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PT. Brown & Root Indonesia

Doc. No. 62-IOM-PS-1201 Rev. 6A

Project TLNG Author’s Org. KJP

KJP Doc. No. S-062-1283-001 Date 27 Feb, 06

KJP Job Code J-3400-20-0000 Sheet 1 of 35

X Core Non-core Lifecycle Code A

For Information For Review For Approval X Released As-Built

Rev. Date Page Description Prep’d Chk’d App’d BP App’d

5A 09Jan’06 All For Approval M.Hatanaka Y.Kakutani Y.Kakutani

6A 27Feb’06 All Released M.Hatanaka Y.Kakutani Y.Kakutani

3.8 MTPA TRAIN CAPACITY

Operation Manual for Steam/Steam Condensate/BFW System

BPMIGAS

TANGGUH LNG

BP Berau Ltd.

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Doc. No. 62-IOM-PS-1201KJP Doc. No. S-062-1283-001 Rev. 6ASheet No. 2 of 35 Operation Manual for Steam/Steam Condensate/BFW System

BP Berau Ltd. Tangguh LNG Project

CONTENTS

1. Introduction.................................................................................................................................4 2. Basis of Design.............................................................................................................................4

2.1 General ........................................................................................................................................4 2.2 Design Condition.........................................................................................................................5 2.2.1 SERVICE CONDITIONS ................................................................................................................ 5 2.2.2 BOILER FEED WATER QUALITIES .............................................................................................. 5 2.2.3 STEAM CONSUMERS................................................................................................................... 5 2.3 Special Equipment......................................................................................................................6 2.3.1 DEAERATORS (062-D-1001A/B)................................................................................................ 6 2.3.2 PACKAGE BOILERS (062-F-1001A/B/C).................................................................................... 6 2.3.3 STEAM TURBINE GENERATOR SETS........................................................................................... 6 2.3.4 HEAT R ECOVERY STEAM GENERATORS .................................................................................... 7 2.4 Process Description.....................................................................................................................7 2.4.1 STEAM GENERATION.................................................................................................................. 7 2.4.2 STEAM DISTRIBUTION................................................................................................................ 7 2.4.3 STEAM CONDENSATE R ECOVERY AND TREATMENT.................................................................. 8 2.4.4 STEAM TURBINE GENERATOR SYSTEM...................................................................................... 9

3. Process Controls..........................................................................................................................9 3.1 Boiler Feed Water.......................................................................................................................9 3.2 High Pressure Steam ................................................................................................................10 3.3 Low Pressure Steam.................................................................................................................11 3.4 Blowdown System for Boilers..................................................................................................12 3.5 Clean Steam Condensate..........................................................................................................12 3.6 Suspect Steam Condensate.......................................................................................................12 3.7 Steam Turbine Generator Sets................................................................................................13

4. Preparation for initial start-up ................................................................................................15 5. Normal Start-up Procedure .....................................................................................................15

5.1 General ......................................................................................................................................15 5.2 Start up of Boiler Feed Water System ....................................................................................15 5.3 Start up of Package Boiler (062-F-1001A/B/C)......................................................................15 5.4 Introduce HP Steam to HP Steam Header.............................................................................16 5.5 Letdown HP Steam to LP Steam.............................................................................................16 5.6 Introduce LP Steam to Deaerators (062-D-1001A/B)............................................................17 5.7 Start Steam Turbine Generator Set (061-GS-1001A/B/C)....................................................17 5.8 Steam Condensate System .......................................................................................................17 5.9 Letdown HP Steam to MP Steam............................................................................................18 5.10 Start up of Heat Recovery Steam Generator (051/052-F-1101/1102)...................................18 5.11 Start up of the Suspect Condensate Recovery System...........................................................19

6. Normal Operation.....................................................................................................................19 6.1 Water Quality Control .............................................................................................................19 6.1.1 GUIDE LINE.............................................................................................................................. 19 6.1.2 BOILER FEED WATER ............................................................................................................... 20 6.1.3 BOILER WATER ........................................................................................................................ 21 6.2 Single Failure of Package Boiler..............................................................................................23 6.3 Single Failure of Steam Turbine Generator...........................................................................23 6.4 Load shedding...........................................................................................................................23

7. Normal Shutdown Procedure ..................................................................................................24 7.1 Deaerator...................................................................................................................................24 7.2 Package Boiler...........................................................................................................................24 7.3 Steam Turbine Generator System...........................................................................................24 7.4 Heat Recovery Steam Generator.............................................................................................24 7.5 Train Shutdown........................................................................................................................25

8. Emergency Shutdown Procedure ............................................................................................25 8.1 General ......................................................................................................................................25 8.2 Loss of Utilities..........................................................................................................................25

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8.2.1 POWER FAILURE ...................................................................................................................... 25 8.2.2 I NSTRUMENT AIR FAILURE ...................................................................................................... 25 8.2.3 COOLING WATER FAILURE ...................................................................................................... 25

9. Safety Procedure.......................................................................................................................25 9.1 General ......................................................................................................................................25 9.2 Emergency Fire Plan................................................................................................................26 9.3 Fire Fighting and Protective Equipment................................................................................27 9.4 Maintenance of Equipment and Housekeeping .....................................................................27 9.5 Repair Work .............................................................................................................................27 9.6 Withdrawal of Samples ............................................................................................................28 9.7 Safe Handling of Volatile and Toxic Materials ......................................................................28 9.8 Respiratory Protection.............................................................................................................28 9.9 Breathing Apparatus (B. A.)....................................................................................................29 9.9.1 NITROGEN................................................................................................................................ 29 9.9.2 CORROSIVE MATERIALS .......................................................................................................... 29 9.9.3 CHEMICALS .............................................................................................................................. 29

10. Isolation Procedure for Maintenance......................................................................................30 10.1 General ......................................................................................................................................30 10.2 Basic Procedures.......................................................................................................................30 10.2.1 TRAIN ISOLATION .................................................................................................................... 30 10.2.2 I NDIVIDUAL EQUIPMENT / SYSTEM ISOLATION........................................................................ 30

10.2.2.1 Horizontal and Vertical Pressure Vessels .......................................................................30 10.2.2.2 Pumps..............................................................................................................................31 10.2.2.3 Shell and Tube Heat Exchangers ....................................................................................32

11. Maintenance Procedure............................................................................................................32 11.1 General ......................................................................................................................................32 11.1.1 R OUTINE/FIRST LINE/ MAINTENANCE ...................................................................................... 33 11.1.2 BREAKDOWN MAINTENANCE .................................................................................................. 33 11.1.3 PLANNED PREVENTIVE MAINTENANCE ................................................................................... 33 11.1.4 PREDICTIVE/CONDITION BASED MONITORING ........................................................................ 33 11.1.5 TURNAROUND /I NSPECTION MAINTENANCE............................................................................ 33 11.2 Precautions prior to Maintenance...........................................................................................33 11.3 Preparation for Maintenance ..................................................................................................34 11.3.1 I NSTALLATION OF BLANK FLANGES OR SPADES ....................................................................... 34 11.4 Typical isolation method ..........................................................................................................34 11.4.1 VESSELS/DRUMS...................................................................................................................... 34 11.4.2 PUMPS ...................................................................................................................................... 34 11.4.3 SHELL AND TUBE TYPE HEAT EXCHANGERS........................................................................... 34 11.4.4 AIR FIN COOLERS ................................................................................................................ 3435 11.4.5 CLOSE OUT............................................................................................................................... 35

12. Attachment List.........................................................................................................................35

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1. INTRODUCTION

The purpose of Steam System (Unit 062) is to produce and distribute High Pressure steam (HP

steam), High Pressure Saturated steam (HP Sat. steam), Medium Pressure steam (MP steam) and LowPressure steam (LP steam) to the plant, and recovery the condensates.

Steam turbine generator (Unit 061) generates electric power to supply power for two trains operationincluding the support facilities including community area, administration area, upstream operation

support area, etc

2. BASIS OF DESIGN

2.1 General

Steam is available at four pressure levels, High Pressure (HP) that is based on the optimum steamturbine design pressure, Low Pressure (LP) that is based on Acid Gas Removal Unit requirements and

fractionation reboilers, Saturated High Pressure (HP SAT.) for stabilizer reboiler and MediumPressure (MP) for deethanizer reboiler.

High-pressure steam is produced from Heat Recovery Steam Generators (HRSG) and Package

Boilers. HRSG is installed in the exhaust duct of all Frame 7 gas turbines that drive refrigerantcompressors in the LNG train. Three package boilers are provided to supplement the HP steam fromHRSGs for generating electric power by steam turbine power generators.

Low-pressure steam is produced from back pressure steam turbines, flash drums at continuous blowdown from HRSGs and package boilers and a HP steam to LP steam letdown station.

HP SAT. steam is produced by desuperheating system from HP steam. MP steam is produced by aletdown station from HP steam to MP steam. HP SAT., MP and LP steam are used as the heating

medium for the LNG facilities and associated facilities.

Steam condensate is categorized as vacuum condensate, clean condensate and suspect condensate.

Suspect condensate is flashed to near atmospheric pressure. The suspect condensate is passedthrough a carbon filter followed by mixed bed polisher to remove possible contaminates prior to

deaeration. All steam condensate and make-up water are deaerated prior to being pumped to eachHRSG and package boiler.

Electric power is generated by Steam Turbine Generator Sets 061-GS-1001A/B/C. The steam tosteam turbines is supplied from high pressure steam system.

