process overview lesson text

ORIENTATION

Process Overview Lesson Text

Document No.:P11-X01-QTOPSGEN-001

Revision No.: 0

Date: 04/27/23

ORIENTATION

PROCESS OVERVIEW

LESSON TEXT

Ras Laffan Liquefied Natural Gas Company Ltd. of 77

Doc No: P11-X01-QTOPSAGEN-001

Date: 04/27/23

ORIENTATION

Process Overview Lesson Text Rev: 0

1 INTRODUCTION

This manual is an overview of the RasGas LNG Project, the main emphasis being placed on the Onshore Process Facilities. The manual has been produced to give an introduction to Qatar, Ras Laffan Liquefied Natural Gas Company and the overall LNG project. All Production and Process facilities are covered in greater detail in later manuals.

The material has been produced as an aid to training and its use is limited to that purpose. The document does not supersede RasGas Operating Manuals and Procedures, Standing Instructions or Safety Procedures.

2 RAS LAFFAN LIQUEFIED NATURAL GAS COMPANY LTD

2.1RASGAS LNG PROJECT

Ras Laffan Liquefied Natural Gas Company Limited (RasGas) was established in 1993 by an Emiri Decree of the State of Qatar. The whole project includes offshore production plant, onshore liquefaction plant, storage and shipping facilities.

2.1.1 SHAREHOLDERS

The company was established in June 1993 as a joint venture between Qatar General Petroleum Company (QGPC) and Mobil Corporation. However, an agreement in principle was reached in December 1996 for two Japanese Companies, Itochu Corporation and Nissho Iwai Corporation, to acquire minor interests in the project. Negotiations for the final agreement are now at an advanced stage and it is expected that a Korean consortium will acquire an interest in the project.

The equity shareholding of RasGas comprises:

QTOPSRas Laffan Liquefied Natural Gas Company Limited of 77


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QGPC 63%

MOBIL 25%

KOREAN CONSORTIUM 5%

ITOCHU CORP. 4%

NISSHO IWAI 3%

QGPCQGPC was established as a state owned corporation in 1974. It is responsible for all aspects of the Qatar oil and gas industries. QGPC is the sole owner of the North Field Phase 1 development, which supplies local demand for gas and feedstock. QGPC is also the major shareholder in Qatar’s first LNG producer Qatargas, which is also situated at Ras Laffan and produced its first shipment of LNG in January 1997.

MOBILMOBIL is one of the major oil companies in the world. It is also a major shareholder in Qatargas. MOBIL also has considerable experience in the development of LNG plants in other countries, notably PT Arun in Indonesia.



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QGPC63%

MOBIL25%

NISSHOIWAI3%


RAS LAFFAN LIQUIEFIED NATURAL GAS COMPANY


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2.1.2 QATAR NORTH FIELD

The North Field is located offshore to the north east of Qatar. The field is one of the world’s largest non-associated gas reservoirs with total recoverable reserves of 370 TCF (trillion standard cubic feet). The field extends over 6,000 square kilometres.

Development of the field commenced in 1991 when QGPC developed the North Field Alpha complex. RasGas will initially develop and produce gas from the Khuff - 4 formation in the North Field Area (NFA). The NFA sits 95 km offshore in approximately 67 m of water. RasGas’s development area in the North Field is a block 10km X 10km, which is surrounded by a 2km buffer zone in which drilling and development is not permitted.

The initial development to support two LNG trains includes the installation of 3 wellhead platforms. The configuration is such that each wellhead platform serves a train with the 3rd wellhead platform common to both trains.

2.1.3 PROJECT BACKGROUND

RasGas drilled and tested a well in 1994, the results of which verified gas quality, well deliverability and gas reserves of the Company’s development area in the Qatar North Field.

ITOCHUCORP.

4%KOREAN

CONSORTIUM5%



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In October 1995, RasGas signed a Sales and Purchase Agreement with Korea Gas Corporation of South Korea for 2.4 million tons per year of LNG. Then in June 1997 the agreement was increased to 4.8 million tons per year of LNG. The first delivery is scheduled for July 1999.

The Engineering, Procurement and Construction (EPC) Contracts were awarded in early 1996. The EPC Contract for the offshore platforms was awarded to the joint venture of Mc Dermott-ETPM East Inc. and Chiyoda Corporation, and Saipem, SpA will be responsible for the subsea pipeline work. The EPC contract for the onshore facilities was awarded to the joint venture of Japan Gas Corporation (JGC) and the M W Kellogg Company.

2.1.4 OVERALL PROJECT

The RasGas LNG plant is situated at Ras Laffan, Qatar’s new industrial development complex approximately 90 km north of Doha.

The offshore complex includes a process and utilities platform, accommodation platform, riser platform, three wellhead platforms, bridge support platform and flare tower. The riser platform contains; infield flowlines from remote wellhead platforms and a 32 inch two-phase gas-condensate pipeline to shore.

The onshore LNG plant consists of two parallel trains each capable of producing 2.6 MTPA (Million Tons Per Annum) of LNG and 45,000 bbls/day of condensate.

The receiving facilities consists of process and utilities area that include a slug catcher and condensate stabilisation unit complete with flaring systems.

The plant also includes storage and loading facilities. RasGas will have dedicated loading facilities at the Ras Laffan Port which is operated by QGPC. A fleet of LNG carriers will deliver the LNG to Korea Gas Corporation.

The plant is completely self-supporting and is designed for easy expansion to six LNG trains, depending on market demand.



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FIGURE 2.2 BLOCK FLOW DIAGRAM OF LNG PRODUCTION


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2.1.5 MAIN FEATURES OF THE PROJECT

The main features of the RasGas project are:

An Offshore Production, Separation, Treatment and Accommodation Complex sitting in 67 metres of water approximately 95 km offshore

3 Wellhead Platforms, each initially with 5 Wells (Each platform has a total of 9 Well Slots).

A 32 inch two-phase gas-condensate sub-sea pipeline to the Ras Laffan LNG Plant onshore.

Onshore Liquefaction Plant to receive, treat, liquefy and export LNG and associated by-products

Condensate Treating

Self sufficient utilities systems

Storage and loading facilities for: LNG / Condensate / Sulphur

A fleet of carriers to deliver LNG to South Korea

Figure 2.2 shows a simplified block flow diagram of the project.

2.2 RASGAS ORGANISATION

2.2.1 INTRODUCTION

RasGas is a new company formed in 1993 by Emiri Decree, therefore all staff will be recruited specifically for the operating company. There will be a large number of nationalities employed within the company, as staff will be recruited from Europe, The Middle East, Asia, Canada and USA.



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The Managing Director (MD) has overall responsibility for the Company and has the managers of the following Groups reporting to him:

Administration

Finance

Operations

Technical

Venture

He also has three further functions reporting to him:

Environment and Safety

Legal

Quality Management

2.2.2 OPERATIONS GROUP

The Operations Group is responsible for:

Operations Safety Production (Offshore operations)

Process (Onshore operations)

Maintenance

Materials & Logistics

Planning



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The organigram shown in Figure 2.3 illustrates the structure of the Operations Group.

The Process Manager has a number of sections reporting to him. These are Process Operations, Offsites Operations, Process Planning, QTOPSRas Laffan Liquefied Natural Gas

Company Limited of 77

FIGURE 2.3 OPERATIONS GROUP


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Process Coordination, Laboratory and Fire & Security. Figure 2.4 shows an organigram of the Process Division.

The Production Manager is responsible for all offshore operations which includes all Production Operations, Maintenance and Safety.

The Maintenance Manager has three sections reporting to him. These are Maintenance Onshore, Planning and Services. The Maintenance and Services Sections cover all three craft disciplines i.e. Mechanical, Electrical and Instruments. Figure 2.5 shows an organigram of the Maintenance Department.

The Material and Logistics Manager is responsible for Procurement, Materials Control and Logistics Support.



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FIGURE 2.4 PROCESS ORGANIGRAM


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FIGURE 2.5 MAINTENANCE ORGANIGRAM


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3 OFFSHORE FACILITIES


FIGURE 3.1 OFFSHORE FACILITIES


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3.1 INTRODUCTION

Refer to Figure 3.1.

