info.md

YADANA OPERATING PHYLOSOPHY

1.	General Field Description
  
The operational activities of PTTEP cover a significant area within Myanmar, 
including the following key locations:

-	Yangon: Head office and logistic bases, including marine and air facilities,
-	Yadana Field: Offshore production platforms where gas from the Yadana, Sein, and Badamyar reservoirs is extracted,
-	Onbinkwin Pipeline Centre(PLC),
-	Ban-I-Tong Metering Station (MS)


Important Glossary:(very important)

Name of Platforms in Yadama Asset:
WP1= wellhead platform 1
WP2= wellhead platform 2
WP3= wellhead platform 3 (Sein)
WP4= wellhead platform 4 (Badamyar)
QP2 = QUarter Platform
PP = Producrion Platform
LCP = low compression platform
MCP = Medium Compression Platform
FP= Flare Platform

1.	ESD Levels:
•	ESD Level 0: Abandon installation, initiates a black shutdown.
•	ESD Level 1: General emergency shutdown, closes all ESVs and initiates blow-down.
•	ESD Level 2: General process shutdown, stops production.
•	ESD Level 3: Individual process shutdown.


•	ESD0 initiated automatically on confirmed gas detection or manually with approval.
•	ESD1 initiated by F&G system and push buttons.
•	ESD2 initiated by key safety switches and push buttons.

•	Each platform is equipped with its own ESD system.
•	Connected to the Control Room via hardwire link or telemetry system.
•	PLC used for ESD control, with operator interface and DCS console.

•	Local independent electro-hydraulic panel for shutdown execution.
•	ESD actions can be initiated from the Control Room.

•	Local resetting required on ESVs and SDVs after any ESD level.
•	BDVs can be reset from the Control Room.
•	Partial stroking facilities for ESD Valve Function testing.

•	ESD 0 push buttons hardwired to platform ESD systems.
•	Dedicated HS for blowout disabling during rig operation.
•	Partial stroking facilities for ESV valves for testing purposes.

    Pipeline System:
•	36" pipeline transports gas (domestic and export) to delivery points at PLC and Thai border.
•	Offshore pipeline length: 346 km to coast. (Yadana offshore to Pipeline Centre)
•	Onshore pipeline length: 63 km. ( Pipeline centre to Metering Station)

•	Custody transferred to PTT of Thailand at border.
•	Gas further transported by 238 km long 42" pipeline from Metering station to Ratchaburi where main users are EGAT and TECO Power Plants.

    Pressure Requirements:
•	Required delivery pressure at EGAT power plant: 36.9 bar (550 psia).
•	Contractual delivery pressure at Thai border: Maximum 64.5 bar (950 psia).

    Gas Delivery:
MMSCFD = million standard cubic feet per day
•	Normal domestic gas supply to MOGE at PLC: 50 MMSCFD since June 2010.
•	Maximum export gas delivery to PTT: 720 MMSCFD with border back pressure around 53 barg (780 psig) by running PTT BVW7 compressors.
•	Maximum delivery to PTT recorded around 750 MMSCFD in May 2011.

________________________________

1.1. Yadana Development History (Offshore)
1.	Phase 1 (Installation of WP2):
•	Remote wellhead platform (WP2) installed with a 20" subsea production line.
•	Platform complex includes wellhead WP1, production PP, living quarters QP, and flare tripod structures, all bridge linked.
•	Gas exported via a 36" pipeline to the Myanmar/Thai border.
2.	Phase 2 (Addition of WP3):
•	Second remote wellhead platform (WP3) developed in 2005 (Sein field).
•	WP3 equipped with a 10" subsea production line, tied into WP1 production manifold.
•	WP3 consists of two gas-producing wells, with production starting in March 2006.
3.	Phase 3 (Installation of MCP):
•	Medium Compression Platform (MCP) installed approximately 87m NNE of existing Production Platform.
•	MCP tied into PP facilities via 24" 900# duplex lines running to MCP and 18" 900# duplex lines returning from MCP, bridge-linked.
•	MCP installed to compensate for declining reservoir pressure, ensuring required export pressure of sales gas.
4.	Phase 3 (Domestic Gas Demand Facilities):
•	Facilities provided in original design planned for Phase 2, including metering and topsides 20" pigging facilities.
•	Implementation occurred after Phase 3, maintaining existing 20" departure facilities with some modifications.
•	Gas sent to onshore independently of 36" export pipeline via 24" subsea line constructed by MOGE in 2009 and 2010.
•	Existing 20" riser blinded for future tie-in.
5.	Phase 4 (Development of Badamyar):
•	Installation of 4th wellhead platform (WP4) located approximately 8 km from central complex.
•	Installation and hook-up of LP compression, comprising the first compression stage (2x50%).
•	LCP compression platform bridge-linked to MCP with tripod bridge support to reduce structural loading of MCP.
6.	Parallel Projects (2012-2015):
•	Two projects conducted alongside development plan between 2012 and 2015.


1.1.1. Yadana Subsidence Project (2012-2015) 
1.	Replacement of Flare Platform:
•	Due to subsidence, the flare platform (FP) replaced by FP2 located next to MCP.
•	Linked to MCP by a 130m long bridge.
•	FP flare and bridge removed, remaining jacket equipped with navigation lights for safety.
2.	Protection Measures for Drain Decks:
•	Drain decks on PP, MCP, WP1, and WP2 now in splash zone due to subsidence.
•	ESV, SDV, Hydraulic accumulators, and HPU protected by rigid caissons to withstand wave impact.
•	Closed drain drum and sump drum on PP relocated to lower deck out of wave reach.
•	Vertical pipes installed on drain systems to collect fluids and pump to re-route fluids to respective drums for treatment.
•	Condensate injection pumps located on lower deck due to low NPSH available, variable cavity pumps selected.
3.	Platform Modifications:
•	On WP1 & WP2, closed drain drum replaced by vertical pipe with similar function.
•	On WP2, electrical transformer and corrosion inhibitor injection skid relocated to lower deck.
•	Grating and secondary structures of drain deck dismantled on all platforms where wave splashing is highly impacted.
4.	Living Quarter Relocation:
•	Second phase relocated living quarter to new jacket and MSF2 designed for new conditions.
•	New arrangement named QP2, with additional accommodation capacity.
•	"Old" jacket remains in place until decommissioning, fitted with navigation lights for safe navigation.


1.1.2 Seismic Impact Project (2014-2015):
1.	Structural Works:
•	Yadana central complex platforms and bridges underwent necessary modifications due to re-evaluated seismic hazard conditions and new soil data.
•	Structural reinforcement performed on PP, MCP, and WP1 platforms, including dismantling where required on Jacket, MSF, and Topsides.
•	PP-MCP and PP-WP1 bridges modified and reinforced on both sides.
•	Bridge sliding supports installed at MCP and WP1 sides.
2.	Piping Works:
•	Existing flare line sections at PP-MCP bridge (30’’ HP Flare, 12’’ HP Flare) and PP-WP1 bridge (8’’ HP Flare) modified.
•	Tie-ins performed to insert expansion loops, including dismantling scope where required.
•	Expansion joints and associated instrumentation added to flare lines.
•	MCP TC-A/B outlet lines (2x18’’) modified to insert expansion loop, including dismantling scope where required.
•	New supports installed for outlet lines.

1.1.3.	Onshore Facilities:
1.	Pipeline Centre and Metering Station:
•	Includes a Pipeline Centre near Onbinkwin and a remote Metering Station at the Thai border.
•	Domestic gas supply facilities commissioned and started up in 2001 with a design capacity of 20 MMSCFD.
•	Due to high domestic gas demand, delivery increased to maximum limit of 50 MMSCFD.
•	New domestic gas facilities with a design capacity of 110 MMSCFD upgraded, commissioned, and started up since December 2006.
2.	Pipeline System:
•	36" pipeline transports gas (domestic and export) to delivery points at PLC and Thai border.
•	Offshore pipeline length: 346 km to coast.
•	Onshore pipeline length: 63 km.
•	Block valve stations installed at landfall point (BV1) and middle of onshore run (BV2).
•	Custody transferred to PTT of Thailand at border.
•	Gas further transported by 238 km long 42" pipeline to Ratchaburi where main users are EGAT and TECO Power Plants.
3.	Pressure Requirements:
•	Required delivery pressure at EGAT power plant: 36.9 barg (550 psia).
•	Contractual delivery pressure at Thai border: Maximum 64.5 barg (950 psia).
4.	Gas Delivery:
•	Normal domestic gas supply to MOGE at PLC: 50 MMSCFD since June 2010.
•	Maximum export gas delivery to PTT: 720 MMSCFD with border back pressure around 53 barg (780 psig) by running PTT BVW7 compressors.
•	Maximum delivery to PTT recorded around 750 MMSCFD in May 2011.
5.	Pigging Facilities:
•	Pipeline system equipped with pig launching/receiving facilities for conventional or intelligent pigging of offshore sea line and onshore pipeline up to Metering station.
•	42" line pigged from PTT station at Ban-I-Tong (BVW-1) up to Ratchaburi under PTT responsibility.
•	Section between Metering Station and PTT station on other side of border (BVW-1) cannot be pigged.

2.	General Data
 
 
Current:
Surface currents at Yadana are primarily influenced by wind, with a mean speed of 0.4 m/s and possible peaks reaching 2.0 m/s during steady Monsoon winds. However, these currents diminish rapidly with depth, with mean speeds near the seabed at approximately 0.15 m/s. The strongest currents generally originate from the northeast (N/E) and east (E), flowing in parallel with the local bathymetry.

Tidal currents also play a significant role, particularly during spring tides, where maximum currents can reach around 0.5 m/s. These tidal currents flow perpendicular to the local bathymetry, resulting in four flow reversals each day (two floods and two ebbs), corresponding to flow directions of northwest (NW) and southeast (SE).

These current patterns are crucial considerations for various activities in the Yadana area, such as offshore operations, navigation, and environmental monitoring.

 


Temperature:
Sea water temperature in the Yadana area exhibits seasonal variation, with lower temperatures typically observed from December to February and higher temperatures in May. Maximum water temperatures, around 30°C, occur during transition seasons between monsoons when there is less mixing. The average sea surface temperature ranges between 26°C to 30°C throughout the year.
The temperature variation with depth reveals three distinct water masses:
•	From the surface to 17 meters depth, the sea water temperature remains relatively stable at 28°C.
•	Between 17 to 22 meters depth, the sea water temperature increases from 28°C to 29°C.
•	From 22 to 40 meters depth, the sea water temperature decreases from 29°C to 25°C.


Gas Composition Notes:
•	Reservoir fluid assumed saturated with water.
•	CO2 content: 3.8% mol, H2S content: Actual 20 ppm, Design 50 ppm.
•	Initially, Yadana gas assumed as pure dry gas with GCV above 715 BTU/SCF.
•	After Start-Up (SU), CO2 found to be ~4% and N2 ~25%, resulting in Yadana sales gas GCV around 711.5 BTU/SCF.
•	TEPM installed C6 injection facilities at PLC to increase sale gas GCV to 720 BTU/SCF; Hexane injection prepared but not used.
•	C6 injection facilities decommissioned in August 1999 at PTT's request, accepting Yadana Sale Gas GCV at 711.5 BTU/SCF level until WP-3 development.
•	Yadana gas contains ppm of C20+ causing side-effects like high-density liquid condensate recovery inside TEG loop on PP and retro-grade condensation along export pipelines.
•	C20+ evaluated through on-site measurements via C6+ campaign using prototype lab equipment in August 2001.
•	WP3 production (Sein reservoir) started in 2006, Sein gas contains more C6+ than Yadana gas, leading to contractual liquid issue with PTT in 2007.
•	Liquid issue settled in 2009 by limiting Yadana export gas GCV at around 720 BTU/SCF.
•	Limit later removed as gas blended with other productions (PTTEPI - Zawtika & PCML - Yetagun).
•	Badamyar gas has lower N2 content, sampled gas from exploration phase shows little or no H2S and traces of CO2 (0.05%mol).
•	Badamyar gas considered to contain fewer heavy end components than Yadana and Sein, with no presence of C4+.