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2.2 Design Condition

2.2.1 Service Conditions

Operating Condition atSource Operating Condition atB.L. of User Unit Mechanical DesignCondition

Pressurekg/cm

2G

TemperatureoC

Pressurekg/cm

2G

TemperatureoC

Pressurekg/cm

2G

TemperatureoC

HighPressure

Steam

40.5 400 Min.40 400 44.7 425

Medium

Pressure

Steam

24.0 223 Min.24 221 27.5 250

Low

PressureSteam

3.5 148 Min.3.3 148 5.3 175

Boiler FeedWater

59.0 120 - - 78.0 148

2.2.2 Boiler Feed Water Qualities

Component Boiler Feed Water

Sodium mg/l as CaCO3 < 0.05

Chloride mg/l as CaCO3 < 0.05

Total Hardness mg/l as CaCO3 Nil

Total Iron mg/l Fe < 0.005

Silica mg/l SiO2 < 0.02

pH 8.5 – 9.5

Conductivity @25oC micro S/cm < 0.2

Total Suspended Solid mg/l < 0.1

Oil & Grease mg/l Nil

Total Copper mg/l < 0.01

2.2.3 Steam Consumers

High Pressure Steam (HP Steam)

- Steam Turbine Generator Set (061-GS-1001A/B/C)

- Steam Turbine Driver for 051/052-C-1001/1004 (051/052-CS-1001)

- Steam Turbine Driver for 051/052-C-1002/1003 (051/052-CS-1002)

High Pressure Saturated Steam (HP SAT. Steam)

- Condensate Stabilizer Reboiler (011-E-1001A/B)

Medium Pressure Steam (MP Steam)

- Deethanizer Reboiler (041/042-E-1005)

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Low Pressure Steam (LP Steam)

- Acid Gas Stripper Reboiler (021/022-E-1002A/B/C/D)

- Feed Gas Heater (021/022-E-1005)

- Defrost Gas Heater (031/032-E-1004)

- Scrub Column Reboiler (041/042-E-1004)

- Depropanizer Reboiler (041/042-E-1007)

- Debutanizer Reboiler (041/042-E-1009)

- Process Fuel Gas Heater (051/052-E-1201)

- Deaerator (062-D-1001A/B)

2.3 Special Equipment

Refer to each equipment data sheet for details (Attachment 3).

2.3.1 Deaerators (062-D-1001A/B)

Two deaerators are provided.

Number of deaerators: Two

Type: Spray trayCapacity: 51,5724kg/h for eachOperation pressure: 1.0kg/cm2G

Residual oxygen: less than 0.007 mg/l

Normally two deaerators are operating in parallel. One deaerator has a capacity to cover one trainoperation with common facility.

2.3.2 Package Boilers (062-F-1001A/B/C)

Three 50% package boilers to generate HP steam are provided.

Number of boilers: Three (Three for continuous operation)

Type: Water tube with economizerCapacity: 160ton/h (MCR) for eachSteam pressure: 40.5 kg/cm2G at boiler package Battery Limit

Steam temperature: 400 °CFuel: Fuel gas

HP steam is primary supplied by HRSGs (051/052-F-1101/1102) and Package Boilers (062-F-1001A/B/C) are designed to supplement HP steam Peak load operation at 110 % of MCR (maximumcontinuous rating) for 2 hours is considered on package boiler design.

For the steam system design, 3% of boiler blow down is considered. Normal blowdown ratio will beless than 1%.

The boilers operation load is controlled by HP steam header pressure controller.

2.3.3 Steam Turbine Generator Sets (061-GS-1001A/B/C)

Three 50% steam turbine generators are provided to supply power for two trains operation includingthe outside fence supporting facilities.

Number of the units: Three (Three for continuous operation)Type: Full condensing turbinePower generated: 35 MW / eachInlet Steam: HP steam

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Condensing pressure: 0.4 kg/cm2A

Condenser: A-frame air cooled surface condenser with condensate pump / ejector

2.3.4 Heat Recovery Steam Generators (051/052-F-1101/1102)

Heat recovery steam generators are provided to produce HP steam by recovering the heat of gas

turbines flue gas.

Number of the units: Four (dedicated to each Frame 7 Gas Turbine)Type: Water tube with economizer

Steam pressure: 40.5 kg/cm2G at package B/LSteam temperature: 400 °CSteam production rate: 132 t/h each

2.4 Process Description

2.4.1 Steam Generation

HP steam is produced at 40 kg/cm2g and 400 °C at Heat Recovery Steam Generator (HRSG)

(051/052-F-1101/1102) installed at the exhaust stack of Gas Turbine driver of C3/HP MRcompressors (051/052-CG-1001) and LP MR/MP MR compressors (051/052-CG-1002), and

supplemented from a Package Boilers (062-F-1001A/B/C).

HP Sat. steam is produced by injecting the boiler feed water to decrease the temperature to the almost

saturated condition of 257°C at 40 kg/cm2g by using temperature controller (011-TIC-1306).

MP steam (24 kg/cm2g, 223 °C) is produced from medium pressure letdown station (pressure

reducing and desuperheating). In this letdown station, the high pressure steam is reduced to 24

kg/cm2g, then the boiler feed water is injected to decrease the temperature to the almost saturatedcondition of 223 °C by the pressure controller (091/092-PIC-1001) and temperature controller

(091/092-TIC-1471) respectively.

LP steam (3.5 kg/cm2g, 148 °C) is produced from steam turbine starter / helper of refrigerant

compressors (051/052-CS-1001 and 051/052-CS-1002) in process trains. The condition of low pressure steam from the turbines is slightly superheated therefore it requires some boiler feed water

injection to desuperheat the steam at temperature of 148 °C. It is done by temperature controllers(091/092-TIC-1314 and 1351). LP letdown station with boiler feed water injection system is also

provided to produce the LP steam from HP steam.

The steam losses in the system will be replaced by make-up water produced from seawater by

desalination, which is mixed with the steam condensate before treatment in the demineralization package.

2.4.2 Steam Distribution

Steam is distributed through the steam headers to the steam consumers. The steam header fromutility area to the process train basically is designed for 2 (two) train capacity.

HP steam is mainly sent to drive Steam Turbine Starter/Helper of refrigerant compressors

(051/052-CS-1001 and 051/052-CS-1002), which provide additional driver power to the compressorstring driven by Frame-7 gas turbines in process train. Since the turbines are back pressure types, theoutlet stream from the turbines is low pressure steam. Another main user of HP steam is Steam

Turbine Generator Set (061-GS-1001A/B/C) in utility area.

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HP sat. steam is sent to Condensate Stabilizer Reboiler (011-E-1001) in Condensate Stabilization

Unit (Unit011).

MP steam produced from letdown station is sent to Deethanizer Reboiler (041/042-E-1005) in

process train through the MP steam header.

LP steam produced from the starter/helper turbines is distributed through the LP steam header to AcidGas Stripper Reboiler (021/022-E-1002A~D), Feed Gas heater (021/022-E-1005), Scrub Column

Reboiler (041/042-E-1004), Depropanizer Reboiler (041/042-E-1007), Debutanizer Reboiler(041/042-E-1009), Process HP Fuel Gas Heater (051/052-E-1201) and Defrost Gas Heater(031/032-E-1004, during startup only) in process train. The LP steam user in utility area is Deaerator

(062-D-1001A/B). However, during startup, the most of the LP steam required for Acid Gas Stripper

Reboiler is produced from letdown system located in utility area. Therefore the LP steam header isalso provided in utility area and is designed considering the start-up and emergency conditions.

The MP steam header is controlled by MP letdown station, and LP steam header is controlled by LPletdown station, LP Steam Control Condenser and Starter/Helper Steam Turbine governors also.

The HP steam header is controlled by master boiler combustion control.

2.4.3 Steam Condensate Recovery and Treatment

Clean steam condensates in process area, mainly Acid Gas Stripper Reboilers (021/022/E-1002A~D),that have no possibility to be contaminated are directly collected at Steam Condensate Flash Drum

(051/052-D-1103). The flashed vapor is condensed in Steam Condensate Flash Drum VentCondenser (051/052-E-1103), and then the steam condensate is returned back to the flash drum. The

steam condensate from 051/052-D-1103 is pumped-out by Condensate Return Pump(051/052-P-1101A/B) from process area to Deaerator (062-D-1001A/B) in utility area directly.

The exhaust steam from Steam Turbine Generator Sets (061-GS-1001A/B/C) is condensed by Air

Cooled Surface Condenser (061-E-1001A/B/C) and collected in Condensate Recovery Drum(061-D-1001A/B/C) as vacuum condensate. The vacuum condensate is pumped-out by CondensatePump (061-P-1001A/B/C) and returned directly to Deaerators (062-D-1001A/B) with clean steam

condensates.

Suspect steam condensates in process area that have a possibility to be contaminated by hydrocarbon

are collected in the Condensate Flash Drum (051/052-D-1104) in process area, which is operated atalmost atmospheric pressure. The flashed vapor is condensed in Condensate Flash Drum Vent

Condenser (051/052-E-1105), and then the steam condensate is returned back to the flash drum. Thesteam condensate from 051/052-D-1104 is pumped-out by Condensate Return Pump

(051/052-P-1102A/B) and cooled in Steam Condensate Cooler (051/052-E-1107) from around

100 °C to 50 °C in order to get the best performance of demineralization package.

The suspect steam condensate is sent to the Activated Carbon Filter (064-V-1006) for removal of any

residual hydrocarbons. The treated condensate plus the desalinated water make-up are fed to theMixed Bed Polisher (064-V-1003) in demineralization unit for further treatment, and finally fed to

Deaerators (062-D-1001A/B).

Deaerator will remove the gaseous dissolved in the steam condensate. Deaerator will be operated at1.0 kg/cm2g and 120 °C. Low pressure steam is used as the medium to removes the gaseous indeaerator upper section. Free gaseous steam condensate (boiler feed water) is collected in the drum

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of lower section of the Deaerator, which is ready to be pumped-out to HRSGs and Packaged Boilers.

Pressure in the Deaerator is controlled by pressure controller, which is installed at LP steam inlet.

The boiler feed water from Deaerators (062-D-1001A/B) is provided with chemical injection

packages (051/052-V-1003, 062-V-1001, 062-V-1002 and 062-V-1003) in order to comply withspecified boiler feed water quality. For this HRSG and Packaged Boiler operation range, the suitable

chemical injection is Phosphate, Oxygen Scavenger, and Neutralization Amine. Oxygen Scavengerand Neutralization Amine will be injected at the Deaerator and Phosphate will be injected at the

HRSGs and Package Boilers.

Boiler feed water is finally fed to HRSGs and Packaged Boilers by Boiler Feed Water Pump(062-P-1001A/B/C).