The main offshore features of the Ras Laffan LNG Project are:

3 Remote Wellhead Platforms and a Central Production, Separation and Treatment Complex which are located 95km offshore, in approximately 67m of water

15 Wells located on 3 Wellhead Platforms. (It is intended to drill further Wells at a later date)

A 32 inch sub-sea pipeline to transport the North Field gas to shore at Ras Laffan

A Flare Platform

A 100 man Accommodation Platform

3.2 CENTRAL PLATFORM COMPLEX

The Central Platform Complex is comprised of the following:

A Process/Utilities Platform

A Riser Platform

Wellhead Platform No. 1 (WP.1)

An Emergency Flare

An Accommodation Platform



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3.3 DESCRIPTION OF THE OFFSHORE FACILITIES

3.3.1 PROCESS/UTILITIES PLATFORM

The process/utilities platform consists of an integrated 2 level deck and a partial upper mezzanine deck supported on an eight leg jacket. The platform accommodates two production trains, each rated at 550 MMSCFD. Each train consists of:

A Single Inlet Separator

Condensate Coalescer

Glycol Contactor

Glycol Regeneration Package

Dry Gas Filter Separator

In addition the PU platform has workshops and maintenance buildings, cranes and the following common utilities facilities:

Process Water Treatment System

Power Generation

Air Compression Facilities

Nitrogen Generator

Fire Water System

Cooling Water System

Fuel Gas System

Open and Closed Drains System

Chemical Injection System



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The platform is designed to process up to 1.1 BSCF/D of wellhead fluids which contain gas, condensate and water. The condensate is de-watered in coalescers and the gas is dried in a glycol dehydration unit. Water produced from these two processes is disposed of overboard after the removal of any hydrocarbons.

3.3.2 RISER PLATFORM

The Riser Platform consists of an integrated 2 level deck supported on a four leg jacket. This platform is bridge connected to the Process/Utilities platform. The main items that are located on the riser platform are:

Intrafield Flowline Control Valves

Connections for a Pig Receiver

Flowline Manifold

Wellhead Production Coolers

High Pressure and Low Pressure Flare Systems

32 Inch Export Pipeline

Export Pipeline Pig Launcher

Export Pipeline Shutdown Valve (SDV)

Open Drain System

The Riser Platform is the central collecting point for the sub-sea pipelines that transport wellhead fluids from the three Wellhead Platforms. The 32 inch export pipeline to the Ras Laffan LNG Plant originates on this platform.



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3.3.3 WELLHEAD PLATFORMS (WP.1, WP.2 & WP.3)

The Offshore Production Facilities comprises three Wellhead Platforms which are located in the North Field Area (NFA). The topsides facilities provided on the Wellhead Platforms are similar in construction, each being of an integrated 3-level deck, supported on a four leg jacket. Wellhead Platform No. 1 (WP.1) has connections to the process/utilities platform for its utilities systems, whereas the other remote Wellhead Platforms have their own independent utilities systems.

Wellhead Platform No. 1 is located close to the Central Platform Complex and is connected to it by a permanent bridge structure. Normal access to and from the platforms is by this interconnecting bridge.

Wellhead Platform No. 2 is located approximately 5.8 km from the Production Platform (PU). Access to the platform will be by boat or helicopter, for which a boat landing and a heli-deck is provided.

Wellhead Platform No. 3 is located approximately 6 km from the Production Platform, access to the platform will also be by boat or helicopter.

Each remote Wellhead is equipped with a:

Production Header

Blowdown Header

Test Separator

Instrument Air Package

Diesel Storage Facilities

Chemical Injection Package

Open and Closed Drainage System



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Electrical Distribution System

Single Craft Heli-Deck and Crane

Fire and Gas Monitoring System (FGMS)

The Wellhead Platforms consist of integrated 2-level topsides with mezzanine decks (Wellhead and Drain) which are supported on four leg jackets. Each wellhead is equipped with surface controlled sub-surface safety valves (SCSSSV), wing and master surface shutdown valves, manual choke valves and automatically operated flow control valves.

Initially, 15 wells will be drilled to support the first two onshore LNG Train, five wells (one vertical and four deviated) will be drilled from each of the Wellhead Platforms.

Each Wellhead Platform has nine available well slots for future development.

The produced fluids (gas/condensate/water) from the Wellhead Platforms are passed through 18 inch gathering lines to the Production Platform. The gathering lines are constructed from carbon steel and are lined with a corrosion resistant alloy (Incaloy 825). The gathering lines and the export pipeline arrive and depart the Offshore Facilities at the Riser Platform.

3.3.4 EMERGENCY FLARE

The flare tower and support platform is of tubular construction with a conventional three leg jacket. The tower supports the flareline and provides access to the flare-tips for maintenance. Both HP and LP flares terminate at the flare platform, each being fitted with pilot and ignition lines. The pilots are equipped with flame-out sensors. The Flare Platform is located down wind to the south of the Central Platform Complex and is connected to the complex by a bridge structure.



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3.3.5 ACCOMMODATION PLATFORM

The platform is located to the north of the Central Platform Complex and consists of an integrated 2 level deck supported on a four leg jacket. It is connected to the Process/Utilities platform by a permanent bridge structure.

The platform consists of:

101 Bed Living Quarters

Central Galley And Dining Facilities

Laundry

Recreational Facilities

Telecommunications Facility

Helideck

Main Control Room (MCR)

The major support facilities located on the Accommodation Platform are:

Diesel Engine Driven Emergency Generator

Diesel Engine Driven Fire Water Pumps

Potable Water System

Washdown Water System

Sewage Treatment Package



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Air Conditioning System

Helicopter Refueling System

Diesel Storage System

Open Drains System

Boat Landings

3.4 GENERAL PROCESS OVERVIEW


Process fluids from the Riser Platform are passed through two parallel process trains on the Process/Utilities Platform. The following description is for Train No. 1, Train No. 2 is identical.

Process fluids at a pressure of 124 bar.a and 43ºC are initially separated in inlet separator V-5501. The function of the three phase separator is to knockout free water carried in from the wellheads. The separated water from the process equipment is passed to an oily water treatment plant before it is disposed of overboard.

Gas, separated in V-5501, passes into glycol contactor C-5601 where it is contacted by a countercurrent flow of lean glycol. The glycol absorbs any remaining moisture, the moisture rich glycol is then regenerated. The dried gas stream from the glycol contactor is then mixed with the dry gas from Train No. 2. A supply of dry gas is taken from this stream for use as fuel to power the gas turbine-driven generators.

Condensate from V-5501 passes through condensate coalescer S-5801 where any entrained water is knocked out. Water is then passed to the oily water treatment plant. The condensate is then mixed with condensate from Train No. 2 before re-combining with the dried gas from Trains No. 1 and No. 2. The combined gas/condensate mixture is passed to the riser platform for transport through the 32 inch main export line to the onshore processing facility.



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FIGURE 3.2 PRODUCTION FACILITIES


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4 ONSHORE FACILITIES


UTILITIES 1/2

COOLING WATER 1/2

CCR

F/H

LAB

COOLING WATER 3/4

FUTURE UTILITIES

SULPHUR HANDLING WWT

TRAIN 1

TRAIN 2

TRAIN 3

TRAIN 4

AGRSRU

AGRSRU

AGRSRU

AGRSRU

STAB

STAB

STAB

STAB

FUTURE 5TH

PROCESS UNITS

FUTURE 6TH

PROCESS UNITS

SLUGCATCHER

REF.STORAGE

ADMINISTRATIONBUILDING

WAREHOUSE ANDDRILLING

SHOREBASE

DRY/WETFLARE

FUTUREFLARE

GTGUTILS

3/4

FIGURE 4.1 ONSHORE PLOT PLAN


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4.1 INTRODUCTION


The function of the onshore process facilities is to receive the combined gas and condensate stream from the 32 inch sub-sea pipeline, separate the combined stream into vapour and condensate, which are then treated in other downstream units to meet product/process specifications. A brief description of the onshore process facilities is given below.

4.2 GENERAL PROCESS OVERVIEW

Refer to Figure4.2

The Process Units are two parallel Liquefied Natural Gas (LNG) units based on APCI (Air Products and Chemicals Inc.) Technology, utilised to produce the desired total LNG of 5.0 Mpta. In addition to LNG, the Process Units produce condensate and sulphur.

The Inlet Facilities receive feedstock from the two phase Feedgas/Condensate Pipeline and provide gas/condensate separation. The gas pressure and temperature are controlled prior to entering The Gas Treating Units, while the Condensate is stabilized, treated for mercaptons and temperature controlledprior to rundown to Condensate Rundown, Storage and Loading.

