. 7. Place LIC-4018 in manual and close then isolate the valve. Maintain a normal level in the hotwell if the shutdown is not to be long term. 8. 118-J, close the block valves at the discharge of 118-Js. 105. 9.1.21.

Emergency Procedures Introduction

Emergency conditions may arise on the unit at any time and it is obviously impossible to present detailed instructions that would apply to all situations. Knowledge of the unit and a complete understanding of the process involved are the best guarantees that operators have to safely and efficiently overcome any unusual conditions which may develop. Complete understanding and familiarity with the unit alarms and warning devices should be a "must" for all personnel concerned. Actual field locations of alarms, and warning devices, as well as all unit instruments Section 9 – Shutdown Procedures

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are on the piping and instrumentation flow diagrams. This information should be consulted and digested, so that any emergency condition may be readily identified and properly handled. In every instance the action taken should satisfy the following requirements: • The action must be one that can be performed without undue hazard to plant personnel. The operators should never jeopardize the safety of themselves or others. • The action should place and maintain the unit equipment in a safe condition. Design pressures, temperatures, or flow rates should not be exceeded. Prompt action demands that these values be known by the operators beforehand. • The action taken should permit resumption of normal operation as quickly and as safely as possible after the emergency has been corrected. Certain emergency conditions of the plant result in automatic action of controls to prevent harm to catalysts, vessels, or equipment. However, this does not in any way relieve the operator from the responsibility of taking immediate corrective action for the unusual conditions. 9.1.22.

Loss of Ammonia Recovery System

This is usually due to a loss of circulation due to pump or instrumentation failure and does not represent a major plant emergency. It can, however, cause a major purifier upset if steps are not quickly taken. PV-1033A valve should be isolated in the field to stop high ammonia content gas from going into the 109-Ds. Gas from 124-D will then vent to the ammonia vent system. Gas can be taken into the fuel gas system by opening FIC-1029. This action will cause an increase in NOx emissions from the primary reformer stack and must be done slowly in order not to upset the reformer box draft. Approximately 5% loss of production will be noticed since the purge gas and ammonia are no longer being recovered and recycled back into the process. 9.1.23.

Loss of 103-J Synthesis Gas Compressor

FV-1024, HV-1033 and HV-1101 should all be closed, if the trip has not automatically already done so, leaving the synthesis loop pressurized. Also vent HV-1019 should be closed if open. 149-D will vent through PV-1109 and 147-D will vent through PIC-1108 both to the ammonia vent. Loop depressurization will continue at a significant rate until PIC-1109, the 149-D vapor overhead, is closed causing PIC-1038, 123-D vent, to open PV-1038B. Isolate PV-1038A. Once Section 9 – Shutdown Procedures

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this valve is isolated, 149-D will vent through PV-1038B to the ammonia vent. 147-D will vent through PIC-1108 to 123-D, to PV-1038B to the ammonia vent. Depressure the converter through the HIC-1019 vent to 3.5 kg/cm2(g) at a rate of 20 kg/cm2(g) / hr., if depressuring is required, otherwise leave the loop under synthesis gas pressure. HV-1028 will open to a preset position letting HP steam to the MP system. Monitor the MP steam system to assure that the pressure is being maintained and adjust HIC-1028 as required to get control. Once under control, slowly close HIC-1028 and let PIC-1018 or PIC-1013 controllers letdown the steam under automatic control. 123-Cs HP steam generation will cease causing a steam shortage in a fairly quick period of time. BFW flow on FIC-1020 will be ramped down to avoid thermal stress on the exchangers but the flow must not be stopped until it is verified that LIC-1001A/B and TIC-1011 have good control of the level in the steam drum and temperature inlet the LTS, respectively. 103-J XV-1103 LP case discharge check valve assist will trip to the closed position to prevent an uncontrolled backflow of high pressure gas. PIC-1004 vent will open to maintain the system backpressure and flow. A different source of hydrogen rich gas from 144-D through FIC-1703 for hydrogenation in 101-D Hydrotreater must be started. 105-J compressors will continue to run and go into recycle mode to protect the compressors. 105-JT will slow down due to the lower load and dropping pressure on PIC-1009 which will tend to lower the HP to MP extraction flow and add to the MP steam system upset. 9.1.24.

Loss of 105-J Refrigeration Compressor

FIC-1009, FIC-1010, FIC-1011, and FIC-1012 should be opened, but only if the automatic system has not already done so. HIC-1028 will open to a preset position letting HP steam to the MP system. Monitor the MP steam system to assure that the pressure is being maintained and adjust HIC-1028 as required to get control. Once under control, slowly close HIC-1028 and let PIC-1018 or PIC-1013 controllers letdown the steam under automatic control. The flash drum pressures may increase to the relief valve pressure relieving to the ammonia vent due to the continued 103-J recycle flow. Section 9 – Shutdown Procedures

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130-Cs will no longer be able to chill the gas to the molecular sieves and the water loading to the 109-Ds will increase significantly. If 105-J can not be immediately restarted, 103-J and the synthesis loop should be shutdown and blocked in as previously described except that the process gas venting should be at PIC1084 not PIC-1004. The Purifier will also need to be shutdown since there will be no chilling in the 130- Cs and the molecular sieves will quickly saturate. Since the ammonia in the converter effluent gas stream will not be fully condensed, the ammonia concentration of the synthesis gas inlet the converter will be very high causing a loss of reaction within the converter. FIC-1059 will be automatically opened to recycle gas around the converter followed by HV-1101. 9.1.25.

