MM-ZTK-1A-WP-PRO-BOD-0100 Rev. C1.Process Design Basis.pdf

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Zawtika Development Project , Phase 1A EPCIC of Zawtika Wellhead Platforms 1, 2 and 3 with Sea Lines \\Netstore-blr\10038\C10038\PROC\Final\DOCUMENTS\Design Basis\Rev C1\MM-ZTK-1A-WP-PRO-BOD-0100.doc

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TABLE OF CONTENTS 1.

INTRODUCTION…………………………………………………………………….……….…..5 1.1 1.2 1.3 1.4 1.5 1.6

General Overview of Zawtika Field Development……………......……..………….5 Overview of Facilities in Zawtika Wellhead Project Phase 1A……..….…..……..7 Abbreviations………………………..………………………………………..…………..7 Units of Measurement…………………………………………………….…………....10 Purpose of this Document………..………………………………………..………….11 Order of Precedence…………………………………………………………………....12

2.

ENVIRONMENTAL & SITE DESIGN REQUIREMENTS……………………………………13

3.

ZAWTIKA WELLHEAD PLATFORMS (ZWP) …………………………………….…………14 3.1 3.2 3.3 3.4 3.5 3.6

4.

Reservoir Data…………………………………………………………………………….15 Wellhead Platform Design Capacity ………………………………………………….17 Material and Corrosion……………………………………………………………….....17 Process Software…………………………………………………………………………17 Major Functional Requirement – WP1……..…………………………………………18 Major Functional Requirement – WP2 and WP3…..………………………………..18

MAJOR DESIGN FEATURES OF THE WELLHEAD PLATFORMS……………….……...20 4.1

Common Design Features of Wellhead Platforms WP1, WP2 &WP3....….….....20 4.1.1 Wellheads …………………………………………………………………………20 4.1.2 Flow lines, Test and Production Manifolds…………………………………23 4.1.3 Test Separator……………………………………………………………………26 4.1.4 Temporary Flare and Liquid Burner Connection…………………………..30 4.1.5 Booster Compressor (Future)…………………………………………………30 4.1.6 Drain System…………………………………………………………….…….....30 4.1.6.1 Hazardous Open Drain System…………………………….…….......30 4.1.6.2 Non-Hazardous Open Drain System……………………….………...30 4.1.6.3 Closed Drain System…………………………………………....……..31 4.1.7 Closed Drain Sump Vessel………………………………………….…….……31 4.1.7.1 Description for WP1…………..…………………………….……..…..31 4.1.7.2 Description for WP2 & WP3…………………………….….……..…..31 4.1.7.3 Design Criteria for WP1, WP2 & WP3……………………………....31 4.1.8 Closed Drain Sump Pump………..………………………………..……….…..32 4.1.8.1 Description for WP1……………..…………………………….….…...32 4.1.8.2 Description for WP2 & WP3…………………………………..………32 4.1.8.3 Design Criteria for WP1, WP2 & WP3……………….....…..……….32

4.2

Design Features Specific to Bridge Linked Wellhead Platform, WP1……..……33 4.2.1 Chemical Injection System………………..…………………….……...……...33 4.2.1.1 Antifoam/ Demulsifier Injection…………………………………….…33 4.2.1.2 Methanol Injection…………………………………………………......33 4.2.2 Relief & LP/ HP Flare Header…………………………….…………..………...33 4.2.2.1 Description…………………….…………………………………….….33 4.2.2.2 Design Criteria for Pressure Safety Valves…………………….......33 4.2.2.3 Design Criteria for Depressurization Device (BDV’s + RO)..…......34


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Condensate Handling & Disposal (Permanent Liquid Burner) ………....35 4.2.3.1 Description…………………….…………………………………….….35 4.2.3.2 Design Criteria………………………………….………………….......35 Diesel Fuel System……………………………………………………………...36 Other Features Specific to WP1…………..…………………………………..36