2.4.4 Steam Turbine Generator System

HP steam is introduced to the Steam Turbine Generator Sets (061-GS-1001A/B/C) to generate

electric power. The exhausted steam from the turbine is fully condensed by Air Cooled SurfaceCondenser (061-E-1001A/B/C) and the steam condensate flows into Condensate Recovered Drum(061-D-1001A/B/C) by gravity. The steam condensate is transferred to Deaerator (062-D-1001A/B)

by Condensate Pump (061-P-1001A/B/C) via Ejector Condenser (061-E-1011A/B/). Vacuumcreating system and drain recovery system from the exhausted line are also provided.

3. PROCESS CONTROLS

3.1 Boiler Feed Water

Demineralized water in Demineralized Water Tank (064-TK-1003) is pumped up by demineralized a

water pump (064-P-1003A/B) to Deaerator (064-D-1001A/B).

The Deaerators receive recovered condensate plus demineralized water required for make up oflosses for steam stripping, blowdown and so on. These condensates and demineralized water are

received to top of heater shell of the Deaerator. There is a level controller on each Deaerator,062-LIC-1111/1112, which keeps normal level in the Deaerators. The Deaerators will hydraulically balance to equalize levels between the two Deaerators.

The water is heated up to the saturated temperature in the Deaerators. There is a pressure controller on

each Deaerator, 062-PIC-1211/1212, which keeps normal operating pressure of 1.0kg/cm2g in the

Deaerators by introducing LP steam to the Deaerators.

Boiler feed water from Deaerators is pumped up by two Boiler Feed Water Pumps(062-P-1001A/B/C) to Package Boilers (062-F-1001A/B/C) and Heat Recovery Steam Generator

(051/052-F-1101/1102) in on-site units.

Two pumps are normally running and the other is stand-by. If the pressure in the discharge lineof the running pumps becomes lower than low set point, the stand-by pump will start automatically to

ensure continued supply of enough boiler feed water.

Oxygen Scavenger is injected in downstream of the deaerators to remove the trace of oxygen

dissolved in the Boiler Feed Water. This is to remove the remaining 0.007 mg/litter dissolved

oxygen from the Boiler Feed Water.Two reciprocating pumps (including one spare) with a rated capacity of 12.0 liter/h are

provided to serve the deaerators.

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Neutralizing Amine is injected into the deaerator to adjust the pH of the Boiler Feed Water.

The injection system is designed so that pH in recovered condensate will be around 8.5 to 9.5.

Two reciprocating pumps (including one spare) with a rated capacity of 12.0 liter/h are

provided to serve the deaerators.

Phosphate is injected into the Package Boilers and HRSGs in order to avoid scaling and keepappropriate pH value in the boiler water.

Injection package is designed so that PO4 concentration in boiler water is 10ppm.

Four reciprocating pumps (including one spare) with a rated capacity of 12 liter/h are provided

to serve the three Package Boilers. And three reciprocating pumps (including one spare) with

a rated capacity of 12 liter/h are provided to serve the two HRSGs in each LNG train.

Injection quantity for each chemical is defined by monitoring analyzer data and sampling

results, and adjusted by manually setting the stroke of the reciprocating pumps of the injection

package. The pump flow rate is confirmed by the calibration pot on suction line of each pump.

Guidelines of the Chemical Injections for water quality control are described in Section 6.1.

Neutralized amine and oxygen scavenger are injected to downstream of the Deaerators. Oxygenscavenger is injected to remove trace of oxygen dissolved in the boiler feed water. And neutralized

amine is injected to adjust the pH of the boiler feed water and that of the steam condensate.

3.2 High Pressure Steam

The HP steam is normally supplied by the HRSGs (051/052-F-1101/1102) and the Package Boilers

(062-F-1001A/B/C). These HRSG and Package Boilers are controlled by DCS.

Three package boilers have HP steam generation capacity of 50% x 3. However, all three

boilers shall be operated normally.

Under normal plant operation, the HP steam header pressure at 40 kg/cm2g is controlled by the

pressure controller (060-PIC-1201), which adjusts or controls the steam production from PackageBoilers (062-F-1001A/B/C) through its burner management system, satisfying the steam demand for

power generation as well. Figure-1 is a Schematic of Unit 062 Steam Complex Control System.

When the Acid Gas Removal Unit (AGRU) is tripped, the demand for LP steam decreases and LP

steam pressure increases. And the HP steam pressure would increase, because the refrigerantcompressors will change to recycle operation mode due to stopping feed gas and the demand of HP

steam to Steam Turbines will reduce based on decreasing the required power.

At this time, the pressure controller (060-PIC-1201) will control the HP steam header pressure by burner management system of Package Boilers (062-F-1001A/B/C).

When the boiler operation will be reached at the minimum controllable duty (25% of MCR), furtherreduction of the boiler duty will be impossible.

At this condition, the 060-PIC-1202A will ask the 060-PV-1207A/B/C to open through thehi-selector, which overrides the 060-PIC-1207, to control the HP steam header pressure by disposingthe HP steam to LP steam header.

The LP steam header pressure will increase then 060-PIC-1206A/B will ask the 091/092-PV-1206A

and 060-PV-1206B to open in order to control the LP steam header pressure as explained in the LPsteam control system below.

The 060-PIC-1202B is provided as a final pressure controller if the pressure continues to increase due

to such upset conditions and dump the HP steam to the atmosphere through 060-PV-1202B.

The 060-PIC-1203 is provided as HP steam header low pressure protection.

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At low pressure condition, the 060-PIC-1203 through the low selector, which are overridden by

060-PIC-1205, will ask Steam Turbine Starter/Helper (051/052-CS-1001/1002) governor to closethrough the high-selector, which overrides the remaining power controller of Steam Turbines, to

control the HP steam header pressure at or above its minimum pressure by reducing the HP steam tosteam turbine drivers

HP Steam Header Pressure Main Control

Tag No. Set Point Control

060-PIC-1201 40.0 kg/cm2G Package Boiler (062-F-1001A/B/C) load control

060-PIC-1202A 41.0 kg/cm2G Open HP-LP Letdown valve (060-PV-1207A/B/C)

060-PIC-1202B 42.8 kg/cm2G Open HP steam release valve (060-PV-1202B)

060-PIC-1203 39.0 kg/cm2G 051/052-CS-1001/1002 governor control

3.3 Low Pressure Steam

Since the refrigerant compressors speed are controlled by the main GT drivers, the Steam Turbine

Starter/Helper (051/052-CS-1001 and 051/052-CS-1002) governors could be utilized to control theLP steam header pressure. The governor pressure controller (060-PIC-1205) through thelow-selector, which is overridden by 060-PIC-1203, will maintain the LP Steam Header pressure at

3.5 kg/cm2g under normal plant operation.

However, there is possibility that LP steam header pressure cannot be maintained at 3.5 kg/cm2g by

control of the steam turbine governors, due to the trips of LP steam users, trips of steam turbinehelper, etc. If the LP steam header pressure continues to decrease, the HP letdown valve

060-PV-1207A/B/C shall control LP steam header at pressure setting of 3.3 kg/cm

2

g by introducingthe HP steam.

When Gas Turbine temperature control becomes active (exhaust temperature increasing) during the

operation that LP steam header pressure is controlled by governors pressure controller(060-PIC-1205), Steam Turbine stops to control LP steam header pressure and starts to act as Helper

to produce power to help Gas Turbine.

In that case, LP steam header pressure will be controlled by dumping to LP Steam Control Condenser(051/052-E-1101). The condenser fans will start with low speed automatically by opening signal to091/092-PV-1206A. or When high temperature of 091/092-TI-2710 on the condenser vent line is

detected, the fan motor speed will be changed to high speed. The condenser fans will stop

automatically in case of closing 091/092-PV-1206A.

If the LP steam header pressure continues to increase, the pressure control valve of 060-PV-1206B

will open to dump the LP steam to atmosphere at 4.5 kg/cm2g.

From the above explanation, 2 controllers, i.e. 060-PIC-1202A and 060-PIC-1207, will use the

060-PV-1207A/B/C. Hi-selector 060-PY-1207 will select which controller overrides other

controller. In the 060-PY-1207, the higher opening request will override the lower opening request.

Continuous nitrogen purge is required for the vent line of 051/052-E-1101 to prevent air ingress into

steam system. A globe valve facing to Flow Gauge (091-FG-9031) shall be adjusted to flow the

required nitrogen of minimum 2.6Nm3/h.

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LP Steam Header Pressure Main Control

Tag No. Set Point Control

060-PIC-1205 3.5 kg/cm2G 051/052-CS-1001/1002 governor control

060-PIC-1206A 3.5 kg/cm2G Open LP steam dump valve (091/092-PV-1206A)Start LP Steam Control Condenser (051/052-E-1101)

with low steed

060-PIC-1206A <3.5 kg/cm2G Stop LP Steam Control Condenser (051/052-E-1101)

051/052-TI-2715 100oC Change motor speed of LP Steam Control Condenser

(051/052-E-1101) to high speed

060-PIC-1206B 4.5 kg/cm2G Open LP steam release valve (060-PV-1206B)

060-PIC-1207 3.3 kg/cm2G Open HP-LP Letdown valve (060-PV-1207A/B/C)

3.4 Blowdown System for Boilers

A continuous blowdown line and an intermittent blowdown line are provided for the package boilers.

Continuous blowdown is flow controlled normally to around 1% of the generated HP steam and up to

a maximum of 3%.

Continuous blowdown is sent to Continuous Blow Down Drum (062-D-1002A/B/C) and flashed at3.5kg/cm

2g for LP steam recovery. Post flashed condensate and intermittent blowdown are sent to

ATM Blowdown Drum (062-D-1003A/B/C) to be flashed at atmosphere. Flashed liquid is drained tochemical sewer through Boiler Blowdown Cooler (062-E-1002A/B/C).

Intermittent blowdown is done manually from bottom of steam drums, to maintain the boiler waterfree from sediments.

Intermittent blowdown is sent to ATM Blowdown Drum (062-D-1003A/B/C) to be flashed at

atmosphere. Flashed liquid is mixed with continuous blowdown and drained to chemical sewerthrough Boiler Blowdown Cooler (062-E-1002A/B/C).