Loss of the Purifier

The loss of the purifier will most likely be due to an expander problem and / or loss of condensation of gasses within the purifier possibly due to fouling of the heat exchangers with dirt, water or ammonia breakthrough. Continued ammonia production is possible but operational changes of the process air and the synthesis loop purge rate, among other things, will have to be carried out and done so very quickly. The hydrogen to nitrogen ratio in the front end of the plant is significantly lower than is required for ammonia production, because the purifier controls the final nitrogen content of the synthesis gas, therefore, an immediate decrease of the air to the secondary reformer will have to be made. The synthesis gas compressor will quickly see a much heavier molecular weight gas and will react accordingly requiring more steam for he extra power required as well as a potential upset with the antisurge control system. A different source of hydrogen rich gas from 144-D through FIC-1703 for hydrogenation in 101-D Hydrotreater must be started IF 103-J is stopped or goes on full recycle and the pressure is too low to push gas to the front end. Firing in the primary reformer will have to be increased to lower the methane slip and front end rates will probably have to be reduced. Since the methane and argon are no longer being removed in the purifier and will now continue into the synthesis loop with the synthesis make-up gas, the synthesis loop purge rate will have to be significantly increased on FIC-1024 and using HIC-1019. Section 9 – Shutdown Procedures

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Since the reject gases from the purifier are no longer being sent to the secondary fuel gas system for burning, there will be a significant draft swing in the primary reformer as well as a temperature reduction due to the loss of the heat from the secondary fuel gas system. The draft will go more negative until the controls have time to react and the operators will have to increase the fuel gas to the main system as PIC-1002 is not fast enough. If the purifier needs to be isolated for maintenance, open the bypass line fully then slowly isolate the outlet valves followed by the inlet valves. The molecular sieves will have to be switched over to synthesis gas for regeneration until the Purifier is back in service. 9.1.26.

Loss of Methanator, 106-D

Any upset in the front end of the unit, particularly the shift converters or the CO2 removal system, may result in excessive carbon oxide concentration in the feed to the Methanator. This will most likely be caused by a circulation failure / upset in the CO2 removal system or possibly due to a LTS temperature upset. This excessive carbon oxide content in the gas stream causes sudden and high temperatures to develop in the Methanator because of the highly exothermic nature of the methanation reaction. A theoretical average temperature rise of about 66°C occurs for each mol percent carbon dioxide in the inlet gas. The trip will shut the inlet MOV valves, MOV-1017 and MOV-1018, to the molecular sieves and will trip the AV-1029 reflux valve on the Purifier. Automatic venting at PIC-1005 upstream of the Methanator, activated by the increasing process backpressure due to the closing of the inlet isolation valves by the high-high temperature trips in the Methanator catalyst bed, has been provided. However, if the Methanator catalyst temperatures start to climb rapidly and it is evident that an emergency condition is impending, it is best to remove the feed from the Methanator at once using HS-1253 to trip the inlet valves and not wait for the high-high temperature trips. 103-J compressor will revert to a total recirculation condition and reduction in speed due to loss of fresh feed leading to a reduction in MP steam extraction flow. The turbine drive may even trip on over speed if the governor and anti-surge valves do not react in time. If the emergency is such that the synthesis loop must be isolated from 103-J, follow the procedures previously stated for loss of the 103-J. 105-J will load will reduce and it too will go in total recycle. Section 9 – Shutdown Procedures

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If the stopping of feed gas to 106-D is due to high carbon oxides causing a temperature "run-away" (temperatures in the vessel exceeding design maximums), the vessel should immediately be depressured through the manual vent, V1011 at the vessel inlet and back-purged with synthesis gas or purged with nitrogen injected in 106-D outlet line through N1007. This will decrease the amount of gas remaining in the vessel for reaction and the high temperatures are less harmful to the vessel at lower pressure. WARNING Depressuring the Methanator can make the carbon oxide related problem worse IF the inlet trip valves to the Methanator leak through. This can allow high carbon oxide containing gases to enter the vessel at greater quantities as it is depressured. Check to be sure that the valves are fully closed before depressuring and use the inlet vent valve to do the depressuring instead of PIC-1004. WARNING When cooling the Methanator while it contains gas with carbon oxides caution must be exercised if the temperature approaches 205°C. Toxic nickel carbonyl can be formed at this temperature when carbon oxides are present. All personnel must be made aware of this concern. The Methanator must be cooled to below its normal operating temperature before it can be put back in service. Flowing synthesis gas / nitrogen up thorough the catalyst bed to the vent at the vessel inlet will aid in cooling and will remove the carbon oxides from the catalyst bed. Once the Methanator temperature has cooled to below the high temperature trip temperatures and the proper carbon oxide content of the feed stream has been attained, the Methanator may then be slowly returned to normal operation. Use a procedure similar to that for normal start-up. Feed rates that may have been reduced when the emergency developed should be slowly returned to normal. Return the synthesis and refrigeration system to normal. Product flow to battery limits may be started when product is available. 9.1.27.