Design Features Specific to Remote Wellhead Platforms, WP2 & WP3……..…36 4.3.1 Chemical Injection System……………………………………..…………...…36 4.3.1.1 Antifoam/ Demulsifier Injection………………………..………….…..36 4.3.1.2 Methanol Injection…………………..………………………………….36 4.3.1.3 Corrosion Inhibition System…………………………………………...37 4.3.1.3.1 Design Criteria: Corrosion Inhibitor Tote Tank…………...37 4.3.1.3.2 Design Criteria: Corrosion Inhibitor Dosing Pump……….37 4.3.2 Vent Boom for Cold Venting…………………….……………………….…….38 4.3.2.1 Description…………………….…………………………………….….38 4.3.2.2 Design Criteria………………………………….………………….......38 4.3.3 Pig Launcher……………………………………….…………………….……….38 4.3.4 Pig Receiver (Future)…………….………………………………...……...........39 4.3.5 Instrument/ Utility Gas System………………………………..………...........40 4.3.5.1 Description for Instrument/ Utility Gas System……..….…………....40 4.3.5.2 Design Criteria……….……………………………………………........42 4.3.5.2.1 Utility Gas Knock Out Drum…………………………..........42 4.3.5.2.2 Instrument Gas Filter/Coalescer……………..………….....42 4.3.5.2.3 Finned Tube Natural Draft Cooler………………………….43 4.3.6 Diesel Fuel System………………………………………………….………......44 4.3.7 Potable Water/ Fresh Water………………………………………….………...44 4.3.8 Crane……………………………………………………………..…….…………..45 4.3.9 Power Generation System………………………………………….…….........45 4.3.10 Nitrogen……………………………………………………………….…………...45

PROCESS DESIGN CRITERIA…………………………………………………….………......46 5.1

Design Pressure……………………..…………………………………………….……..46 5.1.1 Wellhead System and Flow Lines……………………………………….........46 5.1.2 Piping………………………………………………………………………….......46 5.1.3 Pressure Retaining Equipment……………………………………..…………46 5.1.4 Pressure Vessels……………………………………………………….…..……47 5.1.5 Atmospheric Tanks…..…………………………………………….……………47 5.1.6 Pipeline……………………………………………………………….……………47

5.2

Design Temperature…………………………………………………………..…………47 5.2.1 Maximum Design Temperature………………………………….…………….47 5.2.2 Minimum Design Temperature……………………………………….………..47

5.3

Control Valves……………………………………………………………………….........48

6.

LIST OF CODES AND STANDARDS.………………………………………………..…..…...49

7.

REFERENCES……………………………………………………………..…….………..…..…50


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1.

INTRODUCTION

1.1.

General Overview of Zawtika Field Development The Zawtika Project is a gas field development project located in the Gulf of Moattama, Myanmar. The development area covers Block M9 and a small portion of Block M11, owned by Myanmar Oil & Gas Enterprise (MOGE). The field lies approximately 300 km south of Yangon and 290 km west of Tavoy on the Myanmar coast and the average water depth is approximately 135-160 meters (relative to LAT). Zawtika Development Phase 1A consists of ZPQ (Processing platform integrated with Living Quarter module), a bridged-link wellhead platform WP1, two remote wellhead platforms WP2 and WP3, associated intra-field sealines, offshore and onshore gas export to connect to the PTT gas pipeline at Ban-I-Tong, Onshore Operating Center (ZOC), Block Valve #1 and #2 (ZBV1 and ZBV2), and Metering Station (ZMS).

Figure 1.1: Zawtika Location


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Figure 1.2: Zawtika Phase 1A, 1B & 1C Development The design of the surface facilities is based on a Contractual Daily Capacity (CDC) of 345 MMscfd, delivered to the PTT pipeline at 1250 psia (85.2 barg) tie-in pressure. However, the gas processing capacity will be maximized for 400 MMscfd to use the full power available from the selected Gas Turbines (GTs) and to take credit for a minimum PTT tie-in pressure of 950 psia (64.5 barg). Gas will be exported through a new 28” diameter, 230km long offshore pipeline and 70km long onshore pipeline, which is designed to export the combined gas 600 MMscfd at the 1250 psia (85.2 barg) tie-in pressure. ZPQ compression is designed to meet the resulting offshore back pressure, with minimal, and preferably no onshore booster compression. The shore approach for the offshore export pipeline will be landfall at Mawgyi village. The Zawtika Pipeline Operating Centre (ZOC), where gas will be taken off for domestic use in Myanmar at a maximum of 69 MMscfd (corresponding to CDC @ 345 MMscfd), is located near Onbinkwin village.