3.5 Clean Steam Condensate

Hot clean condensates are collected in Condensate Flash Drum (051/052-D-1103) located in each

train. This drum is provided with a Condensate Flash Drum Vent Condenser (051/052-E-1103) tominimize loss of steam. The condensate liquid is sent to the Deaerators by a Condensate Return Pump

(051/052-P-1101A/B). 051/052-LIC-1113 will control the drum level to keep constant.

One pump of the Condensate Return Pump is running and the other is stand-by. When liquid

level of the drum is increased to high liquid level by running pump failure stop etc, stand-by pumpwill start to run automatically.

Continuous nitrogen purge is required for the vent line of 051/052-E-1103 to prevent air ingress intosteam system. A globe valve facing to Flow Gauge (091-FG-9032) shall be adjusted to flow the

required nitrogen of minimum 5.8Nm3/h.

3.6 Suspect Steam CondensateSuspect steam condensates are collected in Condensate Flash Drum (051/052-D-1104) located ineach train. This drum is provided with a Condensate Flash Drum Vent Condenser (051/052-E-1105)

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to minimize loss of steam. The condensate liquid is sent to the demineralized water system through

LP Steam Condensate Cooler (051/052-E-1107) located in utility area by a Condensate Return Pump(051/052-P-1102A/B). 051/052-LIC-1171 will control the drum level to keep constant by

051/052-LV-1171 at outlet of 051/052-E-1107.

One pump of the Condensate Return Pump is running and the other is stand-by. When liquidlevel of the drum is increased to high liquid level by running pump failure stop etc, stand-by pumpwill start to run automatically.

Continuous nitrogen purge is required for the vent line of 051/052-E-1105 to prevent air ingress into

steam system. A globe valve facing to Flow Gauge (091-FG-9033) shall be adjusted to flow therequired nitrogen of minimum 2.0Nm

3/h.

3.7 Steam Turbine Generator Sets

The normal operation of the Main Steam Turbine Generator is controlled from Main Control Room.

Full generator control capabilities are provided in a local generator control room which is notcontinuously manned. The generator control room is primary used to start up, synchronize, andshutdown the generators. A sequence of events recorder is also provided in the local generator control

panel. Data from the turbine controls in the generator control room can be serially linked to the DCS.All substations have hard wiring connection or serial links to the DCS for status, alarm and data

logging.

For detailed control philosophy of the Steam Turbine Generator Set, 061-GS-1001A/B/C, refer to the

vendor operation manual (061-VDR-MES-9801).

Motors of Air Cooled Surface Condenser (061-E-1001A/B/C) are on-off controlled by the exhaustedsteam pressure (062-PIC-1232A/B/C) at outlet of the steam turbine. Operating fan number is

changed by the high and low pressure signal.

Steam drain collected in a drain pot that is installed on the exhausted steam line is transferred toCondensate Recovery Drum (061-D-1001A/B/C) by level controlled drain recovery system. The

drain pot liquid level (062-LI-2830AB/BB/CB) start and stop the drain recovery system by

open/close motive steam condensate introducing valve. One drain recovery ejector is operated

and the other is spare.

When the liquid level reaches to high liquid level, one drain recovery ejector starts to drain out

accumulated liquid in the drain pot. And when the liquid level reaches to low liquid level, the

ejector is stopped.

If the drain level reaches high-high liquid level, two out of three transmitters initiate a signal to tripthe steam turbine generator set.

Steam condensate stored in the Condensate Recovered Drum (061-D-1001A/B/C) is level

controlled and directly sent to Deaerator (062-D-1001A/B) by Condensate Pump

(061-P-1001A/B/C). If the condensate level reaches low-low liquid level, the Condensate Pump will

be stopped to prevent the pump damage.

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F i g u r e - 1 S c h e m a t i c o f U n i

t 0 6 2 S t e a m C o n t r o l S y s t e m

B O I L E R

0 6 2 - F - 1 0 0 1 A

B O I L E R

0 6 2 - F - 1 0 0 1 B

H R S G

0 5 1 - F - 1 1 0 1

H R S G

0 5 1 - F - 1 1 0 2

G

G

G

0 6 1 - G S - 1 0 0 1 A

0 6 1 - G S - 1 0 0 1 B

0 6 1 - G S - 1 0 0 1 C

0 5 1 - C

G - 1 0 0 2

0 5 1 - C G - 1 0 0 1

T R A I N 1

T R A I N 2

P Y 1 2 0 7

P C 1 2 0 7

P C 1 2 0 3

H P S T E A M

H E A D E R

L P S T E A

M H E A D E R

P C 1 2 0 1

P C

1 2 0 2 B

P C 1 2

0 5

0 5 1 - E - 1 1 0 1

P C

1 2 0 6 A

A G R

T O P R O C E S S

U N I T R E B O I L E R S

H I G H

S E L E C T O R

S E T :

3 . 3 k g / c m 2 g

S E T :

3 . 5 k g / c m 2 g

S E

T :

3 . 7

k g / c m 2 g

S E T :

4 0 k g / c m 2 g

S E T :

4 1 k g / c m 2 g

S E T :

3 9 k g / c m 2 g

0 6 0 - P V -

1 2 0 7 A / B / C

0 6 0 - P V - 1 2

0 2 B

0 9 1 - P V - 1 2 0 6 A

S C

S P E E D

C O N T R O L L E R

0 6 0 - P

V - 1 2 0 6 B

P

Y

1 2

0 5

T O V E N T

T O V E N T

T O P R O C E S S

U N I T R E B O I L E R S

O P E

N A T

4 . 5 k g / c m 2 g

O P E N A T

4 2 . 8 k g / c m 2

g

B O I L E R

0 6 2 - F - 1 0 0 1 C

L O W

S E L E C T O R P

C 1 2 0 6 B

P C

1 2 0 2 A

P Y

P Y

H I G H

S E L E C T O R

H I G H

S E L E C T O R

S C

P O W E R

C O N T R O L L

E R

S C

P O W E R

C O N T R O L L E R

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4. PREPARATION FOR INITIAL START-UP

Refer to Commissioning Procedure (62-PRC-OP-1001).

5. NORMAL START-UP PROCEDURE

5.1 General

Check points are as follows:

(1) All equipment including instrument, etc. is ready for use.

(2) Demineralized water, instrument air and emergency electric power are available.

(3) All blinds or spectacle blinds except for Battery Limit have been placed in operation position.

(4) Ensure all vents, drains, and sample connections are closed.

(5) All safety equipment must be properly installed on site, calibrated and operable.

(6) Prepare required chemicals in each chemical vessel.

After all the above checkpoints are checked, start up the Steam System.

Section 5.2 to 5.11 should be followed in order to start up the Air/Nitrogen Steam System.

5.2 Start up of Boiler Feed Water System

(1) Confirm Deaerator (062-V-1001A/B) level controller (062-LIC-1111/1112) is inauto mode.

(2) Demineralized water is introduced in Deaerators (062-V-1001A/B) through

062-LV-1111/1112.

(3) After built up the liquid level in 062-D-1001A/B, one of Boiler Feed Water Pump(062-P-1001A/ or B/C) is started locally. (062-P-1001C is not connected to

emergency power supply.)

(4) Gradually open the pump discharge valve (manually).

(5) Set stand-by pump to auto mode.

(6)(5) Oxygen Scavenger Injection Package (062-V-1002) and Neutralizing Amine InjectionPackage (062-V-1003) are started. As LP steam is not available in this period, Oxygenscavenger feed shall be increased to compensate for the lack of complete deaeration

because water is not deaerated. Therefore the oxygen scavenger feed rate is quite

larger than that at normal. Refer to Section 6.1 Water Quality Control.

(Oxygen scavenger may include stabilized agent to prevent chemical reaction in tank. Nitrogen purge for 062-V-1002 will be required only to use un-stabilized chemical.

Chemical supplier’s advice is required.)

(6) When enough users are available, second pump shall be started locally.

(7) Set stand by pump to auto mode locally.

5.3 Start up of Package Boiler (062-F-1001A/B/C)

(1) Introduce cooling water to Boiler Blowdown Cooler (062-E-1002A/B/C).

(2) Start one Package Boiler (062-F-1001A or B). (062-F-1001C is not connected to

emergency power supply.) It is recommend that boiler start-up should only be

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undertaken locally and not DCS. For the start up procedure of the Package Boilers,

refer to the vendor’ instruction “Operation & Maintenance Manual”(062-VDR-MCI-1800).

(3) Phosphate Injection Package (062-V-1001) shall be started accordingly. Refer to

Section 6.1 Water Quality Control. Each Package Boiler has dedicated phosphateinjection pump.

(4) Confirm boiler blowdown temperature is under 50oC at outlet of the boiler blowdown

cooler.

(5) After starting the Steam Turbine Generator Sets (062-GS-1001A/B/C) and steam

condensate system, the recovered steam condensate may have rust which wasgenerated in steam condensate piping during shutdown period. Continuous boiler blowdown ratio should be increased up to 3% and intermittent blowdown operation

should be done more frequently than usual until boiler water quality meets control

target described in Section 6.1.1.

5.4 Introduce HP Steam to HP Steam Header

(1) Confirm all low point drains on HP steam header are open.

(2) Confirm HP steam releasing valve 060-PV-1202B controller (060-PIC-1202B) is in

auto mode. Also confirm HP steam – LP steam letdown controller (060-PIC-1202A) isin manual mode and closed position.

(3) When on-spec HP steam is produced from the package boiler, the HP steam isintroduced to HP steam header gradually and pressurizes the header. The boiler

should, is will be, operated at minimum load. The steam will be released toatmosphere through 060-PV-1202B.

(4) Warm up HP steam header and release steam condensate from low point drains.

Caution

Hot water with steam will be exhausted from the low point drains. Operators

shall pay attention to prevent suffering steam and splash.

(5) Close all low point drains after finishing condensate draining out.