Water Management Notes:
•	Yadana, Sein, and Badamyar gas reservoirs are water saturated, and produced water mainly results from water condensation.
•	Design limit of 900 BWPD allocated to WP-3 wells, and 500 BWPD for each wellhead platform WP-1 and WP-2.
•	WP4 maximum reservoir water production is 900 BWPD (end of life 2024-2025).
•	Produced water treatment system initially designed for 1200 BWPD in 2008/2009, Total HQ recommended against extending the water treatment facility.
•	Current philosophy is to cut back production from Yadana and Sein once reservoir water is produced.
•	Surface facilities can handle a total of 1900 BWPD.
•	Produced liquid, mainly composed of produced water, condensate, and glycol, injected into Badamyar R5 aquifer via disposal well YAD-1A.
•	YAD-1A maximum acceptable liquid flow rate: 60 m3/day (~380 bbl/day) with maximum allowable wellhead injection pressure.
•	YAD-1F (water breakthrough well) potentially selected to convert into a new injector well in early 2021 if liquid production capacity increases.
•	Current liquid injection pumps designed capacity: 9.0 m3/h, working flow rate: 8.0 m3/h (1200 bbl/d), exceeds YAD-1A limit.
•	Injection of biocide recommended before liquid injection into Yadana reservoir to control H2S level, maintain gas sales specifications, and prevent microbial-induced corrosion (MIC).
•	Addition of dedicated injection skid proposed to control volume and concentration of biocide injected into reservoir, reduce risk of oxygen containment, and limit manual handling for personnel safety.


2.3. Badamyar Sand Management:
•	Badamyar reservoir consists of unconsolidated sandstone prone to sand production.
•	"No Sand Production" strategy employed, with sand-producing wells choked back until sand production stops.
•	Completion with Open Hole Gravel Pack (OHGP) used for sand control in all wells, providing good protection if set correctly and maintained.
•	Sand management strategy includes:
•	Designing WP4 and production sea line to sustain sand erosion.
•	Specific ramp-up procedures for Badamyar wells to preserve completion efficiency.
•	Surface monitoring for sand production, with sand-producing wells choked if detected.
•	Sand recovery facility installed on PP platform downstream of existing free water flash drum.
•	Provision for a de-sanding unit on WP4 for future treatment of sand-producing wells.
•	Acoustic Sand Detectors (ASD) and erosion probes installed on all flow lines for monitoring, with lower detection limit around 1 kg/d.
•	Pigging operations conducted monthly for the first 6 months after Badamyar production start-up to verify equipment functioning and "no sand" philosophy.
•	Monthly pigging frequency reinstated for 3 months for cleaning and verifying no excessive solids production.
•	MP FWKOD controlled yearly after Badamyar production start-up to confirm sand accumulation rate.
•	Significant sand accumulation in MP FWKOD may result in compressor shutdown for removal and high penalties for gas supply outages.


 


3.	Quarter Platform:
  
3.1 General Overview
•	The quarter's platform serves as accommodation for staff, housing various facilities including the main central control room, maintenance workshop, warehouse, and utilities.
•	Designed to accommodate 114 persons in normal operation, with a maximum capacity of 135 persons.
•	Layout includes:
•	Offices on the first deck.
•	Kitchen, dining room, and recreation rooms on the second floor.
•	Cabins for personnel on the third floor and intermediate deck.
•	Main helideck on the roof deck.
•	Utilities housed on the cellar deck and intermediate deck include:
•	2 main fire pumps, 2 jockey pumps, and 2 sea water lift pumps.
•	Potable water maker and treatment facilities.
•	Potable water tanks.
•	Sewage treatment unit.
•	Electro chlorination package  (Electro chlorination is the process of producing hypochlorite by passing electric current through salt water. This disinfects the water and makes it safe for human use, such as for drinking water or swimming pools.)
•	Emergency generator, battery room, transformers.
•	Diesel day tanks for emergency generator and fire pumps.
•	Sump tank for collecting machinery drains.
•	Jet-fuel drip pans drains directed to the sea.
•	Garbage compactor.

3.2. Control Room
The Control Room is the nerve center of the offshore operation, responsible for overseeing and managing various aspects of process control, safety systems, and communication. Here's an overview of its functions and equipment:
Functions:
1.	Operation and Control: Manages the process and utilities of all platforms.
2.	Safety Management: Gathers information and actions related to safety, including Fire & Gas (F&G) and Emergency Shutdown (ESD) systems.
3.	Data Transfer: Transfers minimum data between offshore and onshore facilities.

Operator Interfaces:
1.	PCS / PSS Operator Stations: Allows operation of process and utilities units, ESD system, and F&G detection systems.
2.	ESD Panel: Hardwired hand switches for emergency shutdown.
3.	Fire Water Pumps Panel: Controls fire water pumps.
4.	Fire and Gas Matrix Panel: Backup deluge hand switches for fire and gas systems.
5.	Inhibit/Isolate Permissive Key Switch Panel: Provides permissive I/O overrides.
6.	Telecommunication Equipment: Includes CCTV control, Public Address/General Alarm Console, UHF and Marine VHF remote units, telephone sets, Meteo display Unit, RSI Simulator, and Wave meter data.
7.	CCTV Monitors: Displays CCTV feeds for wellheads and flare.
8.	VDU for Power Distribution Control (PDC) System: Monitors and displays power generation and distribution data.
9.	Computer and Printer: Used for various administrative tasks such as work permits, filing procedures, production reports, and personnel planning.
10.	Intouch Console: For PSS inhibition.

   
Remote Control and S/D Functions:
1.	ESD2: Closure of well wing & master valves and sea-line ESDV.
2.	ESD1: Closure of well DHSV's and ESD2, and utilities shutdown.
3.	Individual Well Control: Closure and reopening of individual wells, choke adjustment, and test separator control.
4.	ESD3: Test separator control and emergency shutdown.
  
Information Available in the Control Room:
1.	Wellhead Platforms (WP1/WP2):
•	Communication status
•	Video camera watch (WP2 only)
•	Hydraulic system pressure, level, and pump status
•	Wellhead pressure, temperature, and flow values
•	Sea-line pressure & temperature (WP2 only)
•	Well test meter flow, pressure & temperature
•	Well valve status
•	Platform ESD status
•	Fire & gas detection system status
•	Corrosion inhibitor tank level and pumps status
•	Closed drain drum level
•	Pigging status
•	Platform electrical common alarms

2.	WP3:
•	Communication status
•	Hydraulic system pressure, level, and pump status
•	Well valve status
•	Wellhead pressure, temperature, and flow values
•	Sea-line pressure and temperature values
•	Corrosion inhibitor tank level, injection pressure, and pump status
•	Platform ESD status
•	Platform F&G detection
•	Pigging status
•	Navaid status
•	Platform electrical common alarms

3.	WP4:
•	Communication status
•	Hydraulic system pressure, level, and pump status
•	Well valve status
•	Wellhead pressure, temperature, and flow values
•	Corrosion inhibitor tank level and pump status
•	Platform ESD status
•	Platform F&G detection
•	Pigging status
•	Platform electrical common alarms

3.3. Utilities - Instrument Air:
•	System Description:
•	Self-contained system for producing dry instrument air with 5°C dew point at 8 barg.
•	Components include:
•	Air compressor rated for 75 Nm3/h with air cooling.
•	Drier package with two columns (one in operation and one in regeneration).
•	QP2 air receiver sized to provide 15 minutes of autonomy on QP2 air consumption if pressure falls from 7.0 barg to 4.0 barg.
•	Operation during Normal Conditions:
•	QP2 air system not expected to be required during normal operation.
•	Control logic panel independent of central PCS (Process Control System) but linked to it.
•	Air compressor operates on a load/unload basis between pressure levels of 7.4 barg and 5.5 barg.
•	Machine starts at 5.0 barg and stops at a predetermined time delay after unload.
•	Backup Functionality:
•	QP2 air can serve as a backup to the PP/MCP air system.
•	Unload/load levels differ from PP/MCP units.
•	User Priorities and Regulation:
•	Instrument air to QP2 users, particularly HVAC actuated valves, is the preferential user.
•	Self-regulated PCV maintains 6.5 barg downstream on the instrument air distribution system.
•	Service air has a self-regulated PCV to maintain 5.5 barg upstream of the valve.
•	Maintenance and Testing:
•	QP2 air compressor test run scheduled for 6 hours per week.
	

Utilities - Fresh Water / Potable Water System:
•	Desalination Process:
•	Fresh water maker package with 2 reverse osmosis trains installed on QP2.
•	Sea water supplied by jockey pumps, chlorinated, filtered, then passed to the desalination unit.
•	Capacity and Treatment:
•	Designed capacity of 42 m3/day.
•	Produced water filtered (granulated active carbon), sterilized, re-mineralized, and chlorinated.
•	Chlorine solution injected separately from electro chlorination package.
•	Storage and Distribution:
•	Fresh water stored in tanks on QP2 with total capacity of 234m3.
•	Tanks designed to supply fresh water requirements for 7 days if fresh water maker is out of order.
•	Water pumped from tanks by 2X100% centrifugal pumps.
•	Distributed to service water network (QP2, PP, MCP) and potable water users (kitchen, laundry, showers).
•	Usage Guidelines:
•	Potable water used as service water for central complex limited to necessity only.
•	Sea water from fire water network used for major cleaning/wash-down operations.
•	Hot Water System:
•	Fed with potable water and distributed by 2 x 100% pumps.
•	Pumps rated at 6.5m3/h at 3.54bar differential per pump.
•	Distribution:
•	Potable water distributed to:
•	QP2 for kitchen, cabin usage, laundry, and sanitary usage.
•	PP/MCP/LCP for utility stations.


Utilities - Sewage System:
•	Grey Water Treatment:
•	Grey water from the kitchen undergoes initial treatment by passing through a starch and grease separator.
•	It is then mixed with other grey and black waters for further treatment.
•	Sewage Treatment Package:
•	Consists of:
•	Initial collection tank.
•	Three stages:
•	Treatment tank (T-4932) equipped with blowers.
•	Post-filtration (T-4933).
•	Discharge tanks (T-4934) equipped with pumps.
•	Additional Treatment Equipment:
•	Ionizers and UV reactors are provided for:
•	Anti-fouling.
•	Disinfection.
•	Sterilization of treated water.
•	Disposal Method:
•	Treated water is disposed of overboard via a dedicated caisson.


Utilities - Drainage System:
•	Collection:
•	Open oily drains from fire water pumps and emergency generator packages.
•	Overflow from fresh water tanks.
•	Collection Point:
•	Collected to an open drain sump drum (D-4430).
•	Ventilation:
•	The sump drum is vented to the atmosphere.
•	Overflow Handling:
•	Overflow from the drum (water with less than 40mg/l oil) flows by gravity via a liquid seal loop overboard.
•	Hydrocarbon Recovery:
•	Recovered hydrocarbon can be evacuated by connection of a portable pump.

Utilities - Fire Water System:
•	Design:
•	Combined ring main system serving QP2.
•	Supplied with sea water by three 50% pumps.
•	Two pumps located on QP2, one on PP.
•	Pump Types:
•	QP2's fire water pumps: Submerged electrical pumps fed by a dedicated diesel generator.
•	PP's fire water pump: Diesel-driven submerged pump.
•	Pump Capacity:
•	Each fire pump has a capacity of 750 m3/h.
•	Diesel Day Tanks:
•	Each fire pump has its own 12-hour diesel day tank fuel supply.
•	Jockey Pumps:
•	Two jockey pumps installed on QP2:
•	One operating and one spare.
•	Nominal capacity of 50m3/h each.
•	Electric motor driven.

Utilities - Electro chlorination System:
•	Purpose:
•	Produces 500ppm chlorine solution.
•	Usage:
•	Dosage to various systems:
•	Sewage effluent (only during maintenance of the sewage package).
•	Sea water lift pumps.
•	Jockey pumps caisson.
•	Fire water pumps caissons (QP2 and PP).

Utilities - Electrical Power Supply:
•	Emergency Generator:
•	Installed capacity: 1000 kW.
•	Serves essential users on QP2, PP, and WP1.
•	Dedicated EDGs for LCP and MCP.
•	Emergency Power Supply Users:
•	Vital lighting.
•	Safety systems (ESD, F&G, PA).
•	Telecommunication systems.
•	UPS.
•	HVAC.
•	Jockey pumps.
•	QP2 crane.
•	Kitchen and laundry.
•	Fresh water supply.
•	Diesel distribution.
•	Operation:
•	Automatically activates upon main power supply failure.
•	Independent starting arrangement.
•	Can be synchronized with main generators.
•	Fuel Supply:
•	Day tank has sufficient fuel for 24 hours of 'full-load' operation.
•	Auto start not functional for ESD 0 level on QP2/PP for safety reasons.

Utilities - Diesel
-	A 2" line is installed on bridge to import diesel from PP for supply to fire water pumps and emergency power generator.



4.	Wellheads Platforms Overview:

General Philosophy:
•	Control and monitoring primarily from the Control Room (CR) located on the Quarters Platform (QP2), with minimum operator intervention.
•	Normal operation remotely controlled and monitored from QP2 via the PCS.
•	Alternative local operation modes from local wellhead control panels are also possible.