Loss of OASE Solution Circulation

OASE circulation loss can only occur by a loss of the OASE circulation pumps or malfunction of a piece of equipment or an instrument. Loss of OASE circulation requires the following steps to be initiated as rapidly as possible: • Trip switch HS-1253 to close XV-1211 and MOV-1011, if the automatic low OASE flow trips have not already tripped the Methanator inlet valves. These valves will trip closed in 20 seconds if flows are not restored on FIC-1005 and in 5 seconds if flow is not restored on FICSection 9 – Shutdown Procedures

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1014. 103-J compressor will revert to a total recirculation condition and reduction in speed due to loss of fresh feed leading to a reduction in MP steam extraction flow. The turbine drive may even trip on overspeed if the governor and anti-surge valves do not react in time. If the emergency is such that the synthesis loop must be isolated from 103-J, follow the procedures previously stated for loss of the 103-J. Follow the previously stated instructions for loss of the Methanator, 105-J and 103-J compressors. Monitor the secondary fuel gas system and reformer temperatures since the 163-D flash gas load may be reduced or stopped.

If the circulation loss is total and for an extended period, the absorber should be blocked in and held under process gas or nitrogen pressure until the item causing the shutdown is repaired and the solution can be regenerated. If the heat load to the stripper is too great because of 105-C exchanger being in service with low OASE circulation rates, then the LTS effluent flow should be reduced or taken out of service by venting upstream of 104-D2A at PIC-1032. This must be done if the 107-J circulation flows on FIC-1005 are lost. Switch seal flushing to OASE solution, if not already in service, to avoid solution dilution. If the maintenance of the item to be repaired takes an extended period of time and requires entry into some vessel, the solution inventory in the system must be transferred to storage. 9.1.28.

Loss of LTS Converters, 104-D2A/B

Possible temperature upsets in the secondary reformer effluent system or in the 103-Cs heat recovery circuit joining the high and low temperature shift converters can cause unacceptable temperatures in the LTS section. Excessive temperature rises in the LTS section can cause a decline in catalyst activity, permanent catalyst damage, or vessel damage. The most likely cause of this will be a BFW flow upset caused by a HP steam system or 141-D level upset reducing the BFW flow to the 103-Cs. Excessively low temperatures will cause a loss of reaction and a breakthrough of CO and possibility of condensation on the catalyst leading to its getting damaged. Emergency valves are provided to enable bypassing the LTS converters in the event of conditions leading to high temperatures during normal operation. This bypassing can be done by using HS-1004 to open MOV-1009 bypassing the LTS converters then closing MOV-1008 and MOV-1007 isolating the LTS inlet and outlet respectively. The Methanator needs to be tripped as described previously as well as the 103-J placed on Section 9 – Shutdown Procedures

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recycle or tripped. Immediate actuation of HS-1253 is necessary if the interlock trip does not occur. This hand switch will isolate the 106-D Methanator by closing XV-1211 and MOV-1011 reducing the possibility of high carbon oxide (CO) containing process gases from entering the vessel resulting in a temperature run-away. Process gas will vent at PIC-1005. After the cause of the emergency has been corrected, the LTS converters can once again be brought into the circuit and rates may be increased slowly as desired. Adjust the heat recovery circuits joining the high and low temperature converters to optimum. 9.1.29.

Loss of HTS Converter, 104-D1

The loss of the 104-D1 HTS will most likely be due to a major process flow loss in the front end of the plant such as loss of process air or loss of process gas as described later in this section. Other possible scenarios are a tube failure in 102-C or 101-C HP steam superheater / generator, respectively. Either of these failures will be indicated by a sudden loss of steam drum pressure (102-C), loss of level in 141-D (101-C) and a rapid increase in the process gas stream pressure with a sudden, sharp temperature drop inlet and throughout the HTS. If this occurs: • The Methanator should be immediately tripped by using HS-1253. • The LTS should be immediately bypassed by activating HS-1004. • Put the HTS downstream vent PIC-1032 on manual and open it fully. • Activate HS-1251 to trip the process gas and process air out of the front end of the plant. • Recycle or stop 103-J and 105-J compressors • See the following procedures for tripping the process air and the process gas streams and associated actions / results. • Refer to the descriptions of those previously written emergencies for additional actions / results. 9.1.30.