5.5 Letdown HP Steam to LP Steam

(1) Confirm all low point drains on LP steam header are open. And also confirm isolation

valves for LP Steam Control Condenser (051/052-E-1101) located at upstream of091/092-PV-1206A are closed.

(2) Confirm LP steam releasing valve 060-PV-1202B controller (060-PIC-12062B) is inauto mode.

(3) Confirm LP steam temperature controller (060-TIC-1303) at downstream of

HP-LP desuperheater is in manual mode and closed position.

(4) Gradually open one of HP-LP letdown control valves 060-PV-1207A by its handwheel and adjust the flow temperature 060-TIC-1303 under 175

oC by opening boiler

feed water injection control valve (060-TV-1303A/B) using its hand wheelbypass

globe valve. The steam will be released to atmosphere through 060-PV-1206B.

Warm up LP steam header and release steam condensate from low point drains. Caution

Hot water with steam will be exhausted from the low point drains. Operatorsshall pay attention to prevent suffering steam and splash.


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5.6 Introduce LP Steam to Deaerators (062-D-1001A/B)

(1) For the start up procedure of the Deaerators, refer to the vendor’s instruction

“Installation, Operation and Maintenance Manual” (062-VDR-TCI-1801).

(2) Adjust the oxygen scavenger injection rate. Refer to Section 6.1.

5.7 Start Steam Turbine Generator Set (061-GS-1001A/B/C)

(1) Confirm blind flanges at HP steam isolation are open position for one of Steam

Turbine Generator Set (061-GS-1001A or B). (061-GS-1001C is not connected to

emergency power supply.)

(2) Fill demineralized water into Condensate Recovery Drum (061-D-1001A/B/C) up tonormal liquid level.

(3) Confirm stop valve of the steam turbine is closed and all low point drains on main

steam line are open.(4) Equalize HP steam line to open 3” globe valve and release steam condensate from low

point drains.

Caution


shall pay attention to prevent suffering steam and splash.


(6) Open 18” block valve on main steam line.

(7) Open 3” gate valve and gradually open 3” globe valve on vent line with silencer

(062-Y-1001A/B/C) at main steam inlet line to warm up of main steam line.

(8) Confirm Condensate Recovery Drum (061-D-1001A/B/C) level controller

(062-LIC-1227A/B/C) and STG Condensate Recovery Pump (061-P-1001A/B/C)

minimum flow controller (062-FIC-1032A/B/C) are in auto mode.

(9) Start STG Condensate Recovery Pump (061-P-1001A/B/C) using minimum flow line.

(10) Start Air Cooled Surface Condenser system (061-E-1001A/B/C) and vacuum system.For the start up procedure of the surface condenser and vacuum system, refer to thevendor’s instruction “Instruction for Erection, Starting-up and Operating”

(V-2153-102-A-801).

(11) Confirm STG inlet HP steam temperature 062-TI-1326A/B/C indicate above 300oC

and close block valve on venting line.

(12) Start Steam Turbine Generator. For the start up procedure of the steam turbinegenerator, refer to the vendor’s instruction “Operation and Maintenance Manual”

(061-VDR-MES-9801).

5.8 Steam Condensate System

(1) Start nitrogen injection to LP Steam Control Condenser (051/052-E-1101) vent pipeand Condensate Flash Drum Vent Condenser (051/052-E-1103) vent pipe. N2

injection rate should be referred to Section 3.3 and 3.5.

(2) Confirm Condensate Flash Drum (051/052-D-1103) level controller

(051/052-LIC-1113) is in auto mode.

(3) Gradually open isolation valves for LP Steam Control Condenser (051/052-E-1101) located at upstream of LP steam dumping control valve (091/092-PV-1206A). LP

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steam will be introduced to the 051/052-E-1101 through restriction orifice

091/092-FO-9011.

(4) Gradually open LP steam dumping control valve (091/092-PV-1206A) by its handwheel.

(5) Start LP Steam Control Condenser.

(6) When liquid level is built up above normal liquid level in the Condensate Flash Drum(051/052-D-1103), one of Condensate Return Pump (051/052-P-1101A/B) is started

locally.


(8) When the drum water level is stable at normal liquid level, switch over HP steam

pressure controller (060-PIC-1201), LP steam temperature controller

(060-TIC-1303), HP steam low pressure controller (060-PIC-1203) and LP steam

high pressure controller (060-PIC-1206A) to auto control mode, and close boiler

feed water injection control valve (060-TV-1303A/B) bypass valve.

5.9 Letdown HP Steam to MP Steam

(1) Confirm Deethanizer Reboiler (041/042-E-1005) is ready for start-up.

(2) Confirm all low point drains on MP steam header are open.

(3) Confirm MP steam pressure controller (091/092-PIC-1001) and MP steam

temperature controller (091/092-TIC-1471) are in manual mode and closed

position.

(4) Slightly open HP-MP letdown control valve (091/092-PV-1001) by its hand wheeland adjust the flow temperature 091/092-TIC-1471 under 250

oC by opening boiler

feed water injection control valve (091/092-TV-1471) bypass globe valveusing its

hand wheel. Be careful not to exceed MP steam header pressure of 24kg/cm2

G, that isPSV set pressure on MP steam header.

(5) Warm up MP steam header and release steam condensate from low point drains.

Caution


shall pay attention to prevent suffering the steam and splash.


(7) Switch over MP steam temperature controller (091/092-TIC-1471) and MP steam

pressure controller (091/092-PIC-1001) to auto control mode, and close boiler feed

water injection control valve (091-TV-1471) bypass valve.

Operating manual for Unit 041/042 shall also be referred to start up MP steam system

because MP steam is used only in Unit 041/042.

5.10 Start up of Heat Recovery Steam Generator (051/052-F-1101/1102)

(1) Introduce cooling water to HRSG Blowdown Cooler (051/052-E-1104/1106).

(2) For the start up procedure of Heat Recovery Steam Generator, refer to the vendor'sinstruction “Operation & Maintenance Manual” (051-VDR-ALP-1800).

(3) Phosphate injection package (051/052-V-1003) shall be started. Refer to Section 6.1.

(4) Confirm HRSG blowdown temperature is under 50oC at outlet of the HRSG

blowdown cooler.

(5) When on-spec HP steam is produced from the HRSG and the Gas Turbine operation

becomes stable, the HP steam can be introduced to HP steam header gradually. Under

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14 ton/minute is preferable HP steam introducing ratio to the header to prevent sudden

load decrease of three Package Boiler loads.

5.11 Start up of the Suspect Condensate Recovery System

(1) Confirm Condensate Flash Drum (051/052-D-1104) level controller

(051/052-LIC-1171) and Activated Carbon Filer Package (064-V-1006) make-up

water flow controller (064-FIC-5501) are in auto mode.

(2) Start Activated Carbon Filter Package (064-V-1006). For the start up procedure of the

064-V-1006, refer to Operation Manual for Water System (62-IOM-PS-1201) and thedemineralization package vendor operation manual (900064-VDR-SAL-1800/1820).

(3) Start nitrogen injection to Condensate Flash Drum Vent Condenser, 051/052-E-1105vent pipe. N2 injection rate should be referred to Section 3.6.

(4) Start Condensate Flash Drum Vent Condenser (051/052-E-1105) locally.

(5) Start LP Steam Condensate Cooler (051/052-E-1107) locally.

(6) Receive steam condensate into Condensate Flash Drum (051/052-D-1104).

(7) When liquid level is built up above normal liquid level in the drum, one of Condensate

Return Pump (051/052-P-1102A/B) is started locally.


(9) Set stand-by pump to auto mode locally.

6. NORMAL OPERATION

6.1 Water Quality Control

The unit is normally controlled automatically but requires operator to monitor process

conditions.

6.1.1 Guide Line

Guide line for quality control of Boiler Feed Water (i.e. Deaerator outlet water) and Boiler Water forcirculation boilers are tabulated below. “Bolded” value will be adopted for Deaerator

(062-V-1001A/B), Package Boilers (062-F-1001A/B/C) and Heat Recovery Steam Generators(051/052-F-1101/1102).

Maximum OperatingPressure (kgf/cm

2G)

9 max.

(LP Steam)

over 19 up toand incl. 29

(MP Steam)

over 29 up to

and incl. 49

(HP Steam)

pH (at 25oC) 7 to 9 8.0 to 9.5 8.0 to 9.5

Total hardness(mg CaCO3 /lit.)

1 max. Nil. Nil.

Oil (mg/lit.) It is preferable

keep low

It is preferable

keep lowIt is preferable

keep low

Dissolved oxygen(mg O/lit.)

It is preferablekeep low

0.1 max. 0.03 max.

Iron (mg Fe/lit.) 0.3 max. 0.1 max. 0.1 max.

Boiler

Feed

Water

Copper (mg Cu/lit.) - - 0.05 max. pH (at 25

oC) 11.0 to 11.8 9.4 to 10.5 9.4 to 10.5Boiler

Water Total Solids (mg/lit.) 2500 max. - -

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Conductivity

(micro-S/cm, at 25oC)

4000 max. 800 max. 600 max.

Chloride (mg Cl /lit.) 400 max. 100 max. 80 max.

Phosphate(mg PO4

3-/lit)

20 to 40 5 to 15 5 to 15

Silica (mg SiO2 /lit.) - 50 max. 20 max.

Remarks ;

1) Based on JIS B 8223-1989

2) Concentration unit mg/litter shall be equal to g/ton. (litter is based on water condition at ambient

temperature.)

Chemical injection quantities are determined by monitoring analyzer and sampling results, andadjusted by manually setting the stroke of the metering pumps of the chemical injection packages.

6.1.2 Boiler Feed Water

A) Oxygen Scavenger

Non hydrazine chemical is used for this plant to treat the boiler feed water.

Component of the chemical is varied by the chemical supplier.

Chemical supplier’s advice and instruction shall be taken to decide injection rate of the oxygen

scavenger.

(1) Normal Operation

Operation with deaerators, (i.e. normal operation), the injection rate is calculated based on oxygen

content (0.007 mg/lit. =0.005 cc/lit.) at the deaerator outlet.

(2) Deaerator cold Operation

Deaerator will be in cold operation at initial operation until LP steam becomes available. At this period, oxygen scavenger injection is increased since oxygen in feed water is not deaerated.