WP1:
•	Designed for 12 slots.
•	Configuration: 9 single string gas producing wells (after drilling one more in 2012 and two new wells in 2020) plus one disposal well.
•	Wellhead topside debottlenecking implemented on high productivity well YAD-1D using water breakthrough well (WBT) YAD-1F flow line.
•	Connected to production platform PP by a 100m bridge.
WP2:
•	Designed for 12 slots.
•	Configuration: 7 single string gas producing wells.
•	Three wells stopped for gas production due to water breakthrough.
•	Wellhead topside debottlenecking implemented on high productivity well YAD-2G using water breakthrough well (YAD-2C) flow line.
•	Planning drilling of one infill well in 2021.
•	Connected to production platform PP through a 3.5 km 20'' sea line.
WP3:
•	Designed for 4 slots.
•	Configuration: 2 single string gas producing wells.
•	Connected to wellhead platform WP1 through an 11.7 km 10” sea line.
•	Initially powered by solar system, later supplemented by wind turbine due to energy shortfall during monsoon seasons.
•	Safety and control systems hydraulically powered and controlled by a low-power PLC in addition to the well-head control cabinet.
•	"Not normally manned" concept applied, no planned overnight occupancy or daily visits.
WP4:
•	Designed for 9 slots.
•	Configuration: Initially 4 production wells drilled in 2016, planned one additional production well in 2021 drilling campaign.
•	Connected to low compression platform LCP through an 8.1 km 16” sea line.
•	Remote platform with electrical power supplied from PP via a submarine cable.
•	Equipped with simple, non-over pressurized weather shelters for personnel and technical equipment.
•	"Not normally manned" concept applied, no planned overnight occupancy or daily visits.
Capacity and Facilities:
•	WP1 and WP2 equipped with a technical room and one shelter.
•	WP4 equipped with simple, non-over pressurized weather shelters.
•	Maximum personnel on board: 12 persons for WP2 and WP4, 8 persons for WP3.
•	Sanitary facilities provided except on WP3.

Non-Routine Operations Procedures:

1.	Types of Operations:
•	Wire-line operations, hot works, pigging operations, well offloading operations, etc.
2.	Equipment Transfer:
•	Temporary equipment transferred to platforms by crane if needed.
3.	Access and Safety Measures:
•	Access limited to daylight hours.
•	Standby supply vessel with fire-fighting facility required during personnel presence.
•	Access allowed only in good weather conditions and based on forecast to ensure safe re-embarkation.
4.	Platform-Specific Considerations:
•	WP3 is unmanned and not designed for helicopter assisted operations.
•	All lifts performed with crane; power provided by supply vessel.
5.	Rigless Well Operations:
•	Adequate design provisions for rigless well operations, including:
•	Installation of Flopetrol type burner boom.
•	Connection of oily flexible water hoses from moored supply boat.
•	Installation of coiled tubing equipment on helideck.
•	Well offloading on WP4 using Closed Drain drum as Vent KO drum with automatic ignition panel (piezo-electric) for lighting the vent.


4.2. Wellheads Operations and Control:

1.	Valve Isolation:
•	Each well can be isolated by shutting off:
•	Down hole safety valve (DHSV) with/without self-equalizing facility.
•	Two master valves: one automatic (Upper master valve – UMV) and one manual (Lower master valve – LMV).
•	A wing valve (WV) with automatic actuator.
2.	Control System:
•	Xmas tree valves controlled hydraulically from the wellhead control safety cabinet.
•	Hydraulic unit treated with 200 ppm biocide (Busan 1285) to eliminate contamination.
3.	Hydraulic Pressure Levels:
•	Very High Pressure (VHP) for DHSV - around 340 barg (5000 Psig).
•	High Pressure (HP) for WV and UMV - around 207 barg (3000 Psig).
•	Medium Pressure (MP) for ESDV, SDV BDV, Choke & Control valves - around 85-110 barg.
•	Low Pressure (LP) for pilots - around 5 barg.
4.	Operation Control:
•	Each valve can be opened/closed/reset from well control drawers in the Wellhead Safety Cabinet (WHSC).
•	WV, UMV, or DHSV closed on an ESD requires local reset before opening.
5.	Start-Up and Shutdown:
•	WP2 and WP3 wells can be closed via PCS action or ESD action depending on the upset.
•	Start-up after PCS closure can be done remotely; re-start after ESD shutdown requires local reset before start-up.
6.	Sequence and Logic:
•	Closing sequence: WV, UMV, DHSV.
•	Opening sequence: DHSV, UMV, WV.
•	Confirmation of each step is needed before proceeding.
•	Choke valve interlocked with respective wing valve via PCS to ensure closure before WV opening.

4.3. Flowlines and Manifolds:

1.	Valve Alignment:
•	Each flowline aligned via double valves to production manifold, test manifold, or depressurization manifold.
•	Methanol injection facility available for hydrates control, transportable to each wellhead platform as needed.
2.	Corrosion Considerations:
•	Yadana and Sein effluents potentially corrosive due to CO2 and H2S.
•	Badamyar gas contains traces of CO2 and H2S.
•	Sand production from WP4 increases erosion corrosion rate.
•	Flowlines and manifolds made of stainless steel to mitigate corrosion.
•	Design basis considers 0.05% CO2 and 10 ppm vol% H2S.
•	WP4 designed for sand production from unconsolidated reservoir.
3.	Material and Design:
•	Flowlines designed for well shut-in pressure of 156 barg (116.5 barg for WP4).
•	Wells flowlines and test manifold made of 6” 321SS for WP1, 2, and 3, and 8” for WP4.
•	Production manifold sizes: 20” for WP1 and WP2, 6” for WP3, and 14” for WP4.
•	Provision for new 20” lines from WP1 and WP2 during phase 4 not used due to changes in Yadana production profiles.

4.4. Well Head Control and Emergency Shutdown:

1.	Control from PCS:
•	Wellhead process control managed from PCS in QP2 control room.
•	Each flowline equipped with ESD3 input from low-low or high-high pressure trips upstream and downstream of choke valves.

2.	Emergency Shutdown (ESD) Levels:
•	ESD3: Closes individual well WV and UMV in response to pressure trips.
•	ESD2: Closes all wellheads WV and UMV, isolates production line to PP, and isolates test separator.
•	ESD1: Initiates ESD2 actions, additionally closing all DHSV and opening all blow down valves.
•	Special consideration for WP2 Rig-On position to prevent cold venting gas while operators are present.

4.4.1. Well Testing:

1.	Test Separator Installation:
•	Test separators installed on WP1 and WP2. WP3 wells tested through WP1 test separator.
•	Two-phase separation vessel used for gas and liquid measurement, pressure, and temperature compensated.
•	Hydraulically actuated back pressure control valve on gas outlet and liquids level control valve.
2.	Operational Procedures:
•	Test separator SDVs opened from QP2 Control room when facility is ready.
•	Control and reporting done from central PCS in QP2 control room.
•	Sample connections provided for laboratory analysis on gas and liquid outlets.
3.	Safety Measures:
•	Only one well tested at a time.
•	High inlet pressure aborts test run and closes inlet and outlet SDVs.
•	Safety relief valve protects vessel in fire case, designed for full closed-in wellhead pressure (156 barg).
4.	WP4 Testing:
•	Wells tested through wet gas flow meter (MPFM) (X-0040).
•	Routing of wells between production header and test header controlled remotely.
•	Sample connections integrated as part of MPFM & WGM test meter package.

4.4.2. Gathering Lines:

1.	WP1:
•	20” stainless steel line transports WP1 effluents to PP via a bridge.
•	No corrosion inhibitor injection.
•	Warning: Vulnerable to extreme waves under 6-m subsidence, requiring advance depressurization during cyclones.
2.	WP2:
•	20” sea line, 3.5 km long, transports WP2 effluents to PP.
•	Equipped with manual pig launching system for intelligent pigging.
•	Continuous corrosion inhibitor injection for carbon steel sealine protection.
•	Batch injection of biocide chemical dosing after each cleaning pig operation.
3.	WP3:
•	10” sea line, 11.7 km long, transports WP3 effluents to WP1.
•	Pig launching and receiving facilities for intelligent pigging operations.
•	Continuous corrosion inhibitor injection.
•	Maintain flow rate above 20 MMSCFD to prevent liquid accumulation and slugging in WP1 test separator and FWKO drums.
•	Manual control of flow rate to achieve required gas mixture for Yadana production.
4.	WP4:
•	16” sea line, 8 km long, transports WP4 effluents to LCP, then across bridge to MCP.
•	Maintain flow rate above 30 MMSCFD from 2022 to prevent liquid accumulation and slugging in FWKO drums.
•	Equipped with manual pig launching system for intelligent pigging.
•	Continuous corrosion inhibitor injection.
•	Batch injection of biocide chemical dosing after each cleaning pig operation.

4.4.3. Blow Down and Relief System:

1.	WP1 and WP2:
•	Automatic depressurization to 7 barg within 15 minutes in case of ESD1.
•	Three blow down valves installed on production manifolds, test manifolds, and test separator.
•	WP1 depressurized through main flare system; WP1-PP gathering line depressurized via blow down valves on PP.
•	WP2 equipped with 6" horizontal cold vent for emergency depressurization.
•	Vent designed to prevent exceeding radiation limits in case of gas ignition.
•	Manual depressurization of WP2 sea line through HP flare on PP when necessary.

2.	WP3 and WP4:
•	Not equipped with Emergency Depressurization system (EDP) due to limited hydrocarbon inventory.
•	WP3 equipped with HP vent drum and manual depressurization facility.
•	WP4 equipped with venting system and manual depressurization facility; CO2 snuffing system provided to extinguish accidental ignition.
•	Derogation granted for WP4 based on full isolation of production manifold prior to manual depressurization.
•	Actuator installation option for remote depressurization during SIMOPS activities.

- Well Offloading:
•	Objective: Clear liquid (water) from well tubing by flowing well at low pressure to closed drain/Vent KO drum.
•	Specific operating procedure outlined.
•	Snuffing system deactivated during offloading; vent tip ignited using high-energy ignition system.
•	Fuel gas for ignition supplied from propane bottles.
•	Nitrogen purge package provided to inert vent system before and after offloading.
•	Propane purge package used to purge vent system during offloading.

- Flare Radiations and Noise:
•	Thermal radiations from ignited vent to Crane cabin exceed acceptable level during offloading, prohibiting crane use and work on weather deck.
•	Noise level exceeds criteria during continuous flaring, requiring hearing protection enforcement at WP4 Platform during offloading.




5. Gas Treatment


5.1. General View

•	Control and monitoring primarily from the Control Room (CR) on the Quarters Platform (QP2).
•	Gas from 4 wellhead platforms directed to the First Stage Separator (FWKO) on the Main Compression Platform (MCP) at around 42 barg.
•	Routed to two identical compression trains on the Low Compression Platform (LCP).
•	Main operation on LCP is to lift pressure by compressing gas to 69 barg.
•	Gas returned to MCP compression trains for further compression to 108 barg.
•	Combined gas from both trains sent to Process Platform (PP) for dehydration and export via two export lines (36” and 24”).
•	Gas flow processed based on demands for 36" export gas and 24" domestic gas users, considering line packing needs.

5.2. Key Parameters

•	Gas can be produced in 4 configurations:
•	HP mode: Directly from Well Platform (WP) to export with minimal treatment.
•	MP mode: Through MP compressors.
•	LP mode: Through LP and MP compressors.
•	LLP mode: Through LP compressors in series and one MP compressor.
•	HP potential not feasible since Q1-2016.


5.3. Flow Control

•	Gas from wellhead platforms WP1+WP3 and WP2 is manifolded at Process Platform (PP) and directed to two First Stage Separator (FWKO) drums on Main Compression Platform (MCP), where it's mixed with WP4 gas received through Low Compression Platform (LCP).
•	Compression trains started in segregated mode to allow compressor time to run up to required production rate without affecting alternate train due to pressure differences.
•	WP1/WP3 & WP4 aligned to LCP/MCP train-A, returning gas to PP train-A.
•	WP2 aligned to LCP/MCP train-B, returning gas to PP train-B.
•	Optimized method for balancing production on both trains:
•	Open MCP FWKO inlet balancing lines.
•	Keep LCP inlet and outlet balancing lines closed.
•	Keep MCP outlet balancing lines closed.
•	Controls implemented to handle field operating modes and events:
•	Choke limiter
•	Pressure control
•	Automatic actions for compressor trips
•	Each dehydration train on PP has an independent flow control loop.
•	Flow transmitter signal processed in PCS logic to allow operator setting of total PP flow rate required.
•	FV-40025 and FV-40026 operated manually (full open) in practice.
•	Chokes set manually to meet compressor suction pressure required for export demand.