A new onshore pipeline, same diameter as

offshore, will take the remaining gas (276 MMSCFD) to export to Thailand via PTT pipeline at Ban I-Tong (BIT) on the Myanmar-Thai Border.


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Overview of Facilities in Zawtika Wellhead Project Phase 1A Major offshore facilities in the Phase 1A Scope of Work include: i)

Zawtika Processing Quarters Platform (ZPQ), which is an integrated living quarters and processing platform;

ii)

Zawtika Wellhead Platforms, WP1, WP2 and WP3. WP1 is bridge linked to ZPQ platform, while WP2 and WP3 are remote wellhead platforms;

iii)

Gathering lines from WP2 and WP3 to ZPQ;

iv)

Offshore Export pipeline from ZPQ to shore.

Major onshore facilities include: i)

Onshore Operating Center (ZOC), which is a fully integrated operating facility for the onshore gas transmission system;

ii)

Block Valve #1 and #2 (ZBV1 and ZBV2), which enable isolation of the onshore pipeline;

iii)

Metering Station (ZMS), which is a facility near the Thai border providing custody metering;

iv)

1.3.

Onshore export pipeline from shore to Myanmar-Thai border.

Abbreviations BDV

Blowdown Valve

BOD

Basis of Design

BPD

Barrels Per Day (U.S.)

°C

Degrees Celsius

CDC

Contractual Daily Capacity

CFT

Call for Tender

CO2

Carbon Dioxide

CRA

Corrosion Resistance Alloy

dBA

Decibels Amplitude

DCQ

Daily Contractual Quantity

DCS

Distributed Control System

DHSV

Down Hole Safety Valve

ESD

Emergency Shutdown

ESDV

Emergency Shutdown Valve

F&G

Fire and Gas System

FOC

Fiber Optic Cable

FSO

Floating Storage and Offloading

GHV

Gross Heating Value


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GSA

Gas Sales Agreement

GT

Gas Turbine

HMI

Human Machine Interface

HP

High Pressure

HPU

Hydraulic Power Unit

HU&C

Hook-up and Commissioning

H2S

Hydrogen Sulphide

IG

Instrument Gas

LAH

Level Alarm High

LAL

Level Alarm Low

LP

Low Pressure

LQM

Living Quarters Module

LTV

L&T Valdel Engineering Ltd.

MAE

Major Accident Events

MAWP

Maximum Allowable Working Pressure

MCC

Master Control Centre

MDQ

Maximum Daily Quantity

MMSCF

million standard cubic feet

MMSCFD

million standard cubic feet per day

MOGE

Myanmar Oil & Gas Enterprise

MSL

Mean Sea Level

mSOT

Minimum Service Operating Temperature

MTO

Material Take-Off

MV

Master Valve

NGL

Natural Gas Liquid

PAHH

Pressure Alarm High High

PCS

Process Control system

PCV

Pressure Control Valve

PLC

Programmable Logic Controller

PO

Purchase Order

POB

Personnel on Board

ppmv

parts per million volume

ppmw

parts per million weight

ppbv

parts per billion volume

P&ID

Piping and Instrument Diagram

PFD

Process Flow Diagram


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Pressure Safety Valve Petroleum Authority of Thailand Exploration and Production International Limited

QMR

Quad Modular Redundant

RO

Restriction Orifice

RTU

Remote Telemetry Unit

SAFE

Safety Analysis Function Evaluation

SCADA

Supervisory Control and Data Acquisition

SCF

standard cubic feet of gas (@ 15.560C and 1.0156 bara)

SCS

Safety Control System

SDV

Shutdown Valve

SIL

Safety Integrity Level

SIS

Safety Instrumented System

SITP

Shut In Tubing Pressure

SSV

Surface Safety Valve (Master Valve, Wing Valve)