Feed gas from the upstream Inlet facilities is passed through a Feed Gas Filter Separator Tag No. 11-V001 to ensure there is no liquid carryover into the mercury removal beds and the downstream Sulfinol Absorber.

The Acid Gas Removal Unit (AGR) is designed to remove hydrogen sulfide, carbon dioxide and other sulphur compounds by means of chemical/physical absorption from the gas coming from the Gas Treating Unit.

The sweet gas leaving the Acid Gas Removal Unit is saturated with water. It is dried in the Dehydration Unit using a propane precooler Tag No. 15-E001 followed by molecular sieves. The purpose is to avoid freezing of water in the downstream Gas Chilling and Liquefaction Units.



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The purpose of gas chilling is to remove heavy hydrocarbons from the treated natural gas and then liquefy the natural gas. A Scrub Column removes heavy hydrocarbons which would otherwise freeze in the Main Cryogenic Heat Exchanger (MHE).

The Refrigeration Unit consists of two Refrigerant Systems. A Propane Refrigerant (PR) System providing chilling to about -34ºC, and a Mixed Refrigerant (MR) System comprising Methane, Ethane, Propane, and Nitrogen.

The Nitrogen Rejection Unit flashes off the nitrogen from the LNG product, pumps the LNG product to storage and delivers the nitrogen-rich fuel gas at a pressure of 27.2 bar.a to the Fuel Gas System.

Acid gas from the Acid Gas Removal Unit is processed to convert the hydrogen sulfide (H2S) and other sulphur compounds in the gas into high purity sulphur.

The process facilities are composed of:

Inlet Facilities (Unit 10)

Gas Treating (Unit 11)

Acid Gas Removal (Unit 12)

Dehydration (Unit 13)

Liquefaction (Unit 15)

Refrigeration (Unit 16)

Refrigerant Preparation (Unit 17)

Nitrogen Rejection (Unit 18)

Sulphur Recovery (Unit19)

Each unit is covered in greater detail in the following sub-sections.



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OFFSHOREFACILITIES

InletFacilities

Gas Treating

Acid GasRemoval

Acid GasEnrichment

Dehydration

Gas Chilling &Liquefaction

N2 Rejection

RefrigerationMake-up &

Storage

RefrigerationPreparation

C5LNG Rundown

Storage &Loading

CondensateRundownStorage &Loading

Solid SulphurStorage &Loading

Refrigeration

MoltenSulphur

Storage &Loading

OFFSHORE

ONSHOREFieldCondensateUntreated Gas

H2S

C2 & MRRef.

C2 Ref.

C2 & C3

Condensate SolidSulphur

Sweet Gas

Dry Gas

ONPLOT

OFFPLOT

366 MT/H 23,000 BBL/D 155 T/D

2 Train Operation1.0 BCF/D Gas

45,000 BBL/D Condensate

SulphurRecovery

Make-up

CondensateTreating/

Stabilisation


FIGURE 4.2 PROCESS FLOW BLOCK DIAGRAM OF LNG PRODUCTION


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FIGURE 4.3 BLOCK DIAGRAM OF INLET RECEPTION


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4.2.1 INLET FACILITIES (UNIT 10)


The 2-phase well stream feed arrives at the Inlet Facilities via the 32 inch sub-sea pipeline and is passed to slug catcher 10-X 002. The slug catcher operates at 75 bar.a and between 15 to 35°C dependent on ambient seawater temperature.

The gas exits the slug catcher and its pressure is reduced at a pressure let down station controlled by 10-PC-9A/B. The gas then passes through product gas knock-out drum 10-V005, gas/condensate exchangers 10-E004 A/B and the feed gas metering skid 10-V001 to the feed gas filter separator Tag No. V001(Unit-11).

The separated condensate from the slug catcher (refer to Figure 4.4) is passed via slug catcher filter 10-S001 A/B into pre-flash drum 10-V001. This drum is sized to effect a 3-phase separation. Any water removed in the drum is passed to the sour water header for further treatment. Condensate from the pre-flash drum passes into the condensate stripper 10-C001 where two steam heated reboilers are used to achieve the condensate product specification.

The offgas from both the pre-flash drum and the condensate stripper are passed to the offgas compressor system which is a 2 stage motor driven unit (refer to Figure 4-5). The compressed gas is re-combined with the primary gas stream, down stream from the pressure let down station.

Condensate from stripper 10-C001, is cooled in precooler 10-E003 and gas/condensate exchanger 10-E004 A/B before entering condensate degassing drum 10-V006. The condensate from the degassing drum is pumped by field condensate pumps 10-P107 A/B through a merichem treatment plant that converts the foul smelling mercaptons into disufdes. The condensate flow passes through 5 contactor/seperator vessels where the condensate is contacted, or washed, with circulating caustic soda. The condensate is finally degassed before being rundown to



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storage tanks 10-T001 ABC. Condensate is recycled to 10-C001 and 10-V006 to maintain minimum levels in the vessels.


FIGURE 4.4 PROCESS FLOW FOR INLET SEPARATION


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FIGURE 4.5 OFF GAS COMPRESSION


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4.2.2 GAS TREATING (UNIT 11)



FIGURE 4.6 MERCURY REMOVAL


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The feed gas from Unit 10 contains small quantities of mercury which is corrosive to aluminium and freezers in the MHE. Because the main cryogenic heat exchanger is fabricated from this material, the feed gas must be treated to remove the mercury.

The mercury removal process consists of one activated carbon mercury removal bed 11-V001. The carbon bed is also impregnated with sulphur. As the North Field gas contains low concentrations of mercury, the removal bed is expected to have an operating life of approximately five years.

Field gas entering Unit 11 for mercury removal is pressure controlled by 12-PV278 before entering feed gas filter separator 11-V001. This vessel removes any entrained condensate from the feed gas, condensate is passed back to the pre-flash drum Tag No.10-V001 on Unit 10. Dried gas from the filter separator passes into feed pre heater 11-E001 which is steam heated.

Heated gas from 11-E001 then passes through mercury removal vessel 11-V002 which is packed with activated carbon. Flow through the bed is from the top of the vessel to the outlet situated at the bottom. Two mercury removal effluent filters 11-S001 A/B located on the gas outlet line remove any activated carbon dust particles. Treated gas is passed to the acid gas removal unit (Unit 11).



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FIGURE 4.7 ACID GAS REMOVAL


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4.2.3 ACID GAS REMOVAL (UNIT 12)


The acid gas removal unit removes H2S, mercaptans, CO2 and other sulphur compounds from the feed gas. The H2S and mercaptans are poisonous and corrosive. The CO2 is removed to eliminate the possibility of it freezing and plugging the small diameter tubes in the Main Cryogenic Heat Exchanger.

The gas sweetening process chosen for RasGas is the Shell Sulfinol Process which is the most appropriate method for removal of the specified impurities.

Feed gas (rich in impurities) passes into the Sulfinol Absorber Bottoms 12-C001and rises to the top of the vessel, passing through a number of trays. The rising gas is contacted by a counter current flow of lean sulfinol which passes downward over the trays.

The rising gas, now stripped of H2S Co2, passes overhead and is passed to the water wash column 12-C005 where any traces of sulfinol carried overhead are absorbed by water washing. The gas, now wet, is passed to Unit 13 for dehydration.

The sulfinol, which is now rich in impurities passes into the rich sulfinol Flash Drum 12-V003 where some of the entrained gases flash off. The gases pass upwards through the recontactor and are washed by a decending flow of lean sulfinol which absorbs any H2S/C02. The gas then passes to unit 93 (fuel gas) for further treatment. The sulfinol exits the flash drum and passes through lean/rich exchangers 12-E003 A/B/C/D/E/F and into the sulfinol regenerator 12-C002.

The sulfinol regenerator, heated by steam reboilers 12-E007 A/B, drives off the remaining H2S and Co2 from the sulfinol solution. The regenerated sulfinol is recirculated to the absorber 12-C001 to perform its function again.



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FIGURE 4.8 DEHYDRATION


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4.2.4 DEHYDRATION (UNIT 13)


Wet gas, from the sulfinol water wash column Unit 12, must first be dried to avoid water freezing in the cryogenic heat exchanger. Unit 13 removes water from the feed gas down to less than 0.1 ppm (parts per million), this is achieved by pre-cooling with propane and adsorption by molecular sieve driers.