5.3.1. Choke Limiter
•	Overall well capacity limited to maximum of 950MMScfd (design capacity) during all operation modes via well control procedure.
•	Operator sets chokes to achieve specific flow and does not adjust them afterward.
•	Chokes have a maximum open position, called choke limiter, which operator cannot exceed.
•	Well control procedure defines limiter setting and maximum potential capacity in case of error.
•	Choke movements are limited to small increments to allow time for LCP and MCP compressors to respond to flow/pressure changes.
•	Individual hydraulically actuated flow line choke valves set from QP2 control room via PCS.
•	Once set, chokes can only be closed further, not opened.
•	Choke position setting conducted under password-controlled system.

5.3.2. Pressure Control
•	Pressure control system initiates actions in case of pressure increase at gas treatment inlet (PICA 49067 / 49061 / 80004) to minimize flaring during upset conditions and avoid tripping the second train on high suction pressure.
•	Each inlet manifold equipped with a PICA monitoring gas flowing pressure with 3 threshold values affecting wells:
•	First threshold: Automatically closes selected wells' choke valves to pre-defined value.
•	Second threshold: Automatically closes selected wells' wing valves, which close faster than chokes, causing significant reduction in flow rate to prevent further pressure increase.
•	Third threshold: Automatically closes all wells' choke and wing valves.
•	Closing wells via PCS prevents ESD trip on Process Platform (PP) by using quicker response of wing valves to halt production before PAHH set point is reached, beneficial for remote wellhead platforms as PCS action doesn't require local reset like ESD trip.
•	Other pressure control systems implemented on manifolds and vessels independent of previous means:
•	Pressure relief valves (PVs) installed on each FWKO routed to HP flare with limited capacity of 192 MMScfd.
•	PVs installed on each PP inlet manifold routed to HP flare, sized to relieve full gas flow from associated wellhead platform.
•	Set of 3x50% full flow Pressure Safety Valves (PSVs) provided on each manifold (116.5 barg).
•	Threshold values related to manifold pressure adjusted based on operating mode (MP/LP/LLP).

5.3.3. Compressor Trip Automatic Actions
•	To anticipate wellhead platform shutdown during events on MP and LP compressors, the following logic is implemented in wells control:
•	In segregated mode:
•	On MP or LP compressor trip, all choke valves on associated wells are set to close position (except on WP3).
•	In balanced mode:
•	On MP or LP compressor trip, all wing valves on WP1 are closed, and choke valves on WP3 are set to a predefined value.
•	In case of event on the second train, all choke valves are set to close position.
•	Choke valve equipped with continuous position indicator/potentiometer providing feedback control for desired valve position.
•	Implemented fixed timer counter in choke valves opening logic to overcome potentiometer failure. Timer corresponds to opening time of maximum allowable % opening. If choke opening doesn't reach set point % within this time, timer stops output of opening signal, notifying control room operator.
•	Logic not implemented for choke valve closing as it conflicts when choke valve is required to close more than maximum allowable limit % during ESD or reaching threshold settings.

5.4. Gas Compression and Dehydration
•	Standard gas compression route post Low Compression Platform (LCP) start-up in LP mode described. Operating Yadana in LLP mode not anticipated before 2023.
5.4.1. MCP Free Water Knockout Drums D-2010/2020
•	Vertical 3-phase separators receiving production fluids from wellhead platforms. Gas from all platforms fed into FWKO located on MCP.
•	For LP regime:
•	Flow from FWKO drums sent to LCP scrubber’s inlet, passes through LP compressors, and returns to MP suction scrubbers of MCP.
•	Most entrained liquid removed at FWKO drum outlet spiral flow cyclones.
•	Note: For LLP regime:
•	LCP design plans the possibility of operating two compressors in serial operation to lower wellhead flowing pressures at end of field life.
•	Process equipment (scrubbers, coolers, compressor casing) designed for LLP regime; piping arrangement planned to operate two trains in serial operation without brownfield works.
•	Recovered liquid passes to oil/water separator inside vessel where condensate rises and is skimmed off into condensate recovery section.
•	Produced water sent to water flash drum on PP under level control via water manifold; condensate sent to condensate flash drum via independent condensate manifold under on/off level control.
•	Drums: 316SS clad carbon steel specified for low temperature service (impact tested to -50°C).
•	Vessels protected against overpressure by relief valve sized for fire case.

5.4.2. LP Compressor Suction Scrubbers D-3011/3021
•	These scrubbers are two-phase separators equipped with spiral flow cyclones and an agglomerator, receiving gas from the LP free water knockout drums.
•	Purpose: Ensure entrained water removal before gas is fed to the compressor. Recovered liquid sent to water treatment facilities on PP under level control.
•	Vessel protected against overpressure by relief valve sized for fire case. Vessels are 316SS clad carbon steel specified for low temperature service (impact tested to -50°C).


5.4.2. LP Compressor Suction Scrubbers D-3011/3021
•	These scrubbers are two-phase separators equipped with spiral flow cyclones and an agglomerator, receiving gas from the LP free water knockout drums.
•	Purpose: Ensure entrained water removal before gas is fed to the compressor. Recovered liquid sent to water treatment facilities on PP under level control.
•	Vessel protected against overpressure by relief valve sized for fire case. Vessels are 316SS clad carbon steel specified for low temperature service (impact tested to -50°C).

5.4.4. LP Discharge Coolers E-3010/3020
•	Compressor discharge air coolers constructed with two bays per train, each bay containing two units (four units per train).
•	Each unit comprises a fan and fixed-speed motor assembly with vibration detector.
•	Motors can be started and stopped individually via PCS.
•	Discharge coolers cool compressed gas before sending it to MCP for further compression.
•	Gas from discharge cooler returned to MCP via discharge manifold equipped with balance line on LCP and MCP ends, both supposed to be closed.
5.4.5. MP Compressor Suction Scrubbers D-2011/2021
•	These scrubbers are two-phase separators with spiral flow cyclones and an agglomerator, receiving gas from LP compression trains on LCP.
•	Purpose: Ensure entrained water removal before gas fed to compressor. Recovered liquid sent to water treatment facilities on PP under level control.
•	Vessel protected against overpressure by relief valve sized for fire case. Vessels are 316SS clad carbon steel specified for low-temperature service (impact tested to -50°C).
	

5.4.6. MP Compressors K-2010/2020
•	Compressors take gas from suction scrubber at 84barg to 58.6barg (WHFP declining) and compress it up to return pressure of 107.6 to 109.8 barg.
•	Compressor suction pressure manually altered to achieve required flow using PICA controller at compressor suction scrubbers. Adjusting PICA set point affects compressor speed and capacity.
•	PIC connected to MP FWKO opens to relieve excess pressure if vessel pressure exceeds PIC set point.
•	Operators must make small changes in PICA set point to avoid venting via PV. Adjusting PICA preferred over closing/opening well chokes for better system stability.
•	The compressor is equipped with flow override capacity control to prevent exceeding 500MMSCFD (single compressor mode)/465MMSCFD (double compressor mode) and overpressure control on export line preventing speed increase if export pressure exceeds 110barg.
•	Compressor discharge has 2 independent trips via ESD and compressor PLC to prevent high pressure. Ultimate protection provided by 3x33.3% PSVs sized for worst-case scenario (807MMSCFD).
•	Anti-surge loop provided from discharge cooler outlet to suction scrubber inlet to prevent surge, also acts as recycle loop for starting compressor. Additional surge protection provided by hot gas bypass (HGBP) from compressor discharge to suction scrubber. Flow monitored at compressor suction and downstream of recycle line for surge controller input.
5.4.7. MP Discharge Coolers E-2010/2020
•	Compressor discharge air coolers constructed with two bays per train, each bay containing two units (four units per train).
•	Each unit comprises a fan and fixed-speed motor assembly with vibration detector, can be started and stopped individually via PCS.
•	Discharge coolers cool compressed gas to 46°C before returning to PP for dehydration.
•	Gas from discharge cooler returned to PP via discharge manifold, equipped with balance line on MCP and PP ends, normally locked closed.

5.4.8. Operation Mode from LP to MP
•	Switching operating mode from LP to MP (or vice versa) possible without modifications, only requires temporary compression interruption to:
•	Adjust pressure of different stages,
•	Modify settings within Yadana DCS,
•	Operate manual isolation valve at MCP FWKO.
5.4.9. Operation Mode from LP to LLP
•	Changing operating mode from LP to LLP requires replacement of one compressor bundle (compressor A). Interconnection line between LP compressor A discharge and LP compressor B suction already installed.
•	Prior compression train restart in LLP, following adjustments required:
•	Modify settings within Yadana DCS,
•	Operate manual isolation valves at MCP FWKO and at LP compressor interconnection. Within this configuration, only one MP compressor will be operated.

5.4.10. PP (HP) Free Water Knock-out Drums D-1010/1020
•	These drums receive pressurized gas returned from MCP, equipped with a demister.
•	Gas fed forward to raw gas filter separators. Recovered liquid sent to water treatment facilities under level control, with condensate disposal under on/off level control.
•	Drums: 316SS clad carbon steel specified for low-temperature service (impact tested to -50°C). Vessels protected against overpressure by relief valve sized for fire case.
5.4.11. PP Gas Filter Separators D-1011/1021
•	These drums receive gas from HP free water knock out drums.
•	Purpose: Remove solids and coalesce/ separate entrained free water droplets before gas fed to glycol contactors.
•	Each train equipped with one gas filter separator, temporarily bypassed in case of maintenance. Recovered water sent to water treatment under level control.
•	Filter protected against overpressure by relief valve sized for fire case. Material: 316SS clad carbon steel specified for low-temperature service.

5.4.12. PP Glycol Contactors C-1010/1020
•	Columns receive gas from gas filter separators, dried by flowing counter current to triethylene glycol (TEG) fed from top. Equipped with packing for gas-glycol contact and wire mesh demister to prevent carryover of glycol droplets.
•	Sized to give maximum gas outlet water content of 4 lbs water per MMSCF of gas, ensuring 7 lbs maximum per MMSCFD for sale gas. Skimming facility provided at contactor normal liquid level for future condensate recovery.
•	Rich glycol flows under level control to regeneration package. Column protected against overpressure by relief valve sized for fire case. Material: carbon steel with bottom part clad with stainless steel 316.
•	Dedicated train pressure control valve to HP flare for normal startup. Outlet PCV maintains pressure greater than 104barg to ensure maximum velocity allowed through tower.
•	Operator adjusts wellhead flows as required on PCS consoles, sending wet or off-spec gas (more than 4 lb H2O/MMSCFD) to HP flare initially while respective TEG regeneration package brought online.
•	Once TEG/gas contact achieved and gas adequately dehydrated, flow to train increased and flow to HP flare backed off to zero.
•	Startup flow: minimum design rate of 130 MMSCFD per train. Absolute minimum flow post startup to prevent coking: 50MMSCFD per train.

5.4.13. PP Glycol Regeneration
Glycol regeneration occurs in two separate trains using a classical fired boiler system. The process involves the following steps:
1.	Flash Vessel: Rich TEG (water saturated) from the gas/glycol contactor under level control enters a 3-phase flash vessel via a glycol preheater. Gas is liberated under back pressure control, and any hydrocarbons produced are separated to an individual compartment. The rich glycol is filtered (solid filter and slipstream through a carbon bed filter) before going to the reboiler still column via the lean/rich glycol plate exchangers. Flow is controlled by level within the flash vessel.
2.	Reboiler: A gas-fired tube-type reboiler, regulated by glycol temperature control, boils off water vapor to the still column (contacting rich TEG in a packed bed). The vapor passes through an overhead total condenser (fin fan cooler) and drum before disposal in the LP flare. Partial liquids from the overhead drum are recycled to the still column with a pump under flow control, with excess liquid dumped to the condensate flash drum under level control.
3.	Lean Glycol Treatment: Lean glycol overflows from the reboiler via an external stripping column (fuel gas used to strip further water and increase purity of lean glycol) and heat exchangers to the surge drum. It is then circulated back to the contactor by reciprocating pumps. Lean glycol is cooled prior to distribution within the contactor by an air cooler with temperature differential control between dry gas outlet and lean glycol inlet to glycol contactor.
4.	Control and Monitoring: Managed by the PCS, reboiler has an independent Burner Management System for pilot and main burners. Control includes back pressure control to LP flare and level control on glycol flash vessel. Manual globe valve on carbon filter bypass regulates slipstream flow through glycol carbon filters.
5.	Additional Controls:
•	Temperature control of reboiler liquids to regulate main fuel gas flow.
•	Self-regulating pressure control valves on fuel gas supply plus manual flow adjustment of stripping gas.
•	Flow control regulation of overheads recycle (reflux) flow with excess liquids to the condensate flash drum by level control from overheads drum.
•	Temperature control on lean glycol to contactor by temperature difference between dry gas and lean glycol inlet.
•	Temperature of lean glycol to the contactor adjusted by temperature difference control acting on air cooler louvers.
•	Rich glycol return from contactor regulated by level control from bottom of contactor.
6.	Glycol Make-up System: Manually operated system includes storage tank, pump, and filter. Tank is blanketed by inert gas (N2) with self-regulating valve and pressure/vacuum breaker valve. Entire system made of carbon steel.