Loss of Process Air

Loss of process air is generally caused by problems or failure of the 101-J compressor or is a result of a process gas trip action. If the compressor does fail, instrument air and steam must be supplied immediately from the offsite source. Upon loss of process air, steam generation will be greatly reduced and ammonia production will stop. With the loss of Process Air, the following immediate actions should be taken: • MP steam export will decrease and the Package Boiler load will increase to help import MP steam. Section 9 – Shutdown Procedures

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103-J will trip on interlock action – refer to the previously described procedures. 106-D will trip on interlock action – refer to the previously described procedures 104-D2A/B will trip on interlock action – refer to the previously described procedures. 101-B secondary fuel gas system will trip on interlock action. 101-B fuel gas tunnel burners, superheat burners and pilots will trip on interlock action. Bring 105-J to minimum governor and shutdown if required – refer to the previously described procedures. Trip the Methanator with HS-1253 – refer to the previously described procedures if interlock did not already do so. Bypass the LTS – refer to the previously described procedures if interlock did not already do so. Verify that MOV-1006, XV-1212 have tripped closed with FV-1004 open. FIC-1044 setpoint will reset putting a specific amount of steam to the secondary reformer. Reduce feed gas, FIC-1001, if required due to lack of steam. Reduce Steam, FIC-1002 to no less than 40% flow rate, if required, due to lack of available steam. Stabilize 101-B Primary Reformer arch burner firing and firebox temperatures and pressure. Monitor the steam to carbon ratio for 101-B. Adjust HP, MP and LP steam systems as needed.

Once the secondary reformer has been ‘relit’, and the gas venting ahead of the Methanator is on spec, operations will proceed to increase the front end rates and initiate steps for ammonia production. NOTE Even if air is restored immediately, the steps outlined above must be taken. When air is reintroduced to the secondary reformer, the procedure should be the same as for a normal start-up. The air must be added slowly. Too rapid introduction of air will result in excessively high temperatures in the catalyst bed with damage to the catalyst and downstream exchangers. 9.1.31.

Loss of Primary Reformer Feed Gas

This failure is normally a result of a trip due to low steam to carbon ratio or loss of the feed gas source. The following immediate actions should be taken: • Verify 103-J has tripped due to interlock action – refer to the previously described procedures. • Verify 106-D has tripped due to interlock action – refer to the previously described procedures. Section 9 – Shutdown Procedures

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• Verify 104-D2A/B has tripped due to interlock action – refer to the previously described procedures. • Bring 105-J to minimum governor and shutdown – refer to the previously described procedures. • Verify that the process air trips and isolations have occurred – refer to the previously described procedures. • Verify FV-1001, FV-1003, XV-1212 have tripped closed. • Verify that the main fuel gas controller, PIC-1002, begins to ramp down to minimum firing • Verify that the secondary fuel gas burners have tripped, closing XV-1222A / B, and opening XV-1222C. • Verify that the fuel gas tunnel burners have tripped, closing XV-4240A / B, and opening XV-4240C. • Verify that the fuel gas superheat burners have tripped, closing XV-1240A / B, and opening XV-1240C. Also verify the pilot valves have tripped, closing XV-1245A / B, and opening XV1245C. • Unblock and open HIC-1108 to cool the feed gas preheat coil and control the temperature to the hydrotreater if high temperatures prevail. Immediate operator action required as follows: • Open PIC-1032 to vent the steam flowing through 101-B, 103-D, and 104-D1 and maintain about 10 kg/cm2(g) of backpressure or less. In case purging steam is not available, continue to reduce pressure further and then replace steam with nitrogen purge. • Increase import MP steam from offsites through PV-1015 or from OEP through PV-1075 which will increase the package boiler firing rate - if gas is available to the offsites. • Shut down all steam consumers. Switch steam driven equipment to motor-driven, where possible. Use the steam available to help remove the heat from the 101-B furnace tubes at reduced rates to avoid excessive thermal shock to the reformer tubes. • Block in the CO2 absorber using MOV-1005 and maintain pressure with nitrogen, if required – refer to the previously described procedures. • Continue steam flow, if available, through the primary reformer tubes at reduced flows of about 30% for at least 30 minutes to sweep all hydrocarbons out to avoid the possibility of a coke deposit on the catalyst. • Start nitrogen to the 174-D, 101-D, 108-DA/DB, 101-B, 104-D2A/B, 121-D, and 122-D2 to purge these vessels. Then block in under nitrogen pressure. Hold under a slight nitrogen pressure until ready for restart if the shutdown is long term. 9.1.32.

Natural Gas Failure

A failure of the Natural Gas supply will affect feed gas flow to 101-B and may affect the fuel gas to the entire plant. A total failure of Natural Gas will stop feed and fuel gas to the plant as well as the package Section 9 – Shutdown Procedures

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boiler and any other users in the offsites. 9.1.33.