The concentration of dissolved oxygen in the feed water is measured, or the amount of saturated

dissolved oxygen is determined from the temperature of the feed water at the open section.

Relation between temperature and concentration of dissolved oxygen is shown below;

Feed Water Temp. (oC) 10 20 30 40 50

Dissolved Oxygen (mg O/lit.) 11.1 9.2 7.9 6.4 5.2

B) Neutralization Amine Injection

Chemical supplier’s advice and instruction shall be taken to decide injection rate of the NeutralizedAmine.

Cyclohexyl amine is assumed as Neutralization Amine to discuss here.

The cyclohexyl amine is injected to adjust the pH and to remove residual CO2 in boiler feed water.However, as deaerated boiler water is used, CO2 content is considered zero.

Relation between cyclohexyl amine injection and pH (at zero CO2) is as follows

Target pH 8 8.5 9 9.5

Cyclohexyl amine injection (mg/ lit.= g/ton -feed water) 0.1 0.3 1.0 3.0

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Example for Normal Operation;

Boiler make up water; approx. 50 ton/hr

Target pH = 9

Injection of Cyclohexyl amine = 1.0 x 50 = 50 g/hr (Cyclohexyl amine 100% base)20wt % Cyclohexyl amine solution may be prepared in Neutralization Amine Injection Package(062-V-1003). However, when injection rate is too small, concentration of the solution will be

adjusted.

6.1.3 Boiler Water

Boiler water quality is controlled with phosphate injection and continuous blowdown.

A) Boiler Blowdown

(1) Continuous Blowdown (Surface Blowdown)For Package Boilers (062-F-1001A/B/C) and Heat Recovery Steam Generators

(051/052-F-1101/1102), 1% continuous blow down may be considered enough rate at normaloperation. Basis is shown below;

Control

Parameter

Expected concentration in

BFW

Control Target

in Boiler Water

Minimum blowdown

to keep target

Conductivity 0.2 micro-S/cm 600 micro-S/cmmax.

0.04 %(0.2/600 x100)

Silica

(as SiO2)

0.02 g/ton 20 g/ton max. 0.1 %

(0.02/20 x 100)

As shown in the above, minimum 0.1% blowdown is required to keep boiler water quality. Normally1.0% blowdown is a sufficient rate considering operation margin for the target value, however if

quality of boiler water is not stable, increase blow down rate. (3 % is the design rate of continuous blowdown.) Actual blowdown rate shall be determined according to actual sampling data.

(2) Intermittent Blowdown (Bottom blowdown)

Intermittent blowdown is done manually from bottom of steam drums, to maintain the boiler waterfree from sediments.

For the operating procedure of the Package Boilers, refer to the vendor’ instruction “Operation &

Maintenance Manual” (062-VDR-MCI-1800).

For the operating procedure of the Heat Recovery Steam Generator, refer to the vendor's instruction

“Operation & Maintenance Manual” (051-VDR-ALP-1800).

B) Phosphate Injection

Phosphate treatment is adopted for treating of leak hardness in feed water and adjusting pH of boilerwater to inhibit corrosion.

(1) Mole Ratio of Sodium and Phosphate

Phosphate solution is injected into each steam drum. In the case that demineralized water is used asmake-up water, tri-sodium phosphate or a mixture of di-and tri- sodium phosphate is generally used

in Na and PO4 mole ratio at the range of 2.6 to 2.8.

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For example, the mole ratio is controlled at 2.8 as typical value to prevent free sodium hydroxide.

For make-up of 2.8 mole ratio phosphate compounds, mix Na3PO4-12H2O and Na2HPO4-12H2O with

mole ratio of 4 and 1. (As weight ratio, 4.25:1. This mixture contains 25.2 % of PO4; hereinafter, thismixture is called “Phosphate compound”)

Character of each phosphate is listed below;

Chemical name Molecularformula

Appearance Molecularweight

pH(1% solution)

PO4 (%)

Sodium Phosphate

(Tri-sodium phosphate)

Na3PO4 Na3PO4-12H2O

White crystal

380 12 24.9

Sodium hydrogen

phosphate (Di-sodium phosphate)

Na2HPO4 Na2HPO4-12H2

O White crystal

358 8.2 26.5

Phosphate Compound Na2.8H0.2PO4 Na2.8H0.2PO4-12

H2O Whitecrystal

376 About 12 25.2

(2) Normal Injection

The normal injection of phosphate solution is determined by the following equation on the basis of

the concentration of phosphate ion;

A-PO4-Normal = {(F-Ca-H x 0.57) + B-PO4 / N} x BFW

where

A-PO4-Normal = normal injection of phosphate ion (g/hr as PO4

3-

)F-Ca-H = concentration of calcium hardness (as CaCO3) in feed water (mg/lit. CaCO3, in the case that

demineralized water is used for make-up of feed water, this is considered zero.)

B-PO4 = concentration of phosphate ion to be kept in boiler water (mg/lit.=g/ton as PO43-

)

N = concentration ratio of Boiler Water (times; = 100/ (blowdown %))

BFW = boiler feed water to each boiler (ton/hr)

Example for 062-F-1001A normal operation;

BFW = approx. 100 ton/hr

B-PO4 = 10 mg/lit.= 10 g/ton

N = 100 (normally 1 % continuous blowdown)

A-Normal = {( 0 x 0.57 )+ 10 / 100 } x 100 = 10 g/hr

2wt % of Phosphate compound solution to be prepared in 062-V-1001. Phosphate compound (i.e. Na2.8H0.2PO4-12H2O ) includes 25.2 wt% of PO4, therefore dilute 2kg of the compound with 98 kg of

deminealized water as ratio and inject by a dedicated reciprocating pump at 6.0 lit./hr. (2.0 lit. = 2000g solution includes 2000 x0.02 x0.252= 10 g of PO4 ) If PO4 concentration of boiler water decreases,increase the injection rate.

(3) Start-up

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The initial charge is performed to obtain nearly the same water quality at start-up as that in normal

operation so that the initial injection is calculated for the holding water volume of the boiler.

The initial injection amount of phosphate solution is usually determined by the following equation on

the basis of phosphate ion concentration;

A-Start = (F-Ca-H x 0.57 + B-PO4) x Holding water in boiler

where

A-Start = initial injection of phosphate ion (g as PO43-

)

Example for 062-F-1001A

B-PO4 = 10 mg/lit. = 10g/ton

Holding water in one boiler = approx. 57.1 m3 = 57.1 ton

A-Start = (0 x 0.57 + 10) x 57.1 = 571 g as PO4

3-

571/0.252 = about 2266 g

Thus 2266 g of phosphate compound is required. Dilute the 1 kg of the compound with 19 kg of

demineralized water as the ratio and inject with 12 lit./hr ( 100 % of pump capacity). It will takeapprox. 3.8 hours to inject 571 g of PO4.

6.2 Single Failure of Package Boiler

When one of the package boilers trips, HP steam will be supplied by remaining two boilers byincreasing steam generation load. However, HP steam is not sufficient during transient period due to

limitation of the boiler load increase. Load shedding system will work to continue LNG train

operation. Refer to Section 6.4.

6.3 Single Failure of Steam Turbine Generator

When one of the steam turbine generators trips, required electrical load will be covered by remaining

two steam turbine generators. However, the electrical generation load cannot increase suddenly dueto limitation of the steam turbine instant load increase. Load shedding system will work to continueLNG train operation. Refer to Section 6.4.

6.4 Load shedding

In case of a Package Boiler (062-F-1001A/B/C) trip or a Steam Turbine Generator Set(061-GS-1001A/B/C) trip, load shedding is required to continue LNG train operation.

Shedding items are as follows;

- BOG Compressors (071-C-1001A/B)

- Desalination Package (064-V-1001A/B)

- Infrastructure

Required period of the load shedding is within 10 minutes.

After the period, it is possible to restart these items.

In case of a Package Boiler (062-F-1001A/B/C) trip or a Steam Turbine Generator Set(061-GS-1001A/B/C) trip during one boiler or one STG maintenance, load shedding of one

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train is required in addition of above items because one boiler or one STG can not cover two

trains operation.

After load shedding, the remaining train shall be turned down in order to start a BOG

compressor, desalination package and infrastructure.

7. NORMAL SHUTDOWN PROCEDURE

An entire shutdown of the steam system is only possible during the whole plant shut down. However

equipment or sections of line may require periodically shutdown for maintenance or an inspection. Inthat case, only the equipment or the sections shall be isolated.

7.1 Deaerator

(1) Confirm one train is completely shut down.

(2) Close Deaerator (062-V-1001A/B) level control valve (062-LV-1111 or 1112) ondemineralized water line.

(3) Close 10” block valve on the pump minimum flow return line.

(4) Close 20” block valve on boiler feed water outlet line.

(5) Slowly close Deaerator pressure control valve 8062-PV-1211 or 1212) on LP steam line

together with slow closing 14” block valve on recovered condensate line.

(6) Close 4” block valve on steam balance line.

7.2 Package Boiler

(1) Steam generation load of the package boiler to shut down shall be gradually reduced to prevent upset of HP steam system. For shutdown procedure of the Package Boilers

(062-F-1001A/B/C) refer to the vendor’s instruction “Operation & Maintenance Manual”

(062-VDR-MCI-1800).

(2) Dedicated phosphate injection pump in Phosphate Injection Package (062-V-1001) shall bestopped.

7.3 Steam Turbine Generator System

(1) Power generation load of the steam turbine generator to shut down shall be gradually reduced

to prevent upset of power distribution system and HP steam system. For shutdown procedureof the Steam Turbine Generator Sets (061-GS-1001A/B/C) refer to the vendor’s instruction“Operation and Maintenance Manual” (061-VDR-MES-9801).

(2) Close block valve of HP steam line to vacuum system.

(3) Stop Condensate Recovery Pump (061-P-1001A/B/C).

(4) Stop Air Cooled Surface Condenser (061-E-1001A/B/C).