5.5. Gas Export

Gas export involves sending the dehydrated gas from both trains through various pipelines for both export and domestic use. Here are the key points:
•	Export Pipeline:
•	Dehydrated gas from both trains is sent through a 36" export gas subsea pipeline for export to Thailand and a 20” domestic gas pipeline via PLC (Kanbauk), as well as a 24" subsea pipeline for domestic gas via (Daw Nyein).
•	Manual pig launching facilities are provided for both the export and domestic gas subsea lines.
•	Metering on PP is performed by an ultrasonic flow meter (non-fiscal), while custody metering station is located onshore just before the Thai border.
•	With booster compressors running on PTT network (at BVW#7), the maximum flow to PTT is 720 MMSCFD (while delivering 50 MMSCFD to MOGE from PLC).
•	Gas is delivered both to PTT (Export to Thailand) and to MOGE (Domestic) in the onshore section.
•	Domestic Gas Pipeline:
•	Flow is measured by a fiscal metering system (AGA 3 type meter skid) before departure to PLC (Daw Nyein).
•	The normal gas supply to MOGE through this domestic line is 225MMSCFD, as per the agreement in 2010.
•	Offshore domestic metering Design Maximum flow for one meter stream is 300MMSCFD, with a minimum flow of 50 MMSCFD.
•	The existing domestic flow control valve can handle up to 267 MMSCFD at 90% opening.
	
5.5.1 PP Export Line PCV
•	Purpose: The pressure control valve (PCV-40111) on the export line maintains a minimum backpressure on the glycol tower to prevent high velocity.
•	Settings: The valve is set at 104barg and is normally fully open, maintaining an export pressure of 105.5barg.
•	Functionality: The PCV opens to allow predetermined export gas flow through the 36” export line, ensuring a constant operating pressure in the gas trains during steady state conditions.
•	Safety Measures:
•	High pressure alarms are provided both on the export PCV and at the pipeline.
•	Two individual PAHH trips downstream of the PCV shut down production facilities if the pipeline pressure exceeds the design pressure.
•	Overpressure Protection for Domestic Gas Line:
•	The 24” domestic gas manifold is equipped with FV-40139, operating in manual or automatic mode.
•	Two pressure sensors ensure overpressure protection, initiating shutdown of the inboard emergency shutdown valve ESV-40268 if the gas pressure increases.

5.5.2 Pipeline Operation
•	Normal Operation: The offshore pipeline is operated under packed conditions with some margin to cope with unplanned shutdowns.
•	Emergency Shutdown: In case of an emergency shutdown on the Yadana offshore platform, packing valves at PLC are operated to de-pack the offshore pipeline. Priority flow is given to export to PTT if the shutdown duration exceeds expectations.

5.5.3 Offshore/Onshore Nomination Change Coordination
•	Responsibilities: Onshore Site Manager and Pipeline Superintendent coordinate with offshore platform to meet daily nominations to PTT and MOGE.
•	Transmission of Nominations: Weekly nominations are transmitted by fax from PTT and MOGE to Technical Director (Operation, Project and Technical Support Manager), validated, and then distributed to both sites.
•	Handling Nomination Changes: Nomination changes by PTT outside office hours are transmitted directly from PTT Chonburi operations center to the PLC, with coordination handled by the Onshore Site Manager.










6. Produced Liquid Treatment, Drains and Dry Fuel Gas

1.	Production Expectations:
•	Reservoir gas is water saturated, and produced water mainly comes from condensation.
•	Free water production from the reservoir isn't expected until late in the field life during LP and LLP operations.
•	The water treatment facilities are designed for 1200 BWPD to account for free water production.

2.	Injection Facilities Operating Principles:
•	During normal operation, all produced liquids are routed to the PP condensate flash drum. Water is pumped out to the well under level control.
•	Downgraded operation scenarios involve routing produced liquid through the PP oily water treatment system if the well injectivity or capacity is reduced.
•	If the disposal well is unavailable, HC is stabilized, stored, and later disposed of at PLC, where it's burned.

3.	Water and Condensate Treatment:
•	Produced water is knocked out of the gas phase in the FWKO drums, separated, and returned to PP for further treatment.
•	Water undergoes treatment in the water flash drum before being fed to desanding and coalescing equipment.
•	Condensate from LCP, MCP, and PP vessels is routed to the condensate flash drum and reinjected into a disposal well.
•	A 500ppm biocide treatment is added as needed.

4.	Emergency Procedures and Monitoring:
•	During operations where produced water is discharged to the sea instead of re-injected, daily samples are collected and analyzed to ensure compliance with discharge specifications.
•	Monitoring and control of operations, such as pump status and manual interventions, are reported in the control room.


6.1. PP Water Flash Drum D-1410:

•	Function: Receives produced water from MCP, LCP, and any liquid accumulation from the PP FWKO drum and filter separators, as well as liquids accumulated on LCP.
•	Gas Handling: Dissolved gas is discharged to the LP flare.
•	Water Handling: Water is directed to the condensate flash drum under level control, or to a closed drain vertical closed pipe if re-injection is unavailable (manual selection).
•	Purging and Venting: Continuously purged with fuel gas, with manual adjustment for regulation. Vent is sized for gas blow-by from the upstream FWKO drum.
•	Construction: Carbon steel construction, designed for 15 barg.
	
6.2. PP Coalescer and Sand Removal Units:

•	Upgrade Necessity: Upgrading of water treatment facilities on PP due to extra water production, water slugs, and potential sand from WP4.
•	Installed Packages: Sand removal package U-1410 and Coalescer package U-1414 installed downstream of Water Flash Drum D-1410 during phase 4.
•	Capacity and Design: Sand removal package has a capacity of 9m3/hr, designed to remove particles from 20 microns.
•	Feeding and Operation:
•	Fed from Water Flash Drum by specific Oily Water Booster Pumps P-1410 A/B.
•	Pumps operate on/off to avoid low velocities and sand dropout at low water flow rates.
•	Start/Stop sequence level controlled through LICA-40199.
•	Components:
•	Sand removal package: 'solid-liquid' cyclone de-sander (2x100%) designed to remove fine sand, scale, and other solids.
•	Each Desander Vessel contains five liners for a total capacity of seven.
•	Discharged solids collected in an accumulator and bagged for shipment to onshore.
•	Operation and Monitoring:
•	Manual operation, only alarms reported to the control room.
•	Desander designed to remove 98% of particles 10 microns and larger, and 99% of particles 20 microns and larger.
•	Discharge and Separation:
•	Clean produced water flow discharged through Coalescer package (U-1414) to condensate flash drum (D-1490).
•	Mare’s tail type coalescing system (2x100%) facilitates oil/water separation in the existing Condensate Flash Drum.

6.3. PP Condensate Flash Drum D-1490:

•	Function: Collects liquid from LCP and MCP condensate manifold, glycol overhead drum, glycol flash drum (NNF), water flash drum, and sump drum. Receives all liquid effluent from the facilities.
•	Vessel Type: Atmospheric vessel directly connected to LP flare network.
•	Compartments:
•	First compartment: Settles incoming liquid before passing to the second compartment. In fully degraded mode, incoming fluid can be heated to improve separation and stabilize the condensate phase prior to disposal via the sump caisson.
•	Second compartment: Stores separated HC condensate. Operates flooded in normal operation, receiving all liquid for re-injection.
•	Temperature Control: Temperature controlled by TIC acting on heater E-1490.
•	Provision for Water Outlet: Provision on the water outlet for additional treatment system during downgraded operations to ensure water quality discharged to the caisson.
•	Re-injection: Produced water and condensate/oil re-injected to water injection well(s) on WP1 by pumping up to injection pressure using progressive cavity pumps (Condensate Injection Pumps).
•	Injection Pumps: Electrically driven eccentric screw type pumps (P-1490 A/B) delivering 8 m3/h each, for a working pressure of ~ 52 barg. Pumps run continuously to provide a constant and stable flow of water to the well(s).

6.4. Produced Liquid Disposal Well YAD-1A:

•	Conversion History: YAD-1a (formerly gas producer) converted into injector during the 2004 well campaign.
•	Conversion Process: Bridge plug set at 1228 mRT, perforations at 1077-1102 mRT performed with 4 runs (6m per each run).
•	Injection Rate Measurement: Liquid flow rate metered with an ultrasonic flow-meter installed on the piping at the outlet of the injection pumps.
•	Remedial Action: Re-perforated in Dec 2006 (1072-1107mRT) due to an increase in WH injection pressure to improve injectivity.
•	Future Plans:
•	YAD-1C identified as the next potential produced liquid disposal well, but modification not implemented during LCP-Badamyar project due to no water flooding at any WP1 well.
•	Early flooding of YAD-1F changed priority of injector well.
•	YAD-1F or another water breakthrough well will be converted to disposal well by early 2021.


6.5. Drains:

6.5.1. PP Open and Closed Drains:
•	Closed Drain Vertical Pipe (T-1430):
•	Acts as a buffer collecting all liquid routed to the closed drain network by gravity.
•	Manually operated nitrogen-driven submerged pump (P-1430) transfers liquid to Closed Drain Drum (D-1430).
•	Liquid HC separated and routed to Open Drain vertical closed pipe (T-1431), while water discharged under level control into de-oiled water return caisson via hydraulic guard.
•	Main Sources to Closed Drain Drum (D-1430):
•	Process vessels, piping when isolated, depressurized, and drained for maintenance.
•	HP and LP flare KO drums.
•	Fuel gas drums.
•	Design Features:
•	Limited capacity of closed drain vertical pipe and pump requires careful monitoring during process vessel emptying.
•	Drum designed with extraction and collection ramp for oil accumulation, equipped with level glasses and sampling points.
•	Open Drain Vertical Closed Pipe (T-1431):
•	Collects liquids routed to open drain network.
•	Manually operated nitrogen-driven submerged pump (P-1431) transfers liquids to Sump Drum (D-1431).
•	Skimmed hydrocarbon pumped back to condensate flash drum (D-1490) by manually operated air-driven condensate transfer pump (P-1432).
•	De-oiled Water Sump Caisson (T-1411):
•	Receives open drain discharge, mainly rainwater and wash water.
•	Manual valve for evacuating eventual free water to de-oiled water return caisson.
•	Equipped with vent with flame arrestor and bird screen.

6.5.2. MCP Open and Closed Drains:
•	Closed Drain Drum (D-2430) and Vertical Closed Pipe (T-2430):
•	Collect drained liquids, transferred to closed drain drum by nitrogen-driven submerged pump (P-2432).
•	Limited capacity necessitates attention during maintenance activities.
•	Closed drain transfer pump (P-2430) returns liquid HC accumulated in drum back to PP water flash drum.
•	Open Drain Drum (D-2431) and Vertical Closed Pipe (T-2431):
•	Collects liquids from open drain system, HPU overflow, and EDG overflow.
•	Skimmed hydrocarbon pumped to closed drain drum.
•	External bypass line available for compromised water quality.
6.5.3. LCP Open and Closed Drains:
•	Closed Drain Drum (D-3611):
•	Receives liquids drainage from maintenance activities and skimmed condensate from open drain drum (D-3612).
•	Liquid accumulated pumped back to PP water flash drum by closed drain transfer pump (P-3611).
•	Open Drain Drum (D-3612):
•	Receives liquids drainage from open drain system, HPU overflow, and EDG overflow.
•	Skimmed hydrocarbon pumped to closed drain drum.
•	Open Drain Caisson (T-3613):
•	Discharges water to sea, includes provision for hydrocarbon spillage skimming.
6.5.4. Open and Closed Drains on Wellhead Platforms:
•	WP1/WP2:
•	Closed drain collection goes to vertical closed pipe, with provision for temporary pump-out facility.
•	WP3:
•	Closed drain collection goes to atmosphere vented CDD.
•	WP4:
•	Closed drain/vent KO drum used for late life well offloading, with LP vent tip and ignition panel provided.
•	Use of boat disposal line to supply boat allowed only when platform is shut down and depressurized.



6.6. Dry Fuel Gas:

6.6. Dry Fuel Gas Overview:
•	Dry fuel gas is essential for various users at three levels of pressure: HP, MP, and LP.
•	HP fuel gas is for turbo-compressor start-up, MP fuel gas for turbo-generators, and LP fuel gas for various purposes including pilot gas for flares, purge gas, and glycol regeneration.
•	LP and MP turbo-compressors have their independent fuel gas supply systems.
6.6.1. Main Fuel Gas System (PP):
•	Dehydrated gas used for fuel.
•	Two dry gas connections provided for redundancy.
•	HP fuel gas supplied via a 3” line to MCP and LCP.
•	Gas heated to around 52°C before pressure reduction to 16barg to prevent condensation.
•	Fuel gas knock-out drum (D-1610) provided to eliminate liquid droplets and ensure uninterrupted fuel supply to power generator turbine.

6.6.2. MP Compressors Fuel Gas:
•	Fuel gas directly taken from MP suction scrubber.
•	Gas treated in FG package and pre-heated during start-up or excessive cooling situations.
•	Liquid removal in FG knock-out drum before heating and filtration.
6.6.3. LP Compressors Fuel Gas:
•	Fuel gas taken from discharge header downstream of air coolers.
•	Gas treated in FG package, pre-heated during start-up or excessive cooling situations.
•	Liquid removal in FG scrubber and coalescing filters before heating and filtration.


7. Utilities

7.1. Electrical Power Generation and Distribution:
•	Main power generation centralized on PP with two dual fuel turbines.
•	The maximum forecasted continuous power is 3083 kW.
•	Emergency diesel generators located at QP2, LCP, and MCP.
•	Offshore electrical control achieved through a Power Distribution Control System (PDCS).
•	Electrical power supplied from PP to MCP, LCP, WP2, and WP4.
•	WP3 utilizes wind turbine and solar panels for electrical power generation.

7.2. Service and Instrument Air:
•	Self-contained system for producing dry air installed on the main complex.
•	4 trains for producing dry air, located on PP, MCP, and LCP.
•	Instrument air package installed on QP2.
•	Air receivers provide autonomy on instrument air consumption.
•	Two independent dried distribution networks for instrument air and service air.
•	Priority given to instrument air header.

7.3. Nitrogen Generation Units:
•	Nitrogen generator packages installed on PP, MCP, and LCP.
•	Sparing philosophy is N+1, with 2 units in operation and 1 in stand-by.
•	Nitrogen purity maintained at 98% minimum.
•	Nitrogen receiver provides 30 minutes of N2 supply between PALL and minimum seal pressure.
	
7.4. Hydraulic Power Supply Unit:
•	Independent hydraulic power units (HPU) installed on PP, MCP, and LCP.
•	Supply energy for actuation of ESV's and SDV's on each platform.
•	Each unit comprises a reservoir, 2x100% electrical pumps, an accumulator skid, and a return tank.
•	HPU operates between 85barg and 110barg.
•	Platform shutdown set at 80barg on loss of hydraulic power.

7.5. Diesel:
•	Diesel supplied from supply boats via a manually operated system with a filter.
•	Diesel transfer by electric motor-driven centrifugal pumps to the diesel storage tank.
•	Distribution to power turbine via filter and automatically operated electric motor-driven centrifugal pumps.
•	Main consumers include power generation units, emergency diesel generators, firewater pumps, and lifeboats.
•	Whole system made of carbon steel.

7.6. Fresh Water:
•	New fresh water maker package installed on QP2 (Two trains of reverse osmosis, 42m3/d).
•	Fresh water provided from PP/QP2 to PP, MCP, LCP, and WP1.
•	Used for toilet, HVAC, and various utility stations.
•	WP2, WP3, and WP4 use rainwater collection or boat transfer for sanitary needs. 

7.7. Electrochlorination:
•	Chlorine produced on QP2 used for shock dosing in firewater pump caisson on PP.
•	Firewater treated from QP2 or PP.
•	No chlorine from electrochlorination unit supplied to MCP and LCP.


7.8. Corrosion Inhibitor:
•	Wet gas is corrosive, requiring corrosion-resistant materials in surface facilities.
•	Corrosion inhibitor injected from wellhead platforms into carbon steel sea-lines.
•	Injection skids on each remote platform include storage tanks and injection pumps.
•	CI manually transferred to platform tanks, with injection rates controlled and optimized.
•	CI injection rates adjusted to achieve 60-80 ppm residual level at PP.
•	Downstream of glycol contactor, gas is dry and not corrosive, so CI injection not required on export pipelines.

7.9. Seismic Monitoring System:
•	Monitors and records earthquakes in the Yadana offshore complex.
•	Composed of one seismic sensor (above-sea), GPS antenna on PP platform roof, cabinet with 2 seismic recorders, and monitoring desktop in PP's technical room.
•	Additional cabinet with monitoring desktop in QP2 control room.
•	Data acquisition performed by recorders, stored internally on Flash-cards.
•	Monitoring desktops not for on-site data analysis; data analyzed by GEOTER's expert in France.









8. Safety Systems

8.1. Emergency Shutdown and Blowdown Overview:
1.	ESD Levels:
•	ESD Level 0: Abandon installation, initiates a black shutdown.
•	ESD Level 1: General emergency shutdown, closes all ESVs and initiates blow-down.
•	ESD Level 2: General process shutdown, stops production.
•	ESD Level 3: Individual process shutdown.

2.	Initiation:
•	ESD0 initiated automatically on confirmed gas detection or manually with approval.
•	ESD1 initiated by F&G system and push buttons.
•	ESD2 initiated by key safety switches and push buttons.

3.	Control and Connectivity:
•	Each platform is equipped with its own ESD system.
•	Connected to the Control Room via hardwire link or telemetry system.
•	PLC used for ESD control, with operator interface and DCS console.

4.	Execution:
•	Local independent electro-hydraulic panel for shutdown execution.
•	ESD actions can be initiated from the Control Room.

5.	Resetting and Testing:
•	Local resetting required on ESVs and SDVs after any ESD level.
•	BDVs can be reset from the Control Room.
•	Partial stroking facilities for ESD Valve Function testing.

6.	Additional Notes:
•	ESD 0 push buttons hardwired to platform ESD systems.
•	Dedicated HS for blowout disabling during rig operation.
•	Partial stroking facilities for ESV valves for testing purposes.

8.2. Flare

8.2.1. New Flare FP2
•	Reason for Replacement: Due to subsidence, the existing flare (FP) was replaced by FP2.
•	Location: FP2 is situated northwest of MCP.
•	Components: Includes a jacket piled in the seafloor, a 100m flare mast with 2 flare tips (HP & LP), and a bridge linking it to MCP.
•	Operation: Flare ignition panel on MCP manages pilots and fuel gas supply, with a sonic flare tip to reduce radiation.
8.2.2. HP & LP Flare
•	Expansion Joints: Equipped with 5 expansion joints each to absorb platform movements.
•	System Design: Flare lines are sloped to avoid liquid accumulation, made of carbon steel for low-temperature service.
8.2.2.1. HP Flare Network
•	Purpose: Collects relief from pressurized equipment during emergencies.
•	Depressurization: Controlled blowdown valves facilitate process depressurization.
•	Capacity: Designed to handle up to 960 MMSCFD, with provisions for partial depressurization.
•	Purge Gas: Continuous purging with fuel gas, with inert gas connections for backup.
8.2.2.2. LP Flare Network
•	Connections: Links low-pressure equipment to the LP flare.
•	Peak Flow Rate: Sized for a peak flow rate of 12 MMSCFD.
•	Purge Gas: Continually swept by purge gas, with provisions for manual adjustment.
•	Separation: Liquid droplets separated from gas in a vertical knock-out drum.

8.2.2.3. Ignition Panel
•	Function: Controls pilot gas feeds and flare ignition for both LP and HP flare tips.
•	Operation: Pilot gas and instrument air are mixed for ignition, monitored by an ionization detection system.
•	Safety: Flame monitoring ensures re-ignition in case of flame out, with temperature monitoring at the pilot level.

8.3. Fire Water
•	System Description: The fire water system serves WP1, PP, LCP, and MCP, utilizing a combined ring main system supplied with seawater by 3x50% diesel-driven pumps.
•	Pump Locations: Two pumps are on QP2 (750 m3/h at 9.9 barg) and one on PP (735m3/h capacity at 10 barg), each with its own 12-hour diesel day tank.
•	Jockey Pumps: Two electrical jockey pumps (2X100%) on QP2 (each of 45m3/h capacity at 11.7 barg) maintain network pressure.
•	Construction: The (wet) firewater ring main is in GRP, supplying firewater to deluge valve sets. Deluge valve sets have 2x100% deluge valves, and low pressure starts another jockey pump. The (dry) deluge network is in copper/nickel.
•	Bridge Supply: Firewater is supplied to bridges to MCP and LCP via two 100% lines, positioned to minimize damage from missiles and blast overpressure.
•	WP2, WP3, WP4: No automatic fire water supply; water will be supplied from boats or rig if needed. A dry firewater ring is connected for hook-up to the rig during drilling.
8.4. Black Start
•	Purpose: To reset and restart the Yadana Complex after a Total Black-out Shutdown.
•	Understanding: It's vital that production personnel, especially the Control Room Operator and Production Supervisor, fully understand the causes and extent of power loss and plant status.
•	Procedure: Initiated after total power loss and depressurization, including UPS and battery backup. Navaids remain on. Steps include checking initial status, assessing causes/effects, ESD checks/actions, installation power-up, preparation for startup, and compressors startup.
•	Training: Annual black start table talk exercises are performed by site operation management to revise associated operating procedures accordingly.
8.3. Fire Water
•	System Description: The fire water system serves WP1, PP, LCP, and MCP, utilizing a combined ring main system supplied with seawater by 3x50% diesel-driven pumps.
•	Pump Locations: Two pumps are on QP2 (750 m3/h at 9.9 barg) and one on PP (735m3/h capacity at 10 barg), each with its own 12-hour diesel day tank.
•	Jockey Pumps: Two electrical jockey pumps (2X100%) on QP2 (each of 45m3/h capacity at 11.7 barg) maintain network pressure.
•	Construction: The (wet) firewater ring main is in GRP, supplying firewater to deluge valve sets. Deluge valve sets have 2x100% deluge valves, and low pressure starts another jockey pump. The (dry) deluge network is in copper/nickel.
•	Bridge Supply: Firewater is supplied to bridges to MCP and LCP via two 100% lines, positioned to minimize damage from missiles and blast overpressure.
•	WP2, WP3, WP4: No automatic fire water supply; water will be supplied from boats or rig if needed. A dry firewater ring is connected for hook-up to the rig during drilling.
8.4. Black Start
•	Purpose: To reset and restart the Yadana Complex after a Total Black-out Shutdown.
•	Understanding: It's vital that production personnel, especially the Control Room Operator and Production Supervisor, fully understand the causes and extent of power loss and plant status.
•	Procedure: Initiated after total power loss and depressurization, including UPS and battery backup. Navaids remain on. Steps include checking initial status, assessing causes/effects, ESD checks/actions, installation power-up, preparation for startup, and compressors startup.
•	Training: Annual black start table talk exercises are performed by site operation management to revise associated operating procedures accordingly.


9. Logistics

9.1. Aeronautical Operations
•	Personnel Transfer: Chopper from Yangon airport to QP2 platform, with refueling facilities available on QP2. WP1 helideck used when QP2 helideck is unavailable. WP2 and WP4 flights depend on operational requirements, with personnel transfer by workboat.
•	Procedures: Covered maximum passengers per flight, flight frequency (currently 3/week), flight restrictions during the monsoon, and emergency flights for MEDEVAC.

9.2. Marine Operations
•	Supply Vessels: Two vessels available, one stays on field for personnel transfer to WP2, helicopter standby, and FIFI standby, while the other supplies equipment and food.
•	Firefighting: Vessels equipped with firefighting capacity, including fire pumps and monitors.
•	Anti-Pollution: Limited anti-pollution system with foam monitor and dispersant tank.
•	Workboat: Placed on LCP platform, personnel transfer to WP2, WP3, & WP4 done using workboat. No supply vessel tie-up requirement for equipment transfer or well servicing.
•	Transfer Operations: Use of platform crane or rig crane for equipment transfer. Stand-by boat required for personnel transfer when personnel present on platforms.
•	Mooring: WP2 and WP4 equipped with pad eyes for supply vessels. WP3 mooring lines designed for maximum estimated force, maintaining safe distance from platform legs.
•	Access Arrangement: V-shaped ladder and high absorption fender for transfer vessel. Platforms equipped with V-shaped ladders and access platforms for sea access, with two levels of ladders and access platforms required for transfer at any tidal amplitude.
•	Personnel Transfer: Combination of direct boat transfer and lifting by crane and basket depending on boat type and sea conditions, with direct boat transfer for field operator and crane operator, and lifting for the rest of the crew.