Loss Of Process Steam

Usually the loss of process steam would be preceded by a loss of medium steam pressure or a sudden increase in process backpressure. The process air and process gas must be reduced to match the available steam flow much the same as a rate reduction or planned shutdown. The process air and process gas will both be tripped if the steam to carbon ratio falls below 2.3 to 1. Process gas and air will automatically be reduced by the ratio controls if a steam flow loss occurs and the instrumentation is in automatic and remote. If the loss of process steam should occur action must be rapid and decisive. • Bring 103-J to minimum governor, isolate the hot loop and shutdown if the unit has not tripped due to interlock action – refer to the previously described procedures. • Bring 105-J to minimum governor and shutdown – refer to the previously described procedures. • Trip the Methanator with HS-1253 if the unit has not tripped due to interlock action – refer to the previously described procedures. • Bypass the LTS if the unit has not tripped due to interlock action – refer to the previously described procedures. • Verify that the process air trips and isolations have occurred – refer to the previously described procedures. • Verify that the process gas trips and isolations have occurred – refer to the previously described procedures. • Open HIC-1108 in manual or by lowering the setpoint to cool the feed gas preheat coil and control the temperature to the hydrotreater if high temperatures prevail. • Verify emergency demineralized water flow to 103-D and 107-D water jackets as well as 101U deaerator, if required. • Switch steam turbine drivers to motor drives, where possible. • Import MP steam from offsites package boiler through PV-1015 or from OEP through PV-1075 and maintain MP steam header pressure. Maintain some MP steam flow to 101-B, if possible, for at least 30 minutes. • Open PIC-1032 to vent the steam flowing through 101-B, 103-D, and 104-D1 and bring down the system pressure to about 5 kg/cm2(g) of backpressure or less. In case purging steam is not available, continue to reduce pressure further and then replace steam with nitrogen purge. 9.1.34.

Loss Of Steam Pressure

Partial loss of steam pressure can result in some operational problems. The entire unit should be checked to see where the fault lies.

Section 9 – Shutdown Procedures

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If a steam header relief valve should open and not reseat, the unit should be shut down to fix the valve as the unit is closely linked to steam production. Conditions may arise in the unit during serious operational upsets or as a result of emergencies, which could conceivably create a demand for steam generation beyond the capacity of the equipment provided. To protect the steam generating equipment against serious damage, the steam consumption should never exceed the capacity that is available or that can be generated at that particular emergency condition. In several of the emergencies, which may occur, the synthesis gas is vented, resulting in a loss of ammonia production. Loss of heat recovery in the synthesis loop as ammonia production ceases, creates a large deficiency in the unit steam balance due to the loss of boiler feedwater preheat and steam generation in the 123-Cs. No attempt should ever be made to recover this loss beyond the normal steam generating capacity of the unit and the package boiler. Instead, every effort should be made to conserve the steam being produced by using less where possible. It should always be kept in mind that any attempt to use more steam than can be generated in the unit could result in an initial level swell in 141-D, due to rapidly reducing HP steam pressure, followed then by a low level in the steam drum 141-D tripping the front end of the unit. The importance of maintaining the steam balance within safe limits during upsets or other emergencies cannot be overemphasized. There is a limited steam generation capacity in the offsites. The ammonia unit can be supplemented with offsites MP steam by increasing the firing rate of the package boiler. 9.1.35.

Loss of Water - Steam Drum 141-D

Should this emergency occur and it is impossible to immediately re-establish the boiler feedwater flow to the drum, the action taken must be positive and immediate. This is usually due to a loss of high pressure boiler feedwater pumps or instrument failure. However, as previously mentioned, a tube failure in 101-C can also lead to a sudden and dramatic water loss in the drum. A low-low steam drum level on 141-D will trip the plant the same way a loss of feed gas trip does. If the loss is not due to a low-low steam drum level then: • Bring 103-J to minimum governor, isolate the hot loop and shutdown – refer to the previously described procedures. • Bring 105-J to minimum governor and shutdown – refer to the previously described procedures. Section 9 – Shutdown Procedures

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• Trip the Methanator with HS-1253 – refer to the previously described procedures. • Bypass the LTS – refer to the previously described procedures. • Trip the process air using HS-1202 and verify that the trips and isolations have occurred – refer to the previously described procedures. • Trip the process gas using HS-1251 and verify that the process gas trips and isolations have occurred – refer to the previously described procedures. • Vent process steam at the 104-D1 HTS outlet vent PIC-1032 and maintain 10 kg/cm2(g) backpressure. • Process heat continues to boil the water in 101-C which lowers the level in 141-D. If 141-D and 101-C go dry and heat continues to be put in 101-C, severe damage to 101-C could result. It can not be stressed enough that forward flow of all process and cooling steam to 101-C MUST BE STOPPED by closing all downstream vents and drains if the level in 141-D can not be corrected. This is expected to be within minutes of the loss of boiler feedwater to the steam drum assuming the drum was at a normal liquid level prior to the loss. This time would drop even more if the drum level were near the minimum trip. • Discontinue all steam flow by closing FIC-1002 and FIC-1044. Vent valve PIC-1032 will remain open to depressure the front end and should be closed when the front end has been depressured. • Open HIC-1108 in manual or by lowering the setpoint to cool the feed gas preheat coil and control the temperature to the hydrotreater if high temperatures prevail. • Check that offsite instrument and plant air source is available. • Reduce steam to 101-B to about 30% of design flow to avoid causing excessive thermal stresses to the cast tube material due to rapid cooling until this needs to be stopped due to inadequate drum level in 141-D. • Stop feed gas to the 108-Ds as soon as the feed preheat coil temperature allows by closing HIC-1108. • Verify emergency demineralized water flow to 103-D and 107-D water jackets, as well; as 101-U deaerator if required. • Protect all catalyst beds with nitrogen. 9.1.36.