The wet gas first passes through the tube side of drier/precooler 15-E001 (propane chiller) where the gas/water vapour is cooled. Condensed water is removed in drier precooler separator 13-V003 and is passed to the effluent treatment unit (Unit 87). Any small amounts of hydrocarbons that also condense are passed to wet liquid disposal.

Gas from 15-E001 passes through molecular sieve driers (two on line, one on regeneration/standby). Heat to regenerate the saturated beds is provided by waste heat recovery units situated in the propane refrigeration gas turbine exhaust ducts. The molecular sieves also provide mercury and mercaptan polishing. (ie. Removal of the last traces of these impurities)

Under normal operating conditions the molecular sieves are regenerated after eight hours service, the timing sequence of drying, regeneration and standby can be adjusted to suit operational requirements.



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FIGURE 4.9 GAS CHILLING AND LIQUEFACTION


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4.2.5 LIQUEFACTION (UNIT 15)


Before liquefaction, the dry, sweetened gas, is chilled using medium and low pressure propane evaporators respectively. This cooling, typically to -25ºC, causes the heavy hydrocarbon liquids to condense. These liquids provide feed to the fractionation section of the LNG plant.

The fractionation section, is used primarily to provide make-up to the refrigerant loops but also supplies a feed to the Main Cryogenic Heat Exchanger (MHE). The separation of these heavy hydrocarbon liquids, referred to as ‘heavy ends’, occurs in a distillation column called the Scrub Column (Tag No.15-C001).

This column has a steam-heated reboiler. The reflux introduced at the top of the column is obtained by cooling and partially condensing the overhead vapour product in a separate heat exchanger located in the ‘warm’ section of the MHE.

The liquefaction of the gas is carried out in the MHE. The feed gas is cooled, liquefied and sub-cooled in this exchanger by a process of heat exchange with a cold mixed refrigerant. The mixed refrigerant is composed of a mixture of methane, ethane, propane, and nitrogen.

The mixed refrigerant vapour from the base of the MHE is compressed, cooled firstly with cooling water and then with propane. It is then collected in the Mixed Refrigerant Separator at -25ºC.

Liquid MR from the MP MR Separator is fed to a coil which passes through the warm and middle bundles in the middle where it is chilled by decending MR in the shell. The cold MR liquid from the coil is flashed across a J.T. Valve into the column shell providing chilling to the coils.

The vapour flow from the the HP/MR separator splits into two streams, one stream passes through the MR/Flash Gas Exchanger, the second stream passes through the MR coils of the MHE. The two streams, now supercooled pass through J.T. Valves into the shell of the MHE as a supercooled vapour/liquid mixture.



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The feed gas is liquefied in the feed coils at -130ºC to -140ºC and is sub-cooled in the cold bundle of the MHE to a temperature of -149ºC at a pressure of 18 bar.g.

4.2.6 REFRIGERATION (UNIT 16)


The function of the Refrigeration Unit is to provide refrigeration to:

Pre-cool and liquefy the natural gas

Provide reflux to the De-ethaniser and Scrub Column

Cool the reinjected Liquified Petroleum (or propane) Gas LPG

The Refrigeration Unit consists of two refrigerant systems, a propane refrigerant (PR) system and a mixed refrigerant (MR) system. Both refrigeration compressors are driven by G.E. Frame 7 Gas Turbines.

The main objective of the Refrigeration Unit is to maintain the temperature approaches on the warm and cold ends of the Main Cryogenic Heat Exchanger and produce approximately 366 t/h of LNG during summer operation.

The colling system in the LNG Plant utilizes 4 cooling meduims, salt water, fresh water, propane and MR which provide water cooling to 35°C, propane colling to -34°C and MR cooling to -150°C.

In the APCI LNG process, refrigeration is provided by propane and mixed refrigerant loops.

The propane loop, which provides cooling to -34ºC, contains a centrifugal compressor driven by a Frame-7 gas turbine. Propane vapour at different pressure levels is drawn into the propane compressor where it is compressed. The hot propane vapour is passed through propane desuperheaters and condensers which are cooled by fresh water.



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The liquid propane is stored in the Propane Accumulator. Liquid propaneis supplied to the propane exchangers in the process at different pressure levels resulting in different temperature levels down to -34ºC.

The second refrigerant loop is the mixed refrigerant loop (containing methane, ethane, propane and nitrogen). The inventory of this loop and the power requirements are significantly larger than for the propane loop. A two stage compressor is used, driven by a Frame-7 gas turbine driver. Freshwater cooling is supplied to the Low Pressure MR Aftercooler and High Pressure MR Aftercooler. Propane is then used to cool the MR in a series of three MR/Propane Evaporators before it is passed to the HP MR Separator.

The MR vapour contains methane, ethane and nitorgen, the MR liquid contains ethane and propane.



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FIGURE 4.10 PROPANE REFRIGERATION


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FIGURE 4.11 FRACTIONATION


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4.2.7 REFRIGERANT PREPARATION (UNIT 17)


The function of the Refrigerant Preparation Unit is to produce ethane and propane in both quantity and quality for use as refrigerant make-up. In order to produce these refrigerant components three fractionation columns are employed:

De-ethaniser

De-propaniser

De-butaniser

De-isopentanizer

The ethane and propane products supply refrigerant make-up which is stored in Refrigerant Make-up and Storage (Unit 72). If the refrigerant storage tanks are full, the ethane and propane will be passed to the Main Cryogenic Heat Exchanger for liquefaction as part of the LNG. All of the butane will be liquefied as part of the LNG. The Debutaniser bottoms product is routed to the de-isopentanizer to remove isopentane, after which the de-isopentanizer bottoms (condensate) will be routed to the Plant condensate storage tanks.

Scrub Column bottoms (Unit 15) supply the feed to the Refrigerant Preparation Unit where the three fractionation columns operate in series, the bottoms from the first column supplying the feed to the second and the second to the third etc. The overheads from the three columns are the ethane and propane streams used as refrigerant make-up.



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FIGURE 4.12 NITROGEN REJECTION


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4.2.8 NITROGEN REJECTION (UNIT 18)


The function of the Nitrogen Rejection Unit is to flash off the nitrogen from the LNG product and deliver the nitrogen rich gas to the fuel gas system.

The LNG stream leaving the Main Cryogenic Heat Exchanger is flashed across a J-T valve. The resulting 2-phase stream is then separated in the LNG Flash Drum which reduces the nitrogen content of the LNG to 1.2 MOL %.

The LNG product from the Flash Drum is pumped to the LNG Storage Facility (Unit 71). The vapour, released in the flash drum, is warmed in the Fuel Gas/MR Exchanger by high pressure mixed refrigerant (MR). The flashed gas is compressed in an LP Fuel Gas Compressor (2 stage) and an H.P. Fuel Gas compressor, also 2 stage. The compressed gas is passed to the fuel gas system (Unit 93).



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FIGURE 4.13 SULPHUR RECOVERY


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4.2.9 SULPHUR RECOVERY (UNIT 19)


The function of the Sulphur Recovery Unit is to recover 95% of the sulphur, contained in the acid gas feed from the Acid Gas Removal Unit (Unit 11). The liquid sulphur produced must be degassed down to an H2S content of less than 10 PPM by weight.

The Sulphur Recovery Unit consists of the following:

Acid Gas Enrichment

Reaction Furnace

3 Sulphur Condensers

2 Claus Reactors

Tail Gas Recovery

Tail Gas Incineration

Each identical Sulphur Recovery Unit has a design capacity of 155 T/D sulphur production. The sulphur produced is drained into the sulphur pit where it is degassed. The tail gas exiting the selective oxidation stage, as well as the sulphur pit vent gas are sent to the thermal tail gas incinerator.

The Sulphur Recovery Process applied, known as the Claus process, is based on the partial combustion of hydrogen sulphide (H2S), successively followed by two (2) catalytic Claus reactor stages and a stage where the remaining H2S is selectively oxidized with air. The partial combustion of H2S at the front end of the unit is achieved by means of a ratio controlled flow of air.