10. Telecommunication Systems

10.1. Satellite Earth Station Equipment
•	Private satellite network connects offshore platforms, Yangon, PLC (KBK & Daw Nyein), and Thailand.
•	Controlled from Yangon earth station acting as a hub.
•	Bandwidth allocated for different satellite hops.
10.2. TOIP & Cisco Analog Voice Gateway telephone system
•	Telephone network installed on multiple platforms with gateways in QP2.
•	Analog Voice GW interfaces with radio transceivers and INMARSAT earth station.
10.3. Public Address/Alarm System
•	Installed on multiple platforms for safety announcements.
•	Fully duplicated with independent coverage for each platform.
•	Interfaced with Fire and Gas system for automatic General Platform Alarm (GPA).
10.4. Optical Fiber System
•	Used for telecommunication links and CCTV data control.
•	Dedicated fibers for ESD, F & G, PCS systems, and CCTV transmission.
•	Duplicated for redundancy.
10.5 INMARSAT system
•	Thuraya INMARSAT Ship Earth Station installed on PP platform for backup communications to shore.
•	Patched into PABX for platform telephone extensions.
10.6. Aeronautical VHF radio
•	Provides communication with helicopters on private aeronautical channel.
•	Backup VHF transceiver available in HLO Room.
10.7. Marine VHF Radio
•	Fixed and portable radio equipment for marine operations.
•	Two marine VHF transceivers installed in QP2 Control Room.
•	Intrinsically safe marine VHF hand portable radios provided.
10.8 Lifeboat Radio Equipment
•	Each lifeboat equipped with type-approved marine VHF radio and Emergency Position Indicating Radio Beacon.
10.9. VHF Radio Network
•	Provides communication within the field during operations, maintenance, and safety.
•	Interfaced with PABX for communications via telephone network.
•	Installed on QP2 platform, with intrinsically safe hand portable radios provided.
10.10. VHF Paging System ( Cancelled )
10.11. MF/HF SSB Radio
•	Allows voice communication between QP2 platform and onshore marine radio stations.
•	Backup communications to shore terrestrial and marine radio stations, helicopters, and ships.
10.12. Non-Directional Beacon (NDB)
•	Installed for approaching helicopters, with control units in Radio Operator's Room and HLOR.
10.13. Crane Radios
•	Used for VHF communications between crane operators and deck crew/supply vessels.
•	Enables hands-free operation with foot switch.
10.14. UHF Radio System
•	Digital UHF radio link for QP2-WP3 communication, supporting Voice, Data, and SCADA communication.
10.15. CCTV System
•	Color CCTV cameras installed on WP2 and WP4 platforms, with video transmitted back to QP2 via dedicated optical fibers.
•	Control unit available on Process/Safety Operator's Console.

10.16. Yadana Intrusion Monitoring System/Marine Surveillance System
•	Radar installed on QP2 for marine surveillance and collision avoidance.
•	Provides comprehensive marine management and logistic system.
10.17. Meteorological System
•	Monitors parameters for helicopters and marine operations, including wind speed/direction, atmospheric pressure, temperature, humidity, current, and wave height.
10.18. E-POB System
•	Electronic system installed to monitor POB and track personnel location.
•	Card readers installed at various locations, connected to main software and database in QP2.


11. Medical Emergency

•	QP2 platform has a clinic and a medic to stabilize patients before evacuation.
•	Evacuation is typically done by helicopter to Yangon airport.
•	Local contracts are arranged to transfer the casualty to the most suitable hospital upon arrival in Yangon.


12. Simultaneous Operations (SIMOPS)

•	Periods of simultaneous drilling operations and gas production are managed according to COMPANY policies.
•	When the drilling rig is on-station, it's linked to the fire & gas/ESD system of the wellhead for manual ESD activation.
•	Typically, ESD input from the rig to a wellhead platform is at ESD1 level, with manual control.
•	During SIMOPS, procedures are in place to ensure safety, such as manual depressurization valves and stopping production on adjacent wells during specific operations.
•	Hot work during drilling or well operation is prohibited.
•	A complete survey is conducted before starting any simultaneous operations to finalize procedures and required protections.
•	Various well operations, including wire line operations, are conducted according to established guidelines and safety measures.



______________________________ Next Chapter:

SSHE


About SSHE
Importance and Mission

At PTTEP, safety is one of our business principles under the aspiration to achieve zero accidents (Target Zero). A proactive safety culture has been instilled and emphasis is placed on personal safety of all workforce and process safety of our facilities. The Company implements the Safety, Security, Health and Environment (SSHE) Management System that is in line with our SSHE policy and complies with international standards and industries best practices, to ensure that everyone working with the Company returns home safely and that accidents are prevented to avoid causing impacts on stakeholders and the environment.

SSHE Vision and Missions
Vision
PTTEP will be a zero incidents organization and the energy partner of choice where SSHE is regarded as a license to operate.

 

Missions
To achieve zero incidents through personal and process safety management.
Recognize the contribution of SSHE towards competitive performance and innovation for long term value creation.
Comply with the SSHE management system which is subject to continuous improvement, and seek opportunities for SSHE transformation.
Prepare for and respond effectively to emergencies, crisis and security-related events.
Create  a generative  SSHE culture  that  is based  on  leadership  at  every level  including contractors and where everybody understands the crucial importance of SSHE risks.
Achieve top quartile SSHE performance in the exploration and production industry.
 

Goals
Achieve zero incidents ( Target Zero )
Emphasize personal safet of all employees and contractors and process safety of all facilities
Safety, Security, Health and Environment Policy (SSHE)
SSHE is a core value for PTTEP. Adherence to SSHE standards is required to ensure the safety and health of everyone involved in our operations and communities where we operate, environmental protection and the security of our people and assets. A lifecycle SSHE management approach is required. A generative SSHE culture will help to achieve our vision of being incident free with the key objective of sustainable development.

 

PTTEP shall:

Work to achieve and sustain a generative SSHE culture driven by accountable leadership and involvement of all employees and contractors. 
Fundamentally SSHE performance is a line management.
Set measurable SSHE objectives, key performance indicators and targets that are used for continuous improvement for top quartile performance.
Recognize compliance obligations with all applicable SSHE laws wherever we operate or the requirements of the PTTEP SSHE management system, whichever is the most stringent.
Manage personal and process safety risks by identifying, analyzing, evaluating and treating them using the As Low As Reasonably Practical principle (ALARP).
Work with contractors and suppliers to achieve PTTEP's SSHE requirements.
Continuously reinforce employees and contractors right to use of the Stop Work Authority (SWA).
Apply Management of Change principles to administrative, organizational and engineering changes to ensure risks remain As Low As Reasonably Practical (ALARP).
Improve SSHE performance by investigating and learning from incidents and implementing audits and reviews.
Plan and prepare for emergencies and crises by providing resources, training and holding regular drills and exercises.
Promote employee and contractor's health as part of an effective health management system.
Apply a drugs and alcohol free workplace program to all employees and contractors. The use or possession of drugs and alcohol while working or driving are strictly prohibited.
Reduce greenhouse gas emissions aligned with the pathway to a low carbon future.
 

The successful implementation of SSHE policy requires total commitment from PTTEP employees and contractors at all levels.

Aspiring to be a leading energy partner, PTTEP sets a goal to be a zero-accident organization that boasts excellent SSHE performance.