7.4 Heat Recovery Steam Generator

(1) Stop Gas Turbine. Refer to shutdown procedure of the Gas Turbine (051/052-CG-1001/1002)and the heat recovery steam generator (051/052-F-1001/1002). Refer to the vendor’s

instruction “Operation, Install. & Maintenance Manual” (51-NPC-802) for Gas Turbine and“Operation & Maintenance Manual” (051-VDR-ALP-1800) for HRSG.

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(2) Dedicated phosphate injection pump in Phosphate Injection Package (051/052-V-1003)

shall be stopped.

7.5 Train Shutdown

(1) Confirm all on-site process units including the HRSG and the steam turbine drivers are

shutdown.

(2) Close isolation valves at the train BL

(3) Stop dedicated LP Steam Condensate Cooler (051/052-E-1107) located in utility area.

8. EMERGENCY SHUTDOWN PROCEDURE

8.1 General

This section describes the guidelines of shutdown procedure in case of emergencies. However, inemergencies, required actions by operators may vary because they depend on the actual situation at

the time of emergency. Therefore, it is most important for the operators to determine the cause ofemergency accurately and to understand the exact situation.

8.2 Loss of Utilities

8.2.1 Power Failure

All pumps and fans will stop. Also forced draft fans in the package boilers will stop and that leads tothe package boilers trip. Accordingly whole plant shut down will occurs.

Emergency generator sets will start to run automatically for safety plant shutdown.

8.2.2 Instrument Air Failure

When there is an instrument air failure, all control valves will assume their fail safe positions.

The fail-safe positions for control valves are either fully open, closed, or maintain last position. Allthe failure positions are shown on the P&ID. The fail-safe position depends on the service. The

operators should be aware of the position of all valves in case of emergency.In the event of total air failure, almost of all facilities can not maintain the operation because most ofthe systems have a control valve. In this case all pumps should be stopped immediately.

8.2.3 Cooling Water Failure

In the event of total cooling water failure, operator should stop 062-P-1001A/B/C,051/052-P-1101A/B, Package Boiler and Steam Turbine Generators manually to avoid mechanicaldamage caused by overheating of lubricant and loss of mechanical cooling. At this situation, all

process units are shutdown, and the steam, feed water and condensate handling system will be shutdown, accordingly.

9. SAFETY PROCEDURE

9.1 General

To prevent accidents it is of the utmost importance that all personnel be instructed properly of

the following subject:

- The leaks and responsibilities of the operators

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- The methods to accomplish this in a safe manner

The following safety regulations cover operations of particular concern to the personnel

responsible for the unit. They are intended to supplement any existing general plant safety

regulations which cover all units; reference should be made to the latter for all points notmentioned below. Mechanical craftsmen working on their unit will be governed by their own

departmental safety regulations, but the operator should see that none of the following safety

regulations are violated by mechanical workers.

In addition to specifically defined rules and practices, the exercise of good judgment by every

person involved is essential to safe operation. An operator should be alert for any situation

which might present a personnel hazard. It should also be the responsibility of each person

familiar with the plant to warn other workers who enter the plant of possible hazards they

could encounter.

All personnel must know the location and use of safety shower, fire extinguisher, plant fire

alarm, and main isolation valves, fire hoses and hydrants, fire blankets, gas masks and

respirators, and other protective equipment such as hard hats, rubber gloves, etc.

Soda acid or foam type extinguisher must not be used on fire around electrical equipment

because the water solution will conduct electricity and may aggravate the difficulty or result in

the electrocution of personnel.

Carbon dioxide or dry powder extinguisher may be used safety on electrical fires.

Gas masks or breathing apparatus must be worn whenever dangerous fumes are encountered.

Safety hats must be worn when outdoors.

Gloves and goggles or face shields should be worn where dangerous or hot vapor or liquid is

encountered, and are recommended for use while samples are being withdrawn and solutions

made up.

Fire extinguishers must be recharged immediately after use. All stream and water hoseequipment must be put back in place after use. Access to such equipment must not be

obstructed.

Gas masks must have fresh cartridges installed after use.

9.2 Emergency Fire Plan

The fire protection system of the plant is designed to prevent fire occurrence, control fire

escalation, or extinguish fire within short period of time, assuming there will be no outside fire

fighting assistance, with only one major fire at a time.

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9.3 Fire Fighting and Protective Equipment

Fire hazard status throughout the plant shall be monitored on the Hazard Detection and

Monitoring System (HDMS (F&G)) consoles in the main control room and fire and emergency

station.

Upon fire detection, suitable fire fighting agents such as water, foam, dry chemical and inertgas shall be used to control and/or extinguish a fire, and cool down equipment exposed by a fire

or a heat radiation.

For the detail, refer to 82-SPE-HS-1540, “Operation Manual for Fire Protection System” and

the relevant drawings for fire protection system.

9.4 Maintenance of Equipment and Housekeeping

1. Operating equipment should be checked frequently for signs of leakage, overheating, or

corrosion, so that unsafe conditions may be corrected before they result in serious

consequences. Unusual conditions should be reported at once.

2. Guard around moving shafts, coupling belts, etc., which have been removed for repairs of

the equipment must be replaced when repair work is completed.

3. Tools, pieces of pipe etc., should never be left lying on platforms or railings of operation

equipment where they can be knocked off and injure someone below.

4. Access to ladders and fire escapes must be kept clear. Waste material and refuse must be

put in proper locations where they will not offer fire or stumbling hazards.

5. Liquid spills must be cleaned up immediately. Blanket gas leaks with steam and

immediately report leaks for repair.

6. In the event that electrical equipment does not function properly, notify the electrical

department and stay clear of the equipment until the electrician arrives.

7. Gas cylinders should be stored so that they cannot fall over. Guard caps must remain inplace over the valves of cylinders, which are not in use.

8. Care should be taken when installing scaffolding to ensure that the wooden boards do not

contact hot equipment and that no part is allowed to impair free access on operational

equipment e.g. ladders, stairways, walkways or valves. Scaffolding should be removed

immediately on completion of the work in hand.

9. Switch pumps regularly when spares are provided. This will assure start the spare pump

will be ready when needed.

9.5 Repair Work

1. Mechanical work around and operating unit must be kept to a minimum, and theminimum number of men should be used.

2. No mechanical work on the equipment is to be done without a properly authorized work

permit.

3. Safety hats must be worn by all personnel in all areas at all times.

4. No burning, welding, open fires, or other hot work shall be allowed in the area unless

authorized by a work permit. Catch basins, manholes, and other sewer connections must

be properly sealed off to prevent the leakage of gases, which may ignite upon contact with

an open flame.

5. No personnel shall enter a vessel for any purpose whatsoever until it has been adequately

purged, blanked off, and then tested to ensure freedom from noxious or inflammable

gases and an entry permit issued.

6. Lines operation at a low temperature might fracture if unduly stressed; therefore, do not

physically strike these lines and avoid operation conditions, which would cause a water

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hammer to start.

7. Do not use light distillates such as gasoline or naphtha to clean machinery or for any other

cleaning purposes.

8. Equipment should not be left open overnight. At the end of each day’s work blanks or

spades should be installed to prevent entry of flammable materials due to valve let-by.9. Welding cylinders should be removed from site to a designate safe area at the end of each

working day.

9.6 Withdrawal of Samples

Samples shall be withdrawn from the unit only by authorized personnel.

Protective equipment, face masks or goggles, and suitable gloves must be worn for sampling. A

container must never be filled to the brim, in order to minimize risk of subsequent spillage.

When sampling any product liquids, gloves and goggles will be worn.

When sampling any material, gas or liquid, the sampling line must be flushed long enough toremove dormant materials to insure that the sample obtained represents the current stream.

Pass enough gas through the sample vessel to insure the displacement of the purge gas and to

adjust the temperature of the sampler to that the composition is not distorted by condensation

or flashing, etc.

Wear proper personal protective equipment and exercise caution to avoid injuries.

When sample cooling is required, operator shall confirm cooling water is flowing properly

before taking the sample.

9.7 Safe Handling of Volatile and Toxic MaterialsThe safety rules given below are for the protection of life and limb, and the prevention of

property loss. It is expected that plant people will exercise common sense, alertness, and good

judgment in carrying them out. If ever there is any doubt as to the safety aspect of a particular

operation, consult your supervisor immediately.

9.8 Respiratory Protection

Most plant gases, other than air, are harmful to human beings if inhaled in certain

concentration. Toxic gases may be classified as either asphyxiating or irritating. Asphyxiating

gases may cause death by replacing the air in the lungs or by reaction with the oxygen carried

in the blood; examples are hydrogen sulfide carbon monoxide, and smoke. Irritating gases may

cause injury or death not only by asphyxiating but also by burns internal and external/

examples are chlorine and sulfur dioxide. To guard against the inhalation of harmful gases:

Secure a gas test certificate showing the gas condition of the vessel is safe for entry.

Stand on the windward side of an operating from which gases escape.

Provide proper ventilation.

All personnel should become familiar with the accepted method of artificial respiration in

order to render assistance to any one overcome by gas, electric shock, or drowning.

If anyone is overcome by gas, his rescuer should:

Never attempt a rescue unless an assistant is standing by.

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Protect himself before attempting a rescue by wearing breathing apparatus.

Get the victim to fresh air as soon as possible.

Give artificial respiration and send his assistant to call for medical aid.

When using a breathing apparatus, be sure that the mask fits the face properly. Test it by theapproved test method.

Wear the correct type of breathing apparatus, suited to the situation encountered.

9.9 Breathing Apparatus (B. A.)

There are four types of breathing apparatus in general plant service. They are the canister type

masks, the fresh air hose line B. A., the compressed air self-contained B. A. and the compressed

air line trolley B. A.

The compressed air self-contained breathing apparatus has a self-contained air supply carriedon the back of the user.

It is used principally in emergencies.

After use, always notify the proper department so that they can recharge the cylinders as soon

as possible.

9.9.1 Nitrogen

N2 is an inert gas used for purging equipment or maintaining a positive pressure inert gas

blanket on a vessel.

N2 is neither poisonous nor flammable, but care must be exercised when working inside

equipment that has been N2 purged. Adequate ventilation must be provided and appropriate

breathing device worn. To breathe an atmosphere high in N2, could result in suffocation.

Before entering vessels that have been purged with N2, a check must be made for proper

oxygen content prior to entry. Rapid vaporization of liquid nitrogen can cause severe burns on

contact with the skin.

9.9.2 Corrosive Materials

Whenever containers of corrosive chemicals such as caustic soda and sulfuric acid, are to be

opened or emptied, always have a connected water hose handy to flush off and help absorb

spilled material and to reduce spread of toxic vapors.

9.9.3 Chemicals

The following chemicals are used in this system. They are hazardous and shall be taken care

when handling them. Plastic gloves, a face shield, overalls, a full PVC suit or chemical resistant

apron, and rubber safety boots shall be worn. The PVC trousers should be outside the boots.

Avoid all contact with and do not inhale the fumes.

- Oxygen Scavenger

- Neutralizing Amine

- Phosphate

Refer to the Material Safety Data Sheet (MSDS) of each chemical.

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10. ISOLATION PROCEDURE FOR MAINTENANCE

This section describes the isolation procedures to be taken prior to maintenance work based on the

following specification:Maintainability Philosophy (99-PHI-EM-0005)

Availability and Sparing Philosophy (99-PHI-PS-0002)

10.1 General

It is necessary to isolate trains, items of equipment, or groups of equipment, in order to facilitate

shutdown for maintenance, inspection, tie-ins, or loss prevention.

As the degree of hazard increases, the measure of protection required must be deeply considered. The

degree of hazard is related to the system contents (e.g. flammability, toxicity etc.), pressure and

temperature. There are two main methods of isolation which can be used:

Positive isolation incorporating the use of spades/spectacle blinds or removable spools and blindflanges, where no leakage can be tolerated for safety and contamination reasons, e.g. for vessel entry

or for creating safe construction areas within a plant.

Valved isolation for less critical duties than those requiring positive isolation, e.g. for control valvemaintenance. Valved isolation will also be required to enable positive isolation to be installed orremoved without the need for a complete plant shutdown.

10.2 Basic Procedures

The basic ideas for method of isolation are shown below. The details will be developed by Ownerwhen actual isolation work will be required. The selection of type of isolation valve and

blind/removable spools shall be in accordance with the applicable piping and material specifications.This section considers train or system requiring isolation followed by individual equipment isolation

requirements. Sketches below are provided as an aid to develop actual planning for maintenancework.

10.2.1 Train Isolation

Refer to Maintainability Philosophy (99-PHI-EM-0005) for Train isolation.

Each train is capable of being isolated.

10.2.2

Individual Equipment / System Isolation10.2.2.1 Horizontal and Vertical Pressure Vessels

All vessels where manned entry may be required are provided with spectacle blinds or spade and

spacer arrangements on every process inlet and outlet nozzles. Relief valve inlet lines from pressurevessels are normally positively isolated from the vessel by removing the relief valve and blinding the

inlet line end. A typical arrangement is shown on Figure 9.2.1 and 9.2.2.

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Figure 10.2.1

Horizontal Pressure Vessel

Figure 10.2.2

Vertical Pressure Vessel

10.2.2.2 Pumps

Normally valved isolation method is applied for isolation of pump suction and discharge lines. If

required from the maintenance work nature, spectacle blinds will be provided. Refer to Figure 9.2.3.

RELIEF VALVES

AND FLARE

GAS OUTLET

LIQUID OUTLET

INLET

LINE

VERTICALVESSEL

INLET

LINE

DRAIN LINES

OIL OUTLET

WATER OUTLET (IF REQUIRED)

GAS OUTLET

RELIEF VALVES

AND FLARE

HORIZONTAL VESSEL

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Figure 10.2.3

Pumps

10.2.2.3 Shell and Tube Heat Exchangers

When removable spool pieces are provided on the piping associated with the tube side connections onshell and tube heat exchangers, the removal of these pieces should be don for the tube bundles for

cleaning/maintenance. If required from the maintenance work nature, spectacle blinds will be provided.

Figure 10.2.4

Shell and Tube Heat Exchangers

11. MAINTENANCE PROCEDURE

11.1 General

INSTRUMENT AIR SYSTEM HAS NITROGEN BACKUP. NEVER USE INSTRUMENT

AIR FOR BREATHING APPARATUS.

Type of maintenance is classified in the following categories.

OUTLET

LINE

INLET

LINE

PUMP‘Y’ or ‘T’ TYPE SUCTION

STRAINER

TUBE SIDE INLET

SHELL SIDE INLET

SHELL

SIDE OUTLET

TUBE SIDE OUTLET

HEAT EXCHANGER SHELL & TUBE

NOTE: BLOCK VALVES NOT

REQUIRED IF EXCHANGER NOTSPARED OR BYPASSED

RS

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11.1.1 Routine/First line/ Maintenance

Routine/First Line Maintenance is the daily on-line or off-line visual inspection, lubrication,calibration or minor adjustment of running and static equipment. In addition to the maintenance

personnel carrying out the above types of checks/adjustments, the operator shall perform the

following routine maintenance activities whilst carrying out his daily checks on the Plant, in order to prevent any minor problems developing into major ones:

• Tightening gland followers on leaking valve packing.

• Tightening gland followers on leaking pump packing.

• Checking temperature and pressure gauges for broken glass faces.

• Checking for correct oil levels in pumps, gearboxes, oil reservoirs.

• Topping up low oil levels in the above equipment as required.

• Cleaning pump filters and strainers.

• Keeping equipment clean and tidy.

11.1.2 Breakdown Maintenance

For Breakdown Maintenance, there will be no scheduled checks or servicing. Corrective repairs will be carried out on failure of the Plant or equipment.

11.1.3 Planned Preventive Maintenance

Planned Preventive Maintenance will be carried out on a calendar or running hours basis. It will be performed in accordance with the vendors’ recommended frequencies.

11.1.4 Predictive/Condition Based Monitoring

Predictive/Condition based maintenance is the most efficient planning option. It uses direct

observations and instrument readings for the monitoring of the actual condition of the Plant andequipment, and can trend and forecast when maintenance activities are due to take place.

11.1.5 Turnaround /Inspection Maintenance

Turnaround/Inspection Maintenance will be carried out at approximately 3 yearly intervals, andusually entails a complete Plant or Train shutdown. It is utilized to perform testing and resetting of

safety valves, and inspections and repairs of equipment that cannot be shutdown or removed duringProduction.

11.2 Precautions prior to Maintenance

This section covers precautions prior to start maintenance work for a whole or a part of the plant.

• All work must be carried out within the requirements of company Safety & Environmental

Policies and Procedures. Prepare all known Work Permits, these must reflect safety issues.Obtain relevant permit to work before starting work.

• Inform Operations of the work content of this preventive maintenance procedure and how it will

affect them.

• All rotating equipment is to be considered energized until proven isolated.

• All vessels must be isolated, drained and vented.

• Cordon the work area, to prevent unauthorized access.

• Prior to commencement of this work ensure that moving/rotating/power generating/energystoring equipment has been isolated in accordance with the relevant permit to work and lock-out /

tag-out requirements.

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• Physically isolate vessels. Only standard blank flanges and spades should be used. No personshould enter a vessel unless all directly connected sources of process and utilities fluids have been positively isolated from the vessel. Entry means total body entry or any part of the body.

• Operations should check for oxygen, taking samples at several representative places, with a

portable analyzer to check for oxygen deficiency.

• Prior to commencement of this work it is recommended that the crew will be briefed on what isrequired and what hazards there are. The crew will be reminded of the location of safety showers,first-aid boxes and telephones.

• If welding or any process liable to evolve noxious fumes is to be carried out in the vessel,

adequate ventilation should be provided.

11.3 Preparation for Maintenance

The outline of the work sequence begins as below.

• Shutdown of the unit operation and liquid removal

• Inerting with nitrogen, if required.

• Installation of isolating blank flanges or spades

• Replacement with air for entry into the equipment

11.3.1 Installation of blank flanges or spades

After inerting have been completed, isolating blank flanges or spades must be installed at locations as

required.

11.4 Typical isolation method

11.4.1 Vessels/Drums

• Erect scaffold for access as required.

• Operations to close down the system, depressurize and nitrogen purge.

• Mechanical to spade inlet and outlet nozzles of said equipment.

• Mechanical to open drum.

• Operations to air purge and check for oxygen level.

• Operations to clean.

• One person to enter another to stand by on watch.

11.4.2 Pumps

• Operations to shut down the unit, stop pump motor and depressurize the line and pump.

• Electrical to lock out motor locally and remove relays/fuse/circuit breaker in substation.

•

Mechanical to spade at inlet and outlet nozzles of said equipment.• Operations to vent, air purge and drain the pump.

11.4.3 Shell and Tube Type Heat Exchangers

• Erect scaffold for access as required.

• Operations to close down the system and depressurize.

• Mechanical to swing spectacle inlet and outlet spectacle blinds.

• Mechanical to open as required.

• Operations to air purge and check for oxygen level.

• Operations to clean

11.4.4 Air Fin Coolers

• Operations to shut down the unit.

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• Electrical to lock out fan motor locally and remove relay/fuse in substation.

• Mechanical to remove access panel.

• Operations to check area is hazard free.

11.4.5 Close out• Ensure the equipment is left in a safe condition.

• Remove all tools and debris, clean local area.

• Note any faults found and comments.

• Raise a work request if any major corrective work is identified or the performance standards are

not met during the above maintenance.

• Sign off permit to work and inform area authority of equipment status.

12. ATTACHMENT LIST

Attachment-1 ProcessUtiliy Flow Diagram (To be attached in As Built)

Attachment-2 P&IDs (To be attached in As Built)

Attachment-3 List of Equipment Data Sheet (To be attached in As Built)

Attachment-4 List of Instrument Alarm Set Point (To be attached in As Built)

Attachment-5 List of Cause and Effect Charts (To be attached in As Built)

Attachment-6 Laboratory Sampling Schedule

Attachment-7 MSDS (Later)

Alarm & Trip Setting List (3)

Documents

Transcript of Alarm & Trip Setting List (3)