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4.3 OFFPLOT FACILITIES

The Offplot Facilities are located approximately 4 kilometres from the main processing area and include:

LNG Rundown, Storage and Loading (Unit 71)

Condensate Rundown, Storage and Loading (Unit 73)

LNG Loading Berth (Unit 74)

Solid Sulphur, Storage and Loading (Unit 77)

Seawater System (Unit 82)

4.3.1 LNG RUNDOWN, STORAGE AND LOADING (UNIT 71)

From the Flash Drum, Tag No. 18-V005, LNG is pumped to storage by LNG Product Pumps at a temperature of minus -162ºC. The sub-cooled LNG from Trains 1 and 2 is run down to the tanks via one Product Rundown line.

The rundown system design pressure is the same as the design pressure of the loading system, 30 bar.g, because under certain operating conditions the systems are inter-connected.

During LNG loading into ship, approximately 50% of LNG product will by-pass the LNG Flash Drum. This will compensate for the deficiency of vapour in the LNG Storage Tanks resulting from the LNG being pumped out.

If both LNG Product Pumps fail, 100% of the LNG Product will by-pass the LNG Flash Drum. In this case, LNG is flashed into the storage tanks, and a large amount of the Boil Off Gas (BOG) is produced.

From the rundown header, the LNG is flashed into LNG Storage Tanks 71-T001, 71-T002 and 71-T003 in parallel through individual rundown leads. Each tank capacity is 140,000 m³, (the largest of their type in the



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world for hydrocarbon storage). LNG Tanks 71-T001 and 71-T002 are provided for Train 1 and Tank 71-T003 is provided for 2 Train operation.

The LNG tanks are above ground type. Each tank has a pre-stressed concrete outer wall with a reinforced concrete roof and a separate 9% nickel steel inner tank. Refer to Figure 4.14.

The LNG loading system is designed to transport LNG from the storage tanks to the ship. The system consists of loading and circulation lines which traverse the distance of approximately 3 km between the LNG storage tanks and the LNG Jetty head.



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FIGURE 4.14 LNG STORAGE TANK


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FIGURE 4.15 LNG STORAGE AND LOADING


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FIGURE 4.16 CONDENSATE STORAGE AND LOADING


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4.3.2 CONDENSATE RUNDOWN, STORAGE AND LOADING (UNIT 73)

The Condensate Rundown, Storage, and Loading Facilities consist of condensate storage tanks, condensate loading pumps, condensate rundown line from the Inlet Facilities (Unit 10) and a condensate loading line which ties into Qatargas’s ship loading facilities.

The Qatargas Condensate ship loading facilities shall be co-used by Qatargas and RasGas. Ship loading facilities consist of a 28 inch ship loading line, two loading arms, platform drain drum, pump and the associated control room, power supply and fire fighting system.

The switching between the Qatargas and RasGas loading operations is achieved by interlocking the appropriate motor operated valves on the two loading systems. The Ras Laffan condensate loading line from Ras Laffan loading pumps ties into a tee on the discharge piping of the Qatargas loading pumps.

The stabilized condensate from Inlet Facilities (Unit 10) flows into one of the Condensate Storage Tanks which are floating roof type, having a nominal capacity of 58,000 m³ each with tank mixers of propeller type. Condensate is transferred from the tanks to the loading berth by Condensate Loading Pumps at a loading rate of 4,000 m³/h. Two pumps are operated with a third on standby.

The Condensate Loading Pumps have a rated capacity of 2,000 m³/h. Minimum flow lines with flow control valves are provided around these pumps due to their high rated capacity. Refer to Figure 4.16.

4.3.3 LNG LOADING BERTH

LNG is circulated through LNG Circulation Pumps to maintain all LNG lines at -160°C. Each tank is equipped with one LNG Circulation Pump. In the event a Circulation Pump fails one of the four LNG Loading Pumps may be used temporarily.

There are two modes of circulating LNG in the loading lines and tank leads: Long circulation and short circulation. Long circulation sends LNG from the storage tank to the loading jetty and back to the storage



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tank, short circulation is used to mix the contents of the LNG storage tanks if layering of the LNG product occurs.

One LNG loading berth has been constructed for RasGas, however there are interconnecting lines between RasGas and QatarGas loading systems. This interconnection will allow both companies to use either of the dedicated LNG loading berths. Upon arrival and connection of the loading arms, a slip stream of LNG is used to cool the loading ships manifold. Full loading commences when the cooling operation is completed. Both the LNG circulation pumps and the LNG loading pumps are on flow control, and are equipped with minimum flow control valves.

4.3.4 SOLID SULPHUR, STORAGE AND LOADING (UNIT 77)

Sulphur loading will utilise common facilities with Qatargas. The sulphur granules are loaded into trucks and are then carried down to the Ras Laffan Port Area for export by ship. The trucks unload the granulated sulphur at the Port onto a Receiving Storage Conveyor. This transports the sulphur into the Storage Hall.

The sulphur is then transported via a series of conveyors to the Travelling Shiploader, which dumps the sulphur into the ship's hold via a Telescopic Spout.

4.3.5 SEAWATER SYSTEMS (UNIT 82)

Seawater is used as the cooling medium in a once through arrangement and as feed water to the desalination units. The seawater system consists of the following sections:

Seawater Intake

Seawater Distribution

Seawater Outfall



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The intake facilities are located at the Ras Laffan Harbour about 6 km from the LNG plant. The intake is designed for the operational cooling water demand, and utilities requirements to accommodate 2 Train Operation. Seawater (maximum temperature: 35ºC, minimum temperature: 15ºC) is drawn from the harbour through three parallel channels which supply a common pump bay.

After passing through open inlet sluice gates, seawater passes through fixed Bar Screens which remove coarse debris. The seawater then passes through Fine Screens which are electrically driven, rotary screens. These screens provide fine filtration of the inlet seawater.

To control marine growth throughout the Seawater System, Sodium Hypochlorite solution from an Electrochlorination Package is continuously injected both upstream of the bar screens and into the pump bay. After passing through the channels the seawater flows into the pump bay, which is designed to supply the operating demand of fire water, cooling water and utility requirements for two Train operation.

The forebay contains six (6) unitised pump bays. Of these, four (4) contain Seawater Pumps for two Train operation; one bay is used for fire water pumps, and the remaining pump bay is reserved for future expansion. The seawater pumps are vertical mixed flow pumps driven by electric motors. Two pumps satisfy the demand of Train 1 and utilities requirements, while a third pump is a spare.

The pump station contains all seawater and fire water pumps, pump motors, mechanical and electrical equipment, electrochlorination unit, pipework and valves. The main seawater supply lines are laid above ground between the intake structure and the plant battery limit. Inside the plant battery limits, the supply lines are located underground to facilitate equipment access.

Seawater returns brine effluent from the desalination units and treated effluents from Unit 87 discharge into a seawater outfall weir, which is located outside the plant. Sea water from the outfall weir flows into an outfall channel to the sea.



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4.4 UTILITIES SYSTEMS

4.4.1 POWER GENERATION/DISTRIBUTION (UNIT 91)

The Power Generation and Distribution Facility will satisfy the power requirements of the RasGas Onshore LNG Plant and its associated ancillaries. Four Gas Turbine Generators (GTGs) provide the necessary electrical power for the LNG train facilities over a wide range of operating and environmental conditions.

Plant electrical loads include the LNG process trains, the LNG/Condensate storage and loading facilities, utilities, offsites, marine jetty and the administration and warehouse area.

The main power generation is located in the Utility area. Generator drivers are GE Frame 6 gas turbine units which are equipped with electric starter motors. Number four gas turbine is fitted with a supplementary fired, Heat Recovery Steam Generator (HRSG).

During normal operating conditions the gas turbine equipped with HRSG will be base loaded to maximise steam production by heat recovery from the gas turbine exhaust. The other three gas turbines, exhausting to atmosphere, will operate as two on line, one on standby.

A load shedding system is provided to ensure that power to selected loads is maintained in the event of a system fault or partial loss of generation. Load shedding priorities are based on safety considerations and process requirements. For selected motors, sequence of restart shall be controlled from individual motor starters equipped with automatic restart modules.

Electrical power, generated at 11 kV 50 Hz stepped up to 33 kV through captive transformers, is fed to the main 33 kV switchgear in the Main Substation. Electric power is distributed from the 33 kV switchgear to the following substations using 33 kV underground 100% redundant feeders:



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Each GTG is controlled by a GE Speedtronic Mark 5 control system. “Local” GTG controls, except for Generator Control Panels, are located in vendor supplied local control cabinets and Generator Accessories Compartments, with duplication of control and monitoring capability in the Central Control Building. The Generator Control Panel is located in the Main Substation.