___________________________________________ More on SSHE:


Understanding SSHE MS
The Safety, Security, Health, and Environment Management System (SSHE MS) is a
structured process utilized in lowering the risk and consequence of incidents.
The PTTEP SSHE MS consistsof7keyelements:
Introduction
The PTTEP SSHE Management System, a reflection of the organization's vision and
missions, is essential for the efficient operation of all SSHE and SSHE-related activities.
This system is properly structured and implemented, serving as a basis for operational
andrisk management.The successof thesystem dependsonthecommitment of PTTEP
employeesandcontractorsatall levels.
The SSHE MS is aligned with the International Association of Oil & Gas Producers (IOGP)
andinternational standards, for example, ISO 14001 Environmental Management System
andISO 45001 Occupational Healthand Safety Management System.
The PTTEP SSHE MS comprisesseven(7)keyelements,asexhibitedbelow.
2
SSHE MS Element Addressing
Leadership and Commitment Top-down commitment and SSHE culture, essential to the
success of the SSHE MS
Policy and Strategic Objectives Corporate intentions, principles of action, and aspirations
with respect to SSHE
Organization, Resources, and
Documentation
Organization of people, resources, and documentation for
sound SSHE performance
Evaluation and Risk Management Identification and evaluation of SSHE risks, for activities,
products, and services, and development of risk reduction
measures
Planning and Operational Control Planning the conduct of work activities, including planning
for changes and emergency response
Implementation and Monitoring Performance and monitoring of activities, and how
corrective action is to be taken when necessary
Audit and Review Periodic assessments of SSHE MS performance,
effectiveness, and fundamental suitability
SSHE MS
PTTEP
Elements
Element
Leadership and Commitment
Leadership and commitment from the top management are the foundation of the
SSHEMS. Managementatall levelsshall:
▪ Adopt the PTTEP SSHE policyandstrategicobjectives.
▪ Effectively communicate the PTTEP SSHE policy to all personnel under their
authority, including contractors, to ensure a safe, secure, and healthy
workplace.
▪ Demonstratestrong,visibleleadershipandcommitment.
▪ Have personal involvement and readiness to provide adequate resources for
SSHEmatters.
▪ Foster active involvement of employees and contractors in improving SSHE
performance.
▪ Participate with employees and contractors in the development and
maintenanceof the"SSHE Culture“.
Element
Policy and Strategic Objectives
The PTTEP SSHE Policy addresses the Corporate SSHE objectives, aspirations,
principles of action, and commitments with respect to SSHE with the aim of
improvedperformance.For thecompanytoachieveits SSHE Visionand Missions:
▪ SSHE policyshallbe:
▪ Implementedandsupportedbyall PTTEP organizations.
▪ Communicated,provided,or readily available toall stakeholders inthe local
languages.
▪ Displayedatcompanies' facilitiesandcontractors'officesonsite.
▪ Containedineveryinvitationtotender,andinallcontract requests.
▪ Availableinthe SSHE Intranet.
▪ SSHE due diligence shall be conducted prior to deciding to proceed with an
investmentopportunity.
▪ Corporate SSHE will assist with influencing all stakeholders, including Joint
Venturestoachievestandardsequivalent to PTTEP SSHE requirements.
Supporting Standard
Corporate SSHE Plan, SSHE KPI’sand Performance Monitoring Standard
This standarddescribes theprocessofdeveloping,endorsing, implementing, and monitoring
annual Corporate SSHE strategic direction, SSHE plans, and SSHE indicators at the Corporate
andFunction Group/ Division/Department level.
The Corporate SSHE strategic direction is set out to align with the Company’s strategic
direction. The means by which the Corporate SSHE strategic direction is translated into practical
actions is by SSHE Plans at Corporate and Function Group levels. The outcomes of SSHE
management are by measuring SSHE performance andcomparing results to a set of leadingand
lagging SSHE indicators with defined targets. It is to ensure continuous improvement in SSHE
performanceandachievetheultimategoalofbecomingazero-incidentorganization.
Element
Organization, Resources and Documentation
Thekeyobjectivesof thiselementareto:
▪ Structure and allocate resources appropriate to the development and
implementationof the SSHEMS.
▪ Standardize establishment, control, and periodically review of SSHE MS
documents.
▪ Ensure all SSHE-related matters are acknowledged and resolved through the
participation of and consultation with employees, contractors, and interested
parties.
▪ Ensure PTTEP andcontractorstaffhavethe minimum SSHE competencylevels.
▪ Ensurecompliance withrelevant legislationandother requirements.
Corporate Oversightof SSHEMS Standard
This standard summarizes the mandatory essential requirements written in the individual
SSHE standards, procedures, and guidelines that assets, projects, and service providers to the
assets/projectsshall follow. Ithighlightshow Corporate SSHE conductsthisoversightactivity.
SSHE Communication Standard
This standard describes the processes needed for internal and external communications
relevant to SSHE management system, including the processes for consultationandparticipation
of employees and contractors at all applicable levels and functions or their representatives to
ensure that all SSHE information is effectively communicated throughout the organization.
Consultation and involvement of all employees, contractors, and interested parties shall be
effectively implemented to promote successful SSHE activities, programs, and a positive SSHE
culture.
Supporting Standards
Element
Organization, Resources and Documentation
SSHE Trainingand Competency Standard
This standard outlines the minimum requirements of SSHE training and competency in
PTTEP as a reference for all PTTEP and Subsidiaries toimplement. It is toensure thatall staff and
contractors have received adequate training and obtainedsufficient knowledge and competency
necessary for executing their assigned tasks and activities according to the requirements of the
SSHE MS and related laws and regulations of the countries that PTTEP and Subsidiaries operate
thebusinessin, toensureregulatorycomplianceofsuchcountries.
SSHE Regulatory Compliance Standard
This document sets out a process to determine and access SSHE compliance obligations
pertinent to PTTEP’s hazards and environmental aspects and how these compliance obligations
apply. The documented information regarding the applicability review of compliance obligations
shall be maintained, kept up-to-date, and communicated to all employees and contractors
working under the control of PTTEP, and other related stakeholders. In addition, to ensure the
status of compliance with applicable compliance obligations and the effectiveness of prevailing
controls, the SSHEMS complianceauditsshallbecarriedoutonaregularbasis.
(Examples) Supplementary SSHE Procedures
▪ SSHE Contractor Management Procedure
▪ SSHE Documentation Management Procedure
Supporting Standards
Element
Evaluation and Risk Management
All activity significant risks shall be identified, prioritized, and managed effectively.
The Hazard and Effects Management Process (HEMP) is used to identify, evaluate,
and determine effective controls for SSHE hazards associated with all activities and
at everyprojectphase. Moreover, all identifiedrisks shallbe managedtobe As Low
As Reasonably Practicable(ALARP).
SSHE Risk Management Standard
The primary objective of SSHE Risk Management is to ensure that all SSHE risks, including
Major Accident Events (MAE), to whichpeople, environment, assets, andreputationare exposed,
aresystematically identified, risks areevaluated,and measures for reducingthem to ALARP levels
are put in place, documented, and maintained. This allows the management of uncertainty on
PTTEP’s SSHE objectives.Thestandardfollows theprinciplesof,e.g., ISO 17776, ISO 31000, ISO
31010,etc.
Safety Case Standard
The purposes of this standard are to define the requirements for Safety Case, outline the
principleprocessofdevelopinga Safety Case, andspecify what shallbedeliveredat each phase
throughout thefacilitylifecycle.
The Safety Case is the means of ensuring and demonstrating that suitable and sufficient
measures are in place to prevent MAEs or high-risk hazards and reduce the effects of these
events. The regular reviewing and reference to the Safety Case shall also ensure continuous
improvement insafetyperformance.
Supporting Standards
Element
Evaluation and Risk Management
Process Safety Management Standard
Process Safety Management is concerned with the prevention of MAE that can occurduring
the drilling and servicing of wells, and production and processing of hydrocarbons, i.e., those
accidents that may cause multiple fatalities or equivalentenvironmentaldamage,productionloss,
plantdamage, andreputationdamageasper PTTEP Risk Assessment Matrix.The most important
aspectofprocess safety is ensuringthat inherently saferdesigns are incorporatedinearlyproject
phases,particularly concept selection, andbasic anddetailedengineering.Thescopefor making
keydecisionsthatcanaffectprocesssafetysignificantlyisoptimalat thistime.
(Examples) Supplementary SSHE Procedures
▪ Environmental Impact Assessment for Exploration, Production, and Decommissioning
Procedure
▪ Health Risk Assessment Procedure
Supporting Standards
Element
Planning and Operational Control
Thekeyobjectivesof thiselementareto:
▪ Addresstheplanningof workactivitiesthroughthe SSHE plan.
▪ Provideguidanceto SSHE activities.
▪ Managepermanentandtemporarychanges inpeople,processes, andplants to
avoidadverseconsequences.
▪ Establishandimplementemergencyandcrisis managementplans.
Emergencyand CrisisManagement Standard
Emergency and crisis management has three primary objectives, i.e., minimizing the
probabilityof athreatoremergency, mitigatingtheimpact if theeventoccurs, recoveringfrom the
emergency, and resuming normal operations. The typical emergency and crisis management
process involves prevention and mitigation, preparedness, response, and recovery phases. The
mitigationphaseis thefirstprocess togather resultsofhazardidentificationandriskassessments,
impact analyses, operational experience, cost-benefit analyses, results of incident investigation,
and lessons learned from previous emergencies. The preparedness phase is essential to the
company’s operations to prevent fatalities and injuries. Also, it reduces damage to the
environment,property, andcompany reputation. The responsephasedescribesnotifications and
team activations, including communication during emergencies. The last process is the recovery
phase whichisrelatedto Business ContinuityManagement (BCM)
Supporting Standards
Element
Planning and Operational Control
EnvironmentalManagement Standard
The Environmental Management Standardhasbeendevelopedtoprovide anoverview ofour
environmental management strategy and its requirements. The main objective of this standard is
to assist all operating assets to properly manage the company’s environmental aspects and
impacts within environmentally sound management practices, which include compliance with
regulations and the Company requirements, ensuring the mitigation and prevention of
environmentalpollution,andencouragingforacontinuousimprovementculture.
Climate Change Management Standard
The Climate Change Management Standard was developed to assist PTTEP in integrating
climate change management into every phase of E&P activities, including all phases of project
development.This standarddemonstrates thecompany’s commitment from thetop management
toreduce GHG emissionsandalign withthepathwayofalow carbonfuture.
Security Management Standard
This standard covers Corporate level requirements for use by operations and activities
undertaken by PTTEP at all levels. The process of regularly assessing Security risks along with
their evaluation and reporting, design, and implementation of cost-effective security measures,
and continually communicating and advising the workforce on how best to manage security risk
shallbeappliedinallcases.
Supporting Standards
Element
Planning and Operational Control
Supporting Standard
Operational SafetyManagement Standard
This standardprovides aframeworkfor managingoperational safety intheactivities whichare
carried out in the exploration and production of oil and gas, both onshore and offshore. The
purposesof thisstandardareto:
▪ Ensure that all operational activities, which need to be carried out in PTTEP, have the
necessary mechanisms andprocesses in place to manage hazards andrisks,both innormal
operating conditions (routine and non-routine activities), Simultaneous Operations (SIMOPS),
anddegradedcondition whenManagementof Change(MOC) isrequired.
▪ Prevent all workplace injuries by encouraging active workforce participation in all aspects of
safetyincludingparticipationinthehazard managementprocess.
▪ Ensurethatallemployeesarecompetent tofulfill theirduties.
▪ Protect,promote,and maintain workplacesafety.
Managementof Change Standard
The purpose of the Management of Change (MOC) Standard is to specify minimum
requirements for systematically managing the changes to any operations, organization,
administration, or regulation (codes and standards) to ensure that any risk or hazard arising from
thatchangeisidentified,assessedandcontrolled,andbusinessactivitiesdonotgetoverlooked.
Element
Planning and Operational Control
Occupational HealthManagement Standard
Thepurposesofoccupationalhealth managementareto:
▪ Protect,promote,and maintainthehealth,safety,and welfareofpeopleat work.
▪ Advise on the provision of safe and healthy conditions by informed assessment of the
physical/psychologicalaspectsof the workingenvironment.
▪ Identify and advise management on the causes of occupational disease and injury and the
meansof theirprevention.
▪ Advise on the rehabilitation and placement in suitable work of those temporarily or
permanentlyincapacitatedby illnessor injury.
▪ Assist intheplanningandpreparednessofemergencyresponseplans.
This standard will cover, for example, Health Risk Assessment (HRA) and planning, industrial
hygiene and control of workplace exposures, medical emergency management, fitness to work
assessmentandhealthsurveillance,etc.
Supporting Standards
Element
Planning and Operational Control
Life-Savingand Process Safety Rules Standard
The Life-Saving and Process Safety Rules Standard is adopted from The International
Association of Oil & Gas Producers (IOGP) Life-Saving Rules Report No. 459, and Process Safety
Fundamentals Report No. 638, respectively. It aims to provide PTTEP’s employees and
contractors with the actions they can perform to protect themselves and their colleagues from
fatalities and to prevent process safety incidents. Implementing the Life-Saving and Process
Safety Rulesaimstoachievethecompany’svisionofbeinga“ZeroIncident Organization”.
(Examples) Supplementary SSHE Procedures
▪ ChemicalManagement Procedure
▪ Crisisand EmergencyManagement Plan
▪ Lifting Operation Safety Procedure
▪ Permit to Work Procedure
▪ SpillManagement Plan
Supporting Standards
Element
Implementation and Monitoring
Thekeyobjectivesof thiselementareto:
▪ Assesstheimplementationandeffectivenessofexistingcontrols
▪ Evaluate SSHE performancecoveringallaspects
▪ Manage accidents and near misses with real and potential
consequencesviatheincident reportingandinvestigationprocess
Supporting Standards
IncidentManagement Standard
This standardprovides an incident reportingandanalysisprocess to ensure that all incidents
are reported, investigated, and logged properly as a lesson learned. This standard sets the
minimum requirements in PTTEP Asset for reporting, investigating, and following up on all
incidents, including High Potential Incidents (HPIs), near misses, external complaints, noncompliance,andothers. Keyrequirementsof IncidentManagementare:
▪ Incidentshallbeimmediatelynotifiedandreportedasperseveritycriteria.
▪ All incidents shall be investigated and provided recommendations for corrective and
preventiveandfolloweduptocloseout thoserecommendations.
▪ All incident recordsandstatisticsshallbeanalyzedfor reoccurrenceprevention.
▪ Incident lessonslearnedshallbepreparedandcommunicatedtoallconcernedparties.
SSHE Culture Management Standard
The purpose of this standard outlines the consistent management and implementation of the
SSHE culture management process. It also provides tools and techniques for SSHE Culture
development toachievethegenerativelevel.Thekeyobjectivesof thisstandardareto:
▪ Implement the SSHE culture program by identifying their SSHE culture maturity level and
havingaplaninplacetocontinuouslyimprovetheir SSHE culture.
▪ Implement Behavioral Based Safety (BBS) programs to improve behavioral processes in
reducingincidentstriggeredbyunsafeactsorat-riskbehaviors.
(Example) Supplementary SSHE Procedure
▪ Environmental Performance Reporting Procedure
Element
Audit and Review
Thekeyobjectivesof thiselementareto:
▪ Periodically review and verify the effectiveness of SSHE MS implementation to
ensure the adequacy of controls and status of compliance with applicable
legislationandother requirements
▪ Documentand manageaudit resultstoclosure
Supporting Standard
Auditand Review Standard
This standarddescribes therequirements for auditandreview plans, theplanning,execution, and
closeout of audits, and continuous improvement of the SSHE auditing process. The audit
standardestablishesauniformmethodfor managing SSHE auditingin PTTEP todetermine:
▪ If SSHE MS elements and activities comply with planned arrangements and are effectively
implemented.
▪ The capability of the SSHE MS to fulfill the SSHE policy, objectives, and performance criteria
of theasset.
▪ Thefulfillmentofpertinent legal requirements.
▪ Identification of areas for improvement that will result in progressively better SSHE
management.
The outcomes of SSHE audits and reviews are managed to facilitate the implementation of
changestoenhanceprocessesandreducerisks.


_____________
Important Glossary:(very important)

Name of Platforms in Yadama Asset:

WP1= wellhead platform 1
WP2= wellhead platform 2
WP3= wellhead platform 3 (Sein)
WP4= wellhead platform 4 (Badamyar)
QP2 = QUarter Platform
PP = Producrion Platform
LCP = low compression platform
MCP = Medium Compression Platform
FP= Flare Platform

1.	ESD Levels:
  
•	ESD Level 0: Abandon installation, initiates a black shutdown.
•	ESD Level 1: General emergency shutdown, closes all ESVs and initiates blow-down.
•	ESD Level 2: General process shutdown, stops production.
•	ESD Level 3: Individual process shutdown.


•	ESD0 initiated automatically on confirmed gas detection or manually with approval.
•	ESD1 initiated by F&G system and push buttons.
•	ESD2 initiated by key safety switches and push buttons.

•	Each platform is equipped with its own ESD system.
•	Connected to the Control Room via hardwire link or telemetry system.
•	PLC used for ESD control, with operator interface and DCS console.

•	Local independent electro-hydraulic panel for shutdown execution.
•	ESD actions can be initiated from the Control Room.

•	Local resetting required on ESVs and SDVs after any ESD level.
•	BDVs can be reset from the Control Room.
•	Partial stroking facilities for ESD Valve Function testing.

•	ESD 0 push buttons hardwired to platform ESD systems.
•	Dedicated HS for blowout disabling during rig operation.
•	Partial stroking facilities for ESV valves for testing purposes.

    Pipeline System:
•	36" pipeline transports gas (domestic and export) to delivery points at PLC and Thai border.
•	Offshore pipeline length: 346 km to coast. (Yadana offshore to Pipeline Centre)
•	Onshore pipeline length: 63 km. ( Pipeline centre to Metering Station)

•	Custody transferred to PTT of Thailand at border.
•	Gas further transported by 238 km long 42" pipeline from Metering station to Ratchaburi where main users are EGAT and TECO Power Plants.

    Pressure Requirements:
•	Required delivery pressure at EGAT power plant: 36.9 bar (550 psia).
•	Contractual delivery pressure at Thai border: Maximum 64.5 bar (950 psia).

    Gas Delivery:
MMSCFD = million standard cubic feet per day
•	Normal domestic gas supply to MOGE at PLC: 50 MMSCFD since June 2010.
•	Maximum export gas delivery to PTT: 720 MMSCFD with border back pressure around 53 barg (780 psig) by running PTT BVW7 compressors.
•	Maximum delivery to PTT recorded around 750 MMSCFD in May 2011.