Loss of Make-Up Water to 101-U

When the steam generation conditions are at design values, the residence time of the water in 101-U deaerator is approximately 10 minutes. This means that full water flow to 101-U can only be interrupted for ~ 10 minutes before the 104-J pumps lose suction and trip. If it is impossible to re-establish water flow to the deaerator immediate action must be taken to safely shutdown the ammonia unit to conserve steam consumption and generation. The major steam consumers in the ammonia unit are the process and two compressors. The front end of the plant must be shut down since there will be no way to maintain the 141-D level. The unit shutdown sequence should be started as follows: • Bring 103-J to minimum governor, isolate the hot loop and shutdown – refer to the Section 9 – Shutdown Procedures

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previously described procedures. Bring 105-J to minimum governor and shutdown – refer to the previously described procedures. Trip the Methanator with HS-1253 – refer to the previously described procedures. Bypass the LTS – refer to the previously described procedures. Trip the process air using HS-1202 and verify that the trips and isolations have occurred – refer to the previously described procedures. Trip the process gas using HS-1251 and verify that the process gas trips and isolations have occurred – refer to the previously described procedures. Vent process steam at the 104-D1 HTS outlet vent PIC-1032 and maintain 10 kg/cm2(g) backpressure. Reduce steam to 101-B to about 30% of design flow to avoid causing excessive thermal stresses to the cast tube material due to rapid cooling. Process heat continues to boil the water in 101-C which lowers the level in 141-D. If 141-D and 101-C go dry and heat continues to be put in 101-C, severe damage to 101-C could result. It can not be stressed enough that forward flow of all process and cooling steam to 101-C MUST BE STOPPED by closing all downstream vents and drains if the level in 141-D can not be corrected. This is expected to be within minutes of the loss of boiler feedwater to the steam drum assuming the drum was at a normal liquid level prior to the loss. This time would drop even more if the drum level were near the minimum trip. Discontinue all steam flow by closing FIC-1002 and FIC-1044. Vent valve PIC-1032 will remain open to depressure the front end and should be closed when the front end has been depressured. Open HIC-1108 in manual or by lowering the setpoint to cool the feed gas preheat coil and control the temperature to the hydrotreater if high temperatures prevail. Stop feed gas to the 108-Ds as soon as the feed preheat coil temperature allows by closing HIC-1108. Verify emergency demineralized water flow to 103-D and 107-D water jackets, if required. If demineralized water / condensate flow is re-established to 101-U while the shutdown sequence is in progress, the shutdown sequence can be discontinued at any safe point, the unit stabilized, and restart begun. If restart is not immediate and the shutdown sequence goes to conclusion, then all vessels and systems must be protected from entrance of air as they cool by injecting nitrogen and draining water due to condensation by opening low point drains and bleeds.

9.1.37.

Cooling Water Failure

Loss or reduction of cooling water will result in the rapid loss of vacuum in the following condensers 101-JTC (for 101-JT), 103-JTC (for 103-JT), and 102-JTC (for 102-JT, 104-JT). Immediately affecting the process will be the inability to condense ammonia vapor from 105-J in 127-C leading to significantly reduced reaction in the 105-D ammonia converter.

Section 9 – Shutdown Procedures

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Loss of the cooling water system will require a fast response to shutting down the plant as all process and compressor inter stage cooling will be lost and temperatures will increase very rapidly. Slightly later, but not the least important, is the inability to cool lube oil to the compressors, turbines, fans and pumps taking effect. Process exchangers and compressor Interstage cooling will also be affected as the cooling water system warms up due to lack of circulation. If the cooling water system cannot be restarted immediately, compressors and pumps must be shut down, starting with 103-JT, 105-JT, 104-JT, 101-JT and 102-JT. The ID/FD fan bearing temperatures will need to be monitored closely and if required the machine will need to be stopped leading to trip of 101-B reformer to protect this equipment. Follow the basic outline for Natural Gas failure. NOTE If no emergency cooling water is available during cooling water or power failure, the preceding procedure must be followed to minimize heat build up in the lube oil systems of the compressors. 9.1.38.