An ELICS is provided and contains Video Display Units that display One-line diagrams, alarms, operating data etc. The operator console has the capability to start and stop the main and essential generators, monitor all power system parameters down to the 415 V level, and control all breakers down to 6.6 kV.

An essential power system shall be provided to ensure continuous operation of critical equipment and systems during a total outage of the main power generation system. The system shall also supply black start power for the plant start-up and after a complete power outage.

The essential power facilities are located at the Utility Plant. They are provided with two diesel engine driven, essential power generator set, SS capable of supplying the total essential power requirements for the two LNG trains. The essential power switchgear is located in the Main Substation SS-01. The essential power system is self-contained and suitable for continuous operation. Essential generators have the capability of synchronizing to main power at the switchgear for transferring load and testing.

Power to critical instruments and control systems is supplied from redundant uniterruptible power supplies, (UPS), comprised of rectifier-chargers, inverters, static transfer switches, and battery backup systems. Battery chargers for UPS systems are connected to the essential power system.

A separate UPS system is provided for each instrument and telecommunication control system and main control room. UPS batteries are rated for 60 minutes at full load. Telecommunication UPS batteries are rated for 6 hours at full load.



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4.4.2 STEAM AND CONDENSATE SYSTEM (UNIT 92)

The Steam and Condensate System consists of steam, condensate recovery and return, deaerators, boiler feedwater pumps, packaged boilers, steam letdown (pressure reducing and desuperheating), and process waste heat steam generation. Heat Recovery Steam Generators (HRSGs) are physically located in Unit 91 on the gas turbine exhausts.

Two makeup water streams feed two deaerators which operate in parallel and mechanically deaerate boiler feedwater to an outlet specification of 7 ppb dissolved 02. One stream is clean steam condensate recovered from the process units which is pumped back to the deaerators at 100ºC. Contaminated condensate, as determined by TOC (Total Organic Carbon) analyzers and manual sampling, is dumped to the oily water sewer.

The condensate splits into two streams and is merged with softened water at 43ºC from the Softened Water Units. The combined makeup water stream enters the deaerator heater section where the dissolved gases (02 and C02 are removed by contact with steam from the LP Steam header. The non-condensible gases are vented from the deaerator along with a small quantity of carrier steam. Deaerated water flows into the deaerator storage drum. Sodium Sulfite is injected to ensure that the low dissolved oxygen level is maintained.

Two boiler feedwater pumps, one turbine driven and one motor driven, take suction from the deaerator storage drum and distribute boiler feed water to the users. Normally the turbine driven pump will operate. The motor driven unit starts automatically on low boiler feedwater header pressure.

The utility plant letdown station generates LP steam at 5.5 bar.a and 165ºC by reducing the pressure of MP steam and desuperheating with boiler feedwater. LP steam is also generated by letting down through the steam turbine drivers of the Boiler Feedwater Pump and Softened Water Pump.



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The Sulphur Recovery Units (SRU) 19 and 29 in the process area are producers of high, medium and low pressure steams. Low pressure steam is produced in the Sulphur Condensers and the MP Condensate

Flash Drums. About 60% of this LP steam is supplied to the users in the AGR and the SRU Units.

Low pressure condensate is collected in the Condensate Flash Drums and transferred to the Utility Condensate System. MP and LP steam are collected in MP and LP steam headers and distributed to the users throughout the LNG facilities.

4.4.3 FUEL SYSTEMS (UNIT 93)

Fuel gas sources for normal operation of the LNG Plant are as follows:

Boil-Off Gas (BOG) leaving the LNG Storage and Loading Unit

Fuel-From Feed (FFF) taken from the Molecular Sieve Bed Afterfilter

End-Flash Gas (EFG) from the Fuel Gas Compressors, in the Nitrogen Rejection Unit

HP Flash gas from the HP Sulfinol Recontactor, in the Acid Gas Removal Unit

Feed gas from the Metering Skid, in the Inlet Facilities Unit

BOG, combined with FFF, is heated to 60ºC by LP steam in the LNG train area and exits the train on pressure control. The major portion of the combined BOG/FFF gas is passed through a Mixing Drum and used as the primary fuel for the power generation GTGs at the Utility Plant.

EFG from the Fuel Gas Compressor Aftercooler, heated to 43ºC by LP Steam, provides fuel gas for the GE Frame 7 gas turbines in the LNG Trains. HP Flash Gas from the Sulfinol Recontactor, provides most of the fuel gas to the SRU, the Utility Plant Packaged Boilers and the



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HRSG. Fuel gas for the Packaged Boilers and HRSG duct burner exits the LNG Train, mixes with the balance of the BOG/FFF in the Fuel Gas Mixing Drum and is passed to the Packaged Boilers and HRSG.

The Sulphur Recovery Units consume fuel gas in the Main Burners, No. 1, 2 and 3 Line Burners and the Incinerator Burner during normal operations. During normal operation HP flash gas from the HP Recontactor in the Acid Gas Removal Units is utilized as the fuel gas source, via the Fuel Gas Drum, to process users described above. Remaining HP flash gas is exported to the Fuel Gas System, via the Fuel Gas Mixing Drum for use as boiler fuel.

Fuel Gas Source for Black Start is from the North Field Phase-1 Pipeline (domestic gas). Sufficient fuel gas is provided to start two power generation GTGs and two Packaged Boilers.

The Diesel Fuel System consists of a Diesel Fuel Day Tank and a Diesel Fuel Filter.

All diesel users have their own dedicated diesel fuel day tank which will be supplied by diesel road tanker. Diesel fuel day tanks are provided for the following users:

Essential Power Generators

Fresh Fire Water Pump Drivers

Seawater Fire Pump Drivers

Diesel Fuel Day Tank For Local Use (Trucks and Cranes)

4.4.4 FRESH WATER SYSTEMS (UNIT 94)

Refer to Figure 4.17

The Fresh Water Systems consist of Desalination Water System, Service Water System, Potable Water System, Demineralised Water System, Softened Water System and Fresh Cooling Water System.



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The Desalinated Water System consists of Desalination Units, Desalinated Water Tanks and Desalinated Water Pumps. A hydrocarbon analyzer is provided on the feed water lines to detect any hydrocarbon contamination in the seawater. This analyzer sends an alarm to the Central Control Building and isolates the Desalination Units by closing upstream isolation valves to prevent ingress of contaminated feed water into the fresh water system.

Feedwater to the two Desalination Units is seawater from the seawater supply headers to the Fresh Water Cooling area. A chemical injection package injects a dechlorination chemical into the common feed water header to the Desalination Units. After chemical injection the header splits to feed seawater to the Desalination Units.

Distillate (desalinated water) formed in the evaporative units is collected and pumped by motor driven distillate pumps to two Desalinated Water Tanks. A conductivity analyzer is provided on the outlet of the Desalination Units with a high conductivity alarm in the Central Control Room (CCR).

Reject brine is collected and pumped by motor driven brine pumps to the Seawater Outfall for disposal with the seawater from the Fresh Cooling Water Area.

Desalinated Water at 7.0 bar.a and 43ºC, is pumped to the following locations:

Remineralisation Unit

Fresh Fire Water Tank

Softener Unit

Service Water System Header

Irrigation Water Tank



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Demineraliser Unit

The service water system supplies water for the utility hose stations, sanitary use in various buildings in the Plant area, gas seals in manholes in the Plant, and as dilution water for contaminated condensate dump to the Oily Water Sewer. The service water header is fed from the desalinated water supply header.

The potable Water System consists of the Remineralisation Unit, Potable Water Storage Tanks, and Potable Water Pumps. The capacity of this system is independent of the number of LNG trains.

Feedwater to the remineralisation Unit is desalinated water. Carbon Dioxide gas is injected into the common feed to lower the pH. The feed then splits to two remineralisation beds. After remineralisation, a hypochlorite solution is injected into the common outlet for biological control. Chlorinated potable water at 5.0 bar.a and 43ºC is then passed to the Potable Water Tanks.

The Demineralised Water System consists of the Demineralization Unit, a Demineralised Water Storage Tank, and Demineralised Water Pumps. This system is sized, based on Online and Offline cleaning of a single gas turbine at a time (Frame 7s and Frame 6s).