TAD

Tender Assist Drilling

TBA

To Be Advised

TEG

Thermo Electric Generator

TMR

Triple Modular Redundant

TOS

Top of Steel

TPH

Total Petroleum Hydrocarbons (in water)

TVD

True Vertical Depth

WGR

Water to Gas Ratio

WHIP

Wellhead Injection Pressure

WHCP

Wellhead Control Panel

WHFP

Wellhead Flowing Pressure

WHFT

Wellhead Flowing Temperature

WHP

Wellhead Platform

WHSIP

Wellhead Shut In Pressure

WPX

Zawtika Wellhead Platform (“X” designates platform number)

WV

Wing Valve

ZBV

Zawtika Block Valve Station

ZGS

Zawtika General Specification

ZMS

Zawtika Metering Station

ZOC

Zawtika Operating Centre

ZPQ

Zawtika Processing Quarters Platform


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Units of Measurement The Zawtika Phase 1A Project will use metric or SI system of units for all calculations, drawings and in all project documentation. Specific units of measurement to be used in this project are provided in the table below. Parameter

Units DIMENSIONS

Equipment Dimension Pipe length Pipe size

mm, m m Inch/ mm

Area Volume

m² m³

Time Distance

d, hr, s m, km PRESSURE

Pressure (absolute) Pressure (gauge) Liquid Head Stress Static Pressure Pressure drop

bara barg mbar, bar, mmH2O MPa (MN/m2), kPa (kN/m2) bar bar TEMPERATURE

Temperature

°C FLOWRATE

Mass Flowrate kg/hr Gas Volume Flowrate (Standard MMSCFD Conditions) Actual Liquid Volume Flowrate BPD, m3/hr, L/hr, L/day Liquid Volume Flowrate (at Standard STBPD conditions) Actual gas volumetric flowrate ft³/d, m3/hr PROPERTIES Amount of Substance

kmol

Density Dynamic Viscosity Kinematic Viscosity Weight/Mass Thermal Conductivity

kg/m³ cP cSt kg, tonne (1000 kg) kW/m-oC

Fouling Factor Velocity

m2.hr.°C/kJ m/s

Interfacial Surface tension

dyne/cm


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Parameter

Units

Mass velocity

kg/s

Particle Size Head Contaminant Concentration (mass) Contaminant Concentration (volume)

micron m ppm ppmv

Concentration mol % HEAT, ENERGY, WORK AND POWER Heat

kJ

Heat Flow/Duty Heat Flux Latent Heat Specific Heat

kJ/hr kJ/m2.hr kJ/kg kJ/kg.°C

Heat Transfer Coefficient Heating Value (Liquid)

kJ/hr.m2.°C kJ/kg

Heating Value (Gas) Btu/SCF Specific Enthalpy kJ/kg Volumetric Heat Release kJ/hr.m3 Power kW RADIATION, CONDUCTIVITY AND NOISE Radiation Noise

kW/m2 dB(A)

Notes: (1) Imperial Units may be given between brackets following the SI Units. (2) Standard Conditions are: 1.01325 bar (abs) and 15.55 °C (SI). (3) Standard Conditions are: 14.7 psia and 60 °F (Imperial). 1.5.

Purpose of this Document This document outlines the basis of the process design work which will be undertaken for Zawtika Phase 1A wellhead platform Detailed Engineering. It defines the design premises that cover all the detailed engineering parameters and essential data required to execute the process Design including. •

Environmental conditions for Zawtika offshore facilities;

•

Operating and design conditions for all equipment and the various systems;

•

Engineering design data to execute process simulations and various equipment, packages, and piping sizing calculations.


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It also describes about the proposed facilities in WP1, WP2 & WP3 for delivering the well fluid from wellhead platform to process complex (ZPQ) etc and the various codes and standards referred and software’s used. 1.6.

Order of Precedence The Order of Precedence shall be as follows, (1) Myanmar Government Laws, Rules & Regulation. (2) Zawtika Contract Documents (Including, Exhibits, and Annexes) (3) Zawtika General Specifications (4) International Standards such as API, NFPA, IP etc…


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ENVIRONMENTAL & SITE DESIGN REQUIREMENTS The Zawtika facility is located within the Northern Andaman Sea.