Instrument Air Failure

The likelihood of a general instrument air failure is normally remote since the main source of instrument air is the 101-J, backed up by the offsite air source importing instrument air from the rest of the complex. However, air failure at individual instruments is more frequently encountered and it is important to know what will happen in the event of a failure. The philosophy used for the action of a valve when the air fails is that the valve will move in the direction of the greatest safety. Thus, for example, air failure will close the feed gas to the unit. The process steam valve will fail last on instrument air failure and open on loss of control signal, because it is advantageous to keep a flow of steam moving over the reforming catalyst. The action of some other valves is, necessarily, a compromise. For example, the steam drum level controller will fail open. It is obviously undesirable to overflow the steam drum, but the "fail open" alternative is chosen because the operator will have more time to catch the level and less serious equipment damage will result from a high level than by loss of level. This information is contained on the instrument data sheets located in the 'Job Specification Book" and is also shown on the P&IDs. Each pneumatic control valve has a small “FO”, “FC”, “FLO” or “FLC” designation under it. These stand for fail open on instrument air loss, fail closed on instrument air loss, fail last on instrument air loss but open on control signal loss or fail last on instrument air loss but close on control signal loss. Most of the control valves also contain a handjack that will enable the operator to manually open, close, or position a valve, if required. Section 9 – Shutdown Procedures

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Those valves that do not have a handjack will be provided with isolation valves and a bypass valve as a minimum unless it is a part of the safety trip circuits. Essential control circuits in the steam generation system are backed up by either an air or nitrogen supply from a capacity cylinder. Therefore, if a total air failure does occur, there will be enough pressure available to safely operate the valve a few times so that the plant can be safely shutdown. A review of this information will disclose that a complete air failure shuts the plant down. Fuel gas flow to the furnaces will stop as well as feed gas to the reformer furnace. Steam letdown from the HP system to the MP steam header through HIC-1028 will continue because of a back-up supply of bottled air provided for the I/P transducer, positioner, and control valve. However, steam production will rapidly decrease because heat input is greatly reduced. While steam is available, the compressors will run on kickback. Certain pumps will be running against closed level control valves. Wherever possible, it will be necessary to go on by-pass control. Steam flow can be maintained through the reformers and vent downstream of the HTS converter. The LTS converters must be bypassed. Steps for the operators to take on instrument air failure after 141-D steam drum and steam systems are under control are basically the same as for loss of process gas detailed above. 9.1.39.

Electric Power Failure

The normal primary source of electric power for the ammonia unit is supplied from the local electrical utility. Loss of this source causes a shutdown of the plant. Emergency Load Schedule And Diesel Generator Capacity The diesel-generator capacity for the plant is to be 2000 KVA with a 0.8 power factor. The following is a typical list of equipment that would be aligned on the ammonia plant emergency bus. The final list will be determined during detail design. • Lube Oil Pump Motors • Turbine Turning Gear Motors • All MOVs • Critical pump motors and their spares needed for safe plant shutdown • Instrument panels

9.1.40.

Electrical Equipment Interlocks

Section 9 – Shutdown Procedures

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The lists below summarize the different types of interlocks required by the process and the equipment associated with each. Please refer Cause and Effect Diagram Ammonia Plant (Doc. No. P2B-10-02-CE-0001-R)

9.1.41.

UPS Load Schedule and UPS Capacity

The Uninterruptible Power Supply rating is estimated to be 120 KVA at 0.8 power factor, 110 V single phase output with battery backup for 90 minutes. The following loads will be aligned to the UPS: TBD 9.1.42.

Electrical Equipment with Auto Reacceleration After Power Dip

Included herein is a listing of "critical motors" and an associated restart control philosophy. The purpose of the document is to define the motors that are to be supplied with automatic restart control circuitry to automatically restart motors in event of a switchgear transfer operation, to outline the control philosophy of the motors and to define the associated restart groups of the motors. The switchgear transfer operations involve two different operation scenarios. The first scenario is a normal supply transfer operation in event of the loss of one of two primary supply feeders. For the normal supply transfer operation the critical motors are defined as any motor that needs to be automatically restarted directly after the transfer operation has been completed to prevent the shut down of a process unit. The second scenario is the transfer of the emergency motor control centers to the emergency generator supply from the normal supply. For the emergency transfer operation the critical motors are defined as any motor that needs to be automatically restarted directly after the transfer operation has been completed to support a safe shut down of the plant. 1. Normal Supply Transfer Operation Critical Motors a. Lube oil pumps for compressors / pumps / drivers. b. Condensate pumps c. Ammonia plant MOVs. 2. Emergency Transfer Operation Critical Motors a. Lube Oil Pumps b. Condensate pumps All of the motors have inherent automatic restart controls associated with the process instrument control system. Section 9 – Shutdown Procedures