Feed water to the Demineralization Unit is desalinated water. The feed splits to two Mixed Bed Polishers. After passing through the Mixed Bed Polisher, the demineralised water at 5.0 bar.a and 43ºC is passed to the Demineralised Water Storage Tank. A conductivity analyzer is provided on the outlet of the Demineralization Unit with a high conductivity alarm in the main control room.

From the storage tank, the Demineralised Water Pumps transfer Demineralised Water at 8.5 bar a and 43ºC to the online Gas Turbine

Cleaning Water Header and to the Offline Cleaning Water Drum. Cleaning agents are manually added to the drum. Offline Cleaning Water Pumps circulate offline cleaning solution which is heated by LP Steam.



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The Softened Water System consists of the Water Softener Unit (Zeolite Softeners complete with brine Regeneration System), Softened Water Storage Tanks and Softened Water Pumps.

Feedwater to the Softener Unit is desalinated water. The feed splits to three softeners. After passing through the Softener Unit, Softened Water at 5.0 bar.a and 43ºC is passed to the Softened Water Tanks. A hardness analyzer is provided on the outlet of the Softener Unit with a high hardness alarm in the main control room.

From the storage tanks, the Softened Water Pumps transfer Softened Water at 7.0 bar.a and 43ºC to the following locations:

Chemical Injection Systems at the SRU

Deaerators

Fresh Cooling Water Storage Tanks

The Fresh Cooling Water System consists of Fresh Cooling Water Tanks, Fresh Cooling Water Pumps and Fresh Cooling Water Coolers. Each LNG train is provided with a dedicated Fresh Cooling Water Tank, pumps and coolers. Provision for upstream and downstream cross connections between each fresh cooling water system is provided for flexibility

Makeup water to the Fresh Cooling Water System is Softened Water to the Fresh Cooling Water Tanks. Fresh Cooling Water Pumps take suction from a common header which is fed by the cooled Fresh Cooling Water Return, the Fresh Cooling Water Coolers and the Fresh Cooling Water Tanks.

The Fresh Cooling Water Pumps circulate fresh cooling water at 6.3-6.9 bar.a and 38ºC to the LNG trains, the Condensate Stabiliser, the Acid Gas Removal Unit, and the Utility Plant. A Fresh Cooling Water Start-up Pump is provided to fill the system and serve limited users on initial start-up.



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Fresh Cooling Water Return at 2.5 bar.a and 47.3ºC is cooled by once-thru seawater in the Fresh Cooling Water Coolers and passed directly to the Fresh Cooling Water Pump Suction Header.

Hydrocarbon gas detectors are provided on the vents from the Fresh Cooling Water Tanks to indicate hydrocarbon leakage from the process into the Fresh Cooling Water System.



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FIGURE 4.17 WATER SYSTEMS


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4.4.5 COMPRESSED AIR SYSTEMS (UNIT 95)

The Compressed Air System consists of air compressors, wet air receivers, air dryers, instrument air receivers, and an extraction system for using GTG compressed air.

Compressed air is extracted, on pressure control, from the gas turbines in power generation service, manifolded together, cooled by Extracted Air Coolers and passed to the Extracted Air Receivers, at 8.8 bar.a and 48ºC.

Compressed air, on pressure control, from two Air Compressor Packages, is passed to Wet Air Receivers at 10.3 bar.a and 48ºC. From the Extracted Air Receivers, compressed air flows to the Air Dryers at 8.6 bar.a and 48ºC. Dry air from the Air Dryers is passed to the Instrument Air Receivers at 8.0 bar.a and 48ºC. Dry compressed air from the Instrument Air Receivers feeds the Instrument Air System and the Service Air System. A shutoff valve is provided on the feed line to the Service Air System to cut the feed to that system on low air pressure (7.5 bar.a) in the Instrument Air Receivers.

From the Wet Air Receivers compressed air flows to the Nitrogen Plant. A shutoff valve is provided on the feed line to the Nitrogen Plant to cut the feed to the plant on low air pressure (7.3 bar.a) in the instrument Air Receivers.

4.4.6 NITROGEN SYSTEMS (UNIT 96)

The Nitrogen production plant consists of two Liquefaction Packages (cryogenic air separation process). The packages can produce both gaseous and liquid nitrogen from the compressed air which is fed to them. Nitrogen gas from the packages flows directly into the nitrogen distribution system. Liquid nitrogen is stored in tanks for later vapourisation when the demand for nitrogen gas is high.



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4.4.7 OFFPLOT UTILITIES (UNIT 99)

The offplot areas which require utilities supply are as follows:

LNG Storage Tanks and BOG Compressor (Unit 71)

Seawater Intake (Unit 82)

LNG Loading Jetty (Unit 74)

Condensate Storage Tanks (Unit 73)

Instrument air is supplied to all users of instrument and plant air in the Offplot areas. Remote instrument air holder vessels are provided in the LNG Storage and BOG Compressor Area, LNG Jetty Area, Seawater Intake Area and Condensate Storage Area. An automatic shutdown valve provided on the service air header maintains air pressure in the instrument air holder vessels.

Potable water is supplied to LNG Storage, LNG Jetty, Seawater Intake and Condensate Storage areas as a source for potable and service water.

Nitrogen in a vapor form is supplied from onplot LNG Plant Area to LNG Storage and BOG Compressor Area, Condensate Storage Tank Area and LNG Jetty Area. Nitrogen Holders (buffer tanks) are provided in LNG Storage and Jetty Areas.

Diesel fuel oil is required only at the Seawater Intake Structure for the diesel engine driven sea fire water pumps. Diesel fuel oil is supplied by a diesel fuel tank truck.

Fuel gas is required at the Offplot facilities for LNG tankage and jetty flare. The fuel gas can be supplied from the Boil Off Gas (BOG) system and the LNG circulation when the LNG plant is in operation. LPG bottles shall be provided for initial start up and as a backup to light off the pilot and the flare.

Steam is not supplied to the Offplot areas. Electric heat tracing is sued for heating instrument and instrument piping.



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5 FIRE PROTECTION AND SAFETY

5.1 GENERAL

The fire protection systems provided for the LNG facilities are self sufficient without any outside support. The systems are capable of dealing with any potential fire source release and fire hazard. Automatic and/or remote actuation capability for fire protection from the fire station and the local control room are provided to minimise fire fighting manpower requirements. The facilities handling LNG/LPG are furnished with all necessary protection to cover all possible hazard scenarios such as gas release without fire, liquid release without fire, torch fire and pool fire.

The following protection systems are provided:-

Fire and Gas Detection

Fire Hydrants

Fixed Fire Monitors

Oscillating Fire Monitors

Fire Water Sprays

High Expansion Foam Systems

Dry Chemical Fire Suppresent Systems

Fire Proofing (Buildings and Steelwork)

Personal Protective Equipment

5.2 FIRE WATER SUPPLY

Fresh Water is used as the primary source of water for fire protection with seawater as a back-up source, the fire water system consists of a fresh water piping grid covering all Onplot and Offplot areas.

A Fire Water Storage Tank, (fresh water) has the capacity to hold maximum fire water demand for four (4) hours is provided to fight a major single fire.



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Provision is made to supply desalinated water from the Desalinated Water Storage Tanks to this fire water storage tank to keep it full. A back-up seawater connection from the seawater cooling lines is provided to this tank. Seawater Fire Pumps are operated only when the Seawater Pumps are not in operation and fresh fire water storage for four (4) hours is depleted.

A direct connection from the Seawater Fire Pumps, is provided to the fresh fire water piping main. This supplies seawater as backup fire water to Condensate Storage, LNG Storage and LNG Jetty Areas. This will allow isolation of any single area without loss of fire water source. The following Fire Water Pumps support the fire water system:

Fresh Water Fire Pumps

Fresh Water Fire Jockey Pumps

Seawater Fire Pumps

5.2.1 FIRE WATER MAIN SYSTEM

The fire mains are laid out in loops or grids along the roads on four sides of the process area, utility area, tankage area and building area. Fire mains around the process area and utility area are buried underground. For Offplot areas fire mains are laid out above ground except at road crossings. Pump discharge lines from fire pumps are arranged to supply fire water to the fire main grid system from two different directions, to ensure continuous fire water supply even when any one supply source line is blocked or failed.

The fire main lines on the LNG facilities are cement lined and the water velocity in these lines will not exceed 3 m/s. A number of block valves and flushing connections are provided for isolation and draining.

5.2.2 FIRE WATER HYDRANTS

Fire water hydrants are located 60 m apart around the process area and 90m apart around Utility, Offplot and building areas. Any given



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area can be accessed by 2½ inch diameter, 75 m length hose. Hydrants are located at least 15 m away from equipment or 12 m away from buildings to be protected.One (1) fire hydrant is located on the roof platform of each LNG tank. Hose boxes are strategically located and furnished with four (4) fire hoses, one (1) fog to straight stream nozzle and two coupling gaskets.

5.2.3 WATER MONITORS

The following monitor types are provided:

Fixed Water Monitor

Portable Wheeled Water Monitor

Ground Oscillating Fixed Water Monitor

Remotely Operated Water Monitor

Elevated Fixed Water Monitor

Equipment to be protected can be covered within a radius of 30 m from any two fixed water monitors.

The Portable Wheeled Water Monitors can be strategically located, four (4) monitors in each process train, two (2) monitors on LNG jetty deck and one (1) monitor on the condensate jetty deck.

The Ground Oscillating Fixed Water Monitors are provided for the protection of the Slug Catcher and Condensate Stabilizer. Two (2) oscillating fixed water monitors are provided on the roof platform of each LNG tank. Two (2) remotely operated water monitors are strategically located on the LNG jetty deck.



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5.2.4 FIXED WATER SPRAY SYSTEM

Fixed water spray systems are provided where equipment containing significant volumes of flammable liquid cannot be quickly and effectively depressured.

Fire water spray is also provided for the following:

Valve Manifold on the LNG Jetty Deck

LNG Pump Platform and Tank PSV Tail Pipe on LNG Tanks

BOG Compressors and LNG Liquid Return Pumps at BOG Compressor Area

LNG Process Train Equipment

5.2.5 FOAM SYSTEMS

High expansion foam systems are provided for liquid spill containment in process areas, LNG jetty and LNG storage tanks area.

A Rim Seal Foam System with tank shell mounted foam chambers and wind girders are provided for the protection of open top floating roof Condensate storage tanks.

5.2.6 DRY CHEMICAL EXTINGUISHING SYSTEMS

A fixed dry chemical extinguishing system is provided on the LNG jetty deck. Carbon dioxide fixed extinguishing systems are provided in the enclosures for MR compressor gas turbines, Propane compressor gas turbines and Power Generation gas turbines.

The following types of portable fire extinguishers are provided:

BC (rated) (Potassium bicarbonate dry powder) Normal 9 kg portable extinguishers

BC Normal 68 kg wheeled extinguishers



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(Potassium bicarbonate dry powder)

5.2.7 INDOOR FIRE PROTECTION

A recently approved clean agent (FM200) extinguishing system is provided to protect areas above and/or below the raised floors for the following buildings:

SIH-04, SIH for LNG Storage Area

SIH-05, SIH for Condensate Storage Area

MTB, Marine Terminal Building Control Room

LCS-03, Seawater Intake Enclosure

LCS-04, Shelter for Molten Sulphur Storage and Solidification

This system (FM200) must not be used at any other location without specific approval. Automatic water sprinkler systems are provided for the dining area of the Canteen, Laboratory, Maintenance Work Shop, Warehouse, Garage and Administration Building.

Indoor hydrants are located inside the buildings except for gate houses, Satellite Instrument Houses (SIHs), Control buildings and Substations. For control rooms, substations and analyzer houses, 6.8 kg CO2

extinguishers are provided with a maximum travel distance of 9 m. In addition, 20 kg CO2 wheeled extinguishers are provided at the entrance to substations. For other buildings, 9 kg portable extinguishers are provided with a maximum travel distance of 22.8 m.

5.2.8 FIRE STATION

A dedicated Fire House is provided for the LNG facilities and includes the following mobile fire equipment:

One (1) First Intervention Fire Truck



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Dry Powder : 500 kg

Pre-mixed foam solution : 3% AFFF Solution, 500 litres(Aqueous Film Forming Foam)

Two (2) Combination Fire Trucks

3% type AFFF : 2,000 litres

Dry Powder : 3,000 kg

One (1) Low Expansion Foam Trailer

Type AFFF : 5,000 litres

One (1) Ambulance

Furnished with all the necessary accessories

5.2.9 FIRE BRIGADE EQUIPMENT

A suitable number of portable extinguishers, fire hoses, water nozzles etc., are provided at the fire station. AFFF and High expansion foam concentrates used by fixed systems and fire trucks are stored in portable drums, located near the fire station. Adequate storage area is provided.

An area of approx. 70 m x 80 m, including 1200 m² of paved training floor is provided as a training ground for fire fighting. The training floor is equipped with miscellaneous simulative training equipment. An 8 inch branch line from the water main is run to the training ground with two (2) hydrants.

The design of the fire and gas alarm, detection and control system (F&G Systems), is based on programmable technology and fully distributed control concept. The system is interfaced with the process DCS for the



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purpose of monitoring only. The system has an interface with the Public Address and General Alarm System (PA/GA System) for sounding F&G audible alarms.

F&G panels are distributed at strategic locations such as Local Control Shelters (LCSs), Satellite Instrument Houses (SIHs), Marine Terminal Building (MTB), Central Control Building (CCB) and Fire Station. These panels receive signals from field devices for remote/automatic actuation of the fire fighting systems and for transferring the received signals to other F&G panels and the process DCS.

Optical fibre cables are used for data network links between F&G panels, while conventional electrical cables are used between field devices and the F&G panels. The optical fibre cables are dual redundant with separate routes.

Three types of F&G mimic panels are utilised:

Simplified mimic panels indicating area-wide alarms for the whole plant area.

Main mimic panels indicating zone alarms for the whole plant area

Local mimic panels indicating zone alarms for related areas

Simplified mimic panels are located in the plant gatehouse, in the administration area and in the gatehouse in the sulphur handling area. Main mimic panels are located in the CCB and the Fire Station. Local mimic panels are located in the MTB and LCRs.

In addition to the mimic panels, Video Display Units (VDUs) are provided in the CCB and Fire Station, to display all individual alarms for the whole plant area.

In order to operate the fire protection systems remotely, an operating panel is provided in the CCB and interfaced with the F&G Systems.

An operating panel is also provided in the Fire Station for the remote start of the fire water pump and F&G audible alarms by the PA/GA



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System. A printer provided in the CCB records all individual alarms and events in the whole plant area. A local panel for each F&G System is located in its own building. Common alarms of the local panel are sent to the relevant F&G panels by means of hard-wired connections.

The fire protection system can be summarised as shown below:

Fire and Gas Panels with hard-wired mimic panel, VDU and operating panel in the CCB and the Fire House

Fire and Gas Panels in SIHs

Fire and Gas Panels with hard-wired mimic panel in LCRs

Fire and Gas Panels with simplified hard-wired mimic panel in plant gatehouses

Printer in the Fire Station

Local Panel (for buildings)

Gas receiving Panel (for each type of detectors)

Flammable gas detectors

H2S gas detectors

Spill detectors (low temperature detectors)

Ultraviolet/Infrared (UV/IR) or Infrared/Infrared (IR/IR) combination fire detectors

Manual alarm call (MAC) points

Smoke detectors and heat detectors

Pressure switches for fire protection system actuation signals

5.2.10 PERSONNEL PROTECTION

The following personnel protection facilities/equipment are provided for the LNG facilities:



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Safety Showers and Eye Wash Units are provided throughout the LNG Plant facility where hazardous and/or toxic materials such as caustic, acid, amine, sulfur etc. are handled and/or stored. These units are located in safe and readily accessible locations.

At least two (2) air breathing stations are provided at the periphery of each process unit. Each station contains at least five (5) Self Contained Breathing Apparatus (SCBAs). One air breathing station with two (2) SCBAs is provided near the electrochlorination unit in the Seawater Intake Area.

In addition, at least one (1) Breathing Air Trailer (BAT) in the Acid Gas Removal Units and Sulfur Recovery Units is provided. The BAT contains at least four (4) breathing air cylinders and other breathing accessories. A package breathing air compressor is located in the Fire House to refill breathing air cylinders.


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