The area is

seismically active due to interaction of the main Eurasian, India and Sunda tectonic plates, as well as with the Burma microplate trapped between them. The facilities are to be designed in accordance with environmental criteria outlined in Zawtika General Specification ZGS-GEN-003 “Zawtika Site Conditions and Climate”. The platform is to be designed for 100 year and 1 year extreme storm conditions. Temperature: Maximum air temperature

:

33 deg C at 80% RH

Minimum air temperature

:

22 deg C at 75% RH

Minimum sea bed Temp

:

19 deg C

Minimum Atmospheric Pressure

:

100.6 kPa

Maximum Atmospheric Pressure

:

101.1 kPa

Pressure:


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ZAWTIKA WELLHEAD PLATFORMS (ZWP) Under the Zawtika development Phase 1A Project, two remote wellhead platforms (WP2 & WP3) connected via. intrafield pipeline and one wellhead platform (WP1) connected via. bridge linked to ZPQ (Processing Platform integrated with Living Quarter Module) shall be installed. These platforms shall provide for 20 slots of single wells through which gas/ condensate wells will be drilled and completed with Christmas Trees by PTTEPI. The production from these WHPs is routed to the Production Manifold through flow lines. The wellhead platforms (WP2 & WP3) shall be energized by solar power and TEG hybrid power supply system (30:70). The bridge connected WP1 shall receive power and other utilities from ZPQ (Via) bridge. The present scope of work envisages the following facilities for WP1, WP2, and WP3. WP1: a. Flow arms from Christmas Trees to Production manifold, Test manifold and Booster compressor manifold b. Production Manifold c. Test Manifold d. Space for Booster compressor Manifold (Future) e. Test separator f.

14” Export line to ZPQ

g. Space for Booster compressor (Future) h. Drain System i.

Space for Methanol Injection System for Start up purpose (to be accommodated inside Future Booster Compressor Package area).

j.

Permanent liquid burner (including auxiliary system)

WP2 & WP3: a. Flow arms from Christmas Trees to Production manifold, Test manifold and Booster compressor b. Production Manifold c. Test Manifold d. Space for Booster compressor Manifold (Future) e. Test separator f.

18” Export pipeline to ZPQ

g. Space for Booster compressor (Future) h. PIG Launcher Zawtika Development Project , Phase 1A EPCIC of Zawtika Wellhead Platforms 1, 2 and 3 with Sea Lines \\Netstore-blr\10038\C10038\PROC\Final\DOCUMENTS\Design Basis\Rev C1\MM-ZTK-1A-WP-PRO-BOD-0100.doc

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i.

Space for PIG Receiver (Future), 2 numbers each WP2 and WP3

j.

Corrosion inhibitor system (Present & Future)

k. Diesel system l.

Instrument and Utility Gas System

m. Utility water system n. Thermoelectric Generator (TEG) and Solar Panel System o. Export risers (18”) for WP2 & WP3 p. One 14” Import preinstalled riser in WP2 and One 18” Import preinstalled riser in WP3 q. Vent and Drain System r.

Provision for one (18”) Import riser each for WP2 & WP3

s. Space for Methanol Injection System for Start up purpose (to be accommodated inside Future Booster Compressor Package area). 3.1.

Reservoir Data Feed gas and condensate compositions for Zawtika Phase 1A Development Project are tabulated below in table 3.1 and 3.2.The reservoir data indicated below shall form the basis for simulation. Table 3.1: Feed gas compositions COMPONENTS

CASE 1

CASE 2

CASE 3

CASE 4

(Note 1)