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The critical motors listed that do not have the instrumentation control facilities will be provided with automatic restart controls in the motor starters. The motors that have automatic restart control circuits that are not in the "Priority 1" restart category will be provided with time delay control features to restart the motors in sequenced steps. If the power fails on the main bus, the emergency generator will automatically start and energize feeders to the 480-Volt emergency motor control centers, EMCC. The emergency generator will start immediately upon the voltage loss to the bus but will not energize the emergency bus for about 15 seconds. The emergency generator usually requires about 15 seconds to start, come up to speed and load. NOTE Ensure that only one large motor of any set of large motors on the emergency power system is put into operation at a time. The use or starting of two large motors of a set can overload the emergency generator causing the emergency power to fail. WARNING Any equipment that is running on the Emergency Bus from the Emergency Generator may be shutdown when the emergency bus breaker is switched back to the main bus. The design is for a “make before break” switching system with a very short time setting. Be sure alternate equipment from the main bus is running prior to switching, if possible, or a severe plant upset or shutdown may result. If both drivers are on the emergency bus or if there is no alternate equipment existing, have an operator standing by the equipment to confirm or do a restart as soon as the switching is completed. 106. Removing Equipment From Service Preparations for equipment maintenance generally start with the equipment being shutdown. Following the shutdown, the equipment must be isolated, locked, and tagged from all energy sources. In all cases, this step should take, as a minimum, the form of blocking in, as well as electrically isolating the equipment. The reason behind isolating the equipment is two-fold. First, and foremost, is personnel safety. Personnel safety involves preventing possible sources of energy from inadvertently entering the maintenance area. The second concern is equipment safety, which, like personnel safety, involves preventing possible sources of energy from entering a system that it was not designed for. The next concern is the removal of process fluid. This is usually accomplished by venting, draining, pressuring, purging or pumping the equipment free of any fluids. Any residual vapors within the equipment or its isolation boundaries must be removed. In most cases, nitrogen is the preferred method for removing potentially explosive / flammable Section 9 – Shutdown Procedures

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vapors. The first step in purging equipment is to establish a vent path. Next, the nitrogen is routed by permanent connection or temporary hoses to the equipment. The following sequence should be followed before using utility hoses for flushing or purging equipment in the ammonia plant. Always refer to the Safety and Health Manual for information covering utility hose standards, and steps for inspecting each hose before use. Return any defective hoses to the warehouse for repair or disposal, after flushing and clearing the hoses. Equipment blinding and preparing the equipment for Confined Space Entry are the last requirements prior to actual maintenance work. Blinding involves placing isolation blinds at all penetration points closest to the equipment to be worked on. Normally acceptable alternatives to blinding are: 1) double block and bleed arrangement with the blocks closed and the bleed open and 2) misalignment of piping by opening a flange and moving the open ends so they are pointing away from each other. "Confined Space Entry" requirements require that the equipment to be entered is safe for personnel. Examples of things checked are toxic environment, flammable environment, and oxygen concentrations. The actual requirements for this permit will normally be specified in the PT PUSRI Safety and Health Manual. Once these requirements have been met, the equipment may be turned over to the appropriate department for inspection and / or maintenance. It should be assumed that equipment in the ammonia plant will contain process fluids after a unit or equipment shutdown. Therefore, specific procedures for opening each piece of equipment should always be followed when inspection / maintenance is necessary. 107. Returning Equipment To Service Returning equipment to service begins with an inspection of the equipment to ensure that it is ready for service and that the responsible party that was working on the equipment has signed off indicating the inspection / maintenance is complete and the equipment is ready to be returned to service. Next, the isolation blinds are removed unless purging is required for safe blind removal. This is done in preparation for purging out the equipment to remove contaminants from the system. Making the equipment oxygen free is normally the next concern in the restoration process. Oxygen-freeing equipment is normally accomplished using nitrogen. The first step in oxygen freeing begins with establishing a vent path. Next, nitrogen is routed by permanent lines or temporary hoses to the equipment. Once this is accomplished nitrogen is supplied to the equipment, until there is no oxygen present. Pressure purging is the preferred method for oxygen-freeing equipment but once-through venting can also be used, although it usually takes longer and requires more nitrogen. Oxygen-free environment is usually verified through the use of a portable oxygen analyzer. At this point the equipment is left with a nitrogen blanket of approximately 0.35 kg/cm2(g).

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Next, the equipment blinds or other isolation removed, tags and / or locks removed and is electrically restored to normal. Once this is done the equipment is ready to be placed back in service. 108. Catalyst Oxidation Oxidation of catalyst is not recommended unless it is absolutely necessary to do so. If catalyst oxidation is required, the catalyst manufacturer should be contacted to obtain their current recommendations, procedures, and possibly to supply a representative to supervise and assist during implementation of the procedure. The design of the ammonia unit does not incorporate any additional systems or equipment for use when oxidizing catalyst. Therefore, before any catalyst oxidation is implemented, the temperature and temperature differential limitations and integrity of each piece of equipment and piping system to be used must be thoroughly investigated. 109. Conclusions Unit shutdown procedures have been thoroughly discussed in the shutdown section of this manual and may be referred to and applied either in whole or in part. In addition to the primary actions previously outlined for specific failures, it is well to keep in mind the following: Steam generating equipment is very sensitive to sudden load changes. Boiler feedwater levels may bounce and cause wide variations in steam production. Level controllers may have to be reset or even put on manual control until conditions have stabilized. Preheat coils in the convection section of the primary reformer must have an adequate flow through them during furnace operations to avoid overheating. A change in the flow of any of these streams or a change in the firing conditions of the furnace itself should be immediately followed by a check of the preheat coil outlet and appropriate flue gas temperatures. Sudden venting, because of an emergency, may produce flow rates that exceed the capacity of the vent system. If this occurs, as evidenced by a back pressure increase, it may be necessary to decrease the unit throughput until normal flows can be re-established. Follow all precautions and keep air out of the various catalysts at all times during any shutdown

Section 9 – Shutdown Procedures