Alarm & Trip Setting List (3)

Doc. No.

TANGGUH LNG BPMIGAS

BP Berau Ltd.

62-IOM-PS-1201

Rev.

Author’s Org.

6A

Project

TLNG

KJP

KJP Doc. No.

S-062-1283-001

Date

27 Feb, 06

KJP Job Code

J-3400-20-0000

Sheet

1 of 35

3.8 MTPA TRAIN CAPACITY Operation Manual for Steam/Steam Condensate/BFW System

X

Core

Non-core

For Information

For Review

For Approval

X

Released

Date

Page

Prep’d

Chk’d

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

-2006

B 28-FE

PT. Brown & Root Indonesia

A

As-Built

Rev.

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Description

Lifecycle Code

BP App’d

BP Berau Ltd. Tangguh LNG Project Operation Manual for Steam/Steam Condensate/BFW System

Doc. No. 62-IOM-PS-1201 KJP Doc. No. S-062-1283-001 Rev. 6A Sheet No. 2 of 35

CONTENTS 1. 2. 2.1 2.2 2.2.1 2.2.2 2.2.3 2.3 2.3.1 2.3.2 2.3.3 2.3.4 2.4 2.4.1 2.4.2 2.4.3 2.4.4 3. 3.1 3.2 3.3 3.4 3.5 3.6 3.7 4. 5. 5.1 5.2 5.3 5.4 5.5 5.6 5.7 5.8 5.9 5.10 5.11 6. 6.1 6.1.1 6.1.2 6.1.3 6.2 6.3 6.4 7. 7.1 7.2 7.3 7.4 7.5 8. 8.1 8.2

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Introduction.................................................................................................................................4 Basis of Design.............................................................................................................................4 General ........................................................................................................................................4 Design Condition.........................................................................................................................5 SERVICE CONDITIONS ................................................................................................................ 5 BOILER FEED WATER QUALITIES .............................................................................................. 5 STEAM CONSUMERS................................................................................................................... 5 Special Equipment ......................................................................................................................6 DEAERATORS (062-D-1001A/B)................................................................................................ 6 PACKAGE BOILERS (062-F-1001A/B/C) .................................................................................... 6 STEAM TURBINE GENERATOR SETS ........................................................................................... 6 HEAT RECOVERY STEAM GENERATORS .................................................................................... 7 Process Description.....................................................................................................................7 STEAM GENERATION.................................................................................................................. 7 STEAM DISTRIBUTION ................................................................................................................ 7 STEAM CONDENSATE RECOVERY AND TREATMENT.................................................................. 8 STEAM TURBINE GENERATOR SYSTEM...................................................................................... 9 Process Controls..........................................................................................................................9 Boiler Feed Water.......................................................................................................................9 High Pressure Steam ................................................................................................................10 Low Pressure Steam .................................................................................................................11 Blowdown System for Boilers ..................................................................................................12 Clean Steam Condensate..........................................................................................................12 Suspect Steam Condensate.......................................................................................................12 Steam Turbine Generator Sets ................................................................................................13 Preparation for initial start-up ................................................................................................15 Normal Start-up Procedure .....................................................................................................15 General ......................................................................................................................................15 Start up of Boiler Feed Water System ....................................................................................15 Start up of Package Boiler (062-F-1001A/B/C) ......................................................................15 Introduce HP Steam to HP Steam Header .............................................................................16 Letdown HP Steam to LP Steam .............................................................................................16 Introduce LP Steam to Deaerators (062-D-1001A/B)............................................................17 Start Steam Turbine Generator Set (061-GS-1001A/B/C)....................................................17 Steam Condensate System .......................................................................................................17 Letdown HP Steam to MP Steam............................................................................................18 Start up of Heat Recovery Steam Generator (051/052-F-1101/1102)...................................18 Start up of the Suspect Condensate Recovery System...........................................................19 Normal Operation.....................................................................................................................19 Water Quality Control .............................................................................................................19 GUIDE LINE .............................................................................................................................. 19 BOILER FEED WATER............................................................................................................... 20 BOILER WATER ........................................................................................................................ 21 Single Failure of Package Boiler..............................................................................................23 Single Failure of Steam Turbine Generator...........................................................................23 Load shedding ...........................................................................................................................23 Normal Shutdown Procedure ..................................................................................................24 Deaerator...................................................................................................................................24 Package Boiler...........................................................................................................................24 Steam Turbine Generator System...........................................................................................24 Heat Recovery Steam Generator.............................................................................................24 Train Shutdown ........................................................................................................................25 Emergency Shutdown Procedure ............................................................................................25 General ......................................................................................................................................25 Loss of Utilities..........................................................................................................................25

BP Berau Ltd. Tangguh LNG Project Operation Manual for Steam/Steam Condensate/BFW System

Doc. No. 62-IOM-PS-1201 KJP Doc. No. S-062-1283-001 Rev. 6A Sheet No. 3 of 35

8.2.1 POWER FAILURE ...................................................................................................................... 25 8.2.2 INSTRUMENT 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 INDIVIDUAL 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 ROUTINE/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 /INSPECTION MAINTENANCE ............................................................................ 33 11.2 Precautions prior to Maintenance...........................................................................................33 11.3 Preparation for Maintenance ..................................................................................................34 11.3.1 INSTALLATION 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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BP Berau Ltd. Tangguh LNG Project Operation Manual for Steam/Steam Condensate/BFW System

1.

Doc. No. 62-IOM-PS-1201 KJP Doc. No. S-062-1283-001 Rev. 6A Sheet No. 4 of 35

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 Low Pressure steam (LP steam) to the plant, and recovery the condensates. Steam turbine generator (Unit 061) generates electric power to supply power for two trains operation including 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 steam turbine 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 Medium Pressure (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 refrigerant compressors in the LNG train. Three package boilers are provided to supplement the HP steam from HRSGs for generating electric power by steam turbine power generators. Low-pressure steam is produced from back pressure steam turbines, flash drums at continuous blow down 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 a letdown 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 passed through 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 each HRSG and package boiler. Electric power is generated by Steam Turbine Generator Sets 061-GS-1001A/B/C. The steam to steam turbines is supplied from high pressure steam system.

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BP Berau Ltd. Tangguh LNG Project Operation Manual for Steam/Steam Condensate/BFW System

2.2

Design Condition

2.2.1

Service Conditions Operating Condition at Source

2.2.2

Operating Condition at B.L. of User Unit

Pressure kg/cm2G

Temperature o C

Pressure kg/cm2G

Temperature o C

Pressure kg/cm2G

Temperature o C

High Pressure Steam

40.5

400

Min.40

400

44.7

425

Medium Pressure Steam

24.0

223

Min.24

221

27.5

250

Low Pressure Steam

3.5

148

Min.3.3

148

5.3

175

Boiler Feed Water

59.0

120

-

-

78.0

148

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

2.2.3

Mechanical Design Condition

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

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)

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Deethanizer Reboiler (041/042-E-1005)

BP Berau Ltd. Tangguh LNG Project Operation Manual for Steam/Steam Condensate/BFW System

Doc. No. 62-IOM-PS-1201 KJP Doc. No. S-062-1283-001 Rev. 6A Sheet No. 6 of 35

Low Pressure Steam (LP Steam)

2.3

-

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)

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 tray Capacity: 51,5724kg/h for each Operation 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 train operation 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: Type: Capacity: Steam pressure: Steam temperature: Fuel:

Three (Three for continuous operation) Water tube with economizer 160ton/h (MCR) for each 40.5 kg/cm2G at boiler package Battery Limit 400 °C Fuel gas

HP steam is primary supplied by HRSGs (051/052-F-1101/1102) and Package Boilers (062-F-1001 A/B/C) are designed to supplement HP steam Peak load operation at 110 % of MCR (maximum continuous 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 be less 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 including the outside fence supporting facilities. Number of the units: Type: Power generated: Inlet Steam:

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Three (Three for continuous operation) Full condensing turbine 35 MW / each HP steam

BP Berau Ltd. Tangguh LNG Project Operation Manual for Steam/Steam Condensate/BFW System

Condensing pressure: Condenser: 2.3.4

Doc. No. 62-IOM-PS-1201 KJP Doc. No. S-062-1283-001 Rev. 6A Sheet No. 7 of 35

0.4 kg/cm2A A-frame air cooled surface condenser with condensate pump / ejector

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: Type: Steam pressure: Steam temperature: Steam production rate:

2.4

Process Description

2.4.1

Steam Generation

Four (dedicated to each Frame 7 Gas Turbine) Water tube with economizer 40.5 kg/cm2G at package B/L 400 °C 132 t/h each

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 MR compressors (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 saturated condition 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 from utility 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 compressor string driven by Frame-7 gas turbines in process train. Since the turbines are back pressure types, the outlet 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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Doc. No. 62-IOM-PS-1201 KJP Doc. No. S-062-1283-001 Rev. 6A Sheet No. 8 of 35

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 Acid Gas 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 is also 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 LP letdown 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 Vent Condenser (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 Condensate Pump (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 at almost 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. The steam 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 the Mixed 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 at 1.0 kg/cm2g and 120 °C. Low pressure steam is used as the medium to removes the gaseous in deaerator upper section. Free gaseous steam condensate (boiler feed water) is collected in the drum

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Doc. No. 62-IOM-PS-1201 KJP Doc. No. S-062-1283-001 Rev. 6A Sheet No. 9 of 35

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 with specified boiler feed water quality. For this HRSG and Packaged Boiler operation range, the suitable chemical injection is Phosphate, Oxygen Scavenger, and Neutralization Amine. Oxygen Scavenger and 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 Surface Condenser (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/). Vacuum creating 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 of losses 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 line of 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 keep appropriate 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. Oxygen scavenger 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 Package Boilers (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 refrigerant compressors 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), further reduction 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 the hi-selector, which overrides the 060-PIC-1207, to control the HP steam header pressure by disposing the 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 LP steam 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 close through 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 to steam turbine drivers HP Steam Header Pressure Main Control

3.3

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

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 the LP steam header pressure. The governor pressure controller (060-PIC-1205) through the low-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 turbine helper, 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/cm2g by introducing the 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 to 091/092-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.

_ _ _ __ RA| D __| N I ||___ -2006

B 28-FE

BP Berau Ltd. Tangguh LNG Project Operation Manual for Steam/Steam Condensate/BFW System

Doc. No. 62-IOM-PS-1201 KJP Doc. No. S-062-1283-001 Rev. 6A Sheet No. 12 of 35

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

3.4