H2S Hydrogen Sulphide 0 CO2 Carbon Dioxide 0.369 N2 Nitrogen 22.44 C1 Methane 75.717 C2 Ethane 0.723 C3 Propane 0.39 iC4 Iso-Butane 0.165 nC4 N-Butane 0.03 iC5 Iso-Pentane 0.028 nC5 N-Pentane 0.031 C6 Hexanes 0.032 C7 Heptanes 0.033 C8+ Octanes Plus 0.03 C6 Benzene 0.001 C7 Toluene 0.008 C8 Ethylbenzene 0.001 C8 O-Xylene 0.001 C8 M+P-Xylene 0 TOTAL 100 791.9 Saturated Gross Heating Value (BTU/SCF) 804.6 Dry Gross Heating Value (BTU/SCF) Note 1. This is the most likely case during operation. Zawtika Development Project , Phase 1A EPCIC of Zawtika Wellhead Platforms 1, 2 and 3 with Sea Lines \\Netstore-blr\10038\C10038\PROC\Final\DOCUMENTS\Design Basis\Rev C1\MM-ZTK-1A-WP-PRO-BOD-0100.doc

MOLE % 0 0 0.31 0.24 15.566 7.357 83.043 91.786 0.576 0.401 0.263 0.111 0.106 0.035 0.026 0.021 0.03 0.01 0.02 0.007 0.02 0.006 0.02 0.005 0.02 0.008 0 0.001 0 0.008 0 0.001 0 0.001 0 0.001 100 100 854.6 929.6 868.5 944.7

0 0.181 1.171 98.363 0.149 0.071 0.045 0.02 0 0 0 0 0 0 0 0 0 0 100 992 1008.4

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COMPONENT

Mole %

C1 C2 C3 C4 C5 C6 C7 C8 C9 C10 C11 C12 C13 C14 C15 C16 C17 C18 C19 C20 C21 C22 C23 C24 C25 C26 C27 C28 C29 C30 C31 C32 C33 C34 C35+ TOTAL API Gravity at 60 deg. F Density at 15 deg. C, g/ml Flash Point, deg. C Heating Value, Gross, cal/g


0 0 0.08 0.25 0.51 1.06 7.32 14.6 14.81 9.86 7.74 6.34 5.36 5.97 5.76 3.51 2.94 4.27 2.41 1.48 1.4 1.28 1.12 0.93 0.63 0.25 0.07 0.01 0.01 0.01 0.01 0.01 0 0 0 100 42.3 0.8139 ≤ 40 10468

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Wellhead Platform Design Capacity The following is the design capacity for the WP1 and shall be designed for the maximum capacity of: Gas Flow rate

: 100 MMSCFD

Condensate Flow rate

: 60 STBPD

Water Flow rate

: 4500 BPD

WGR

: 0 & 45 (BPD Actual/MMSCFD)

The wellhead platform WP2 & WP3 shall be designed for the maximum capacity of:

3.3.

Gas Flow rate

: 200 MMSCFD

Condensate Flow rate

: 60 STBPD

Water Flow rate

: 9000 BPD

WGR

: 0 & 45 (BPD actual/MMSCFD)

Material and Corrosion The composition provided does not contain H2S & there is limited 0.1-1 mole% CO2. However, for design purpose the following are to be used for material selection: •

50 ppmv H2S for material selection only – contingency;

•

5 mol % CO2 for material selection only-contingency;

•

Free water (liquid);

•

Sand production is expected and mitigation (down-hole sand screen and target tee for sand control) will be used for well completion design;

3.4.

•

1.8 µg / Nm3 Mercury;

•

0.001-22.4 mole% Nitrogen.

Process Software Following software shall be used for simulation during detail design phase. All process simulations

HYSYS Version 7.1

SMART Plant P & IDs

SMART Plant V.2009

LTV spreadsheets

In-house spreadsheets for line sizing, equipment sizing, PSV sizing etc…

Flare / Vent Hydraulics

Aspen Flare System Analyser V 7.1

Steady State / Transient analysis for pipeline hydraulics, Pipeline Blowdown, Topside dynamic process & control Study

OLGA 6.2


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Fire Water Steady State Hydraulic analysis

Pipenet Version 4.3

Topside Depressurization and Minimum Metal Design Temperature

HYSYS depressurization Utility

Thermal Design of heat exchangers

HTRI exchanger suite - 5

Major Functional Requirement – WP1 The main functional requirements for production operations for the bridge linked wellhead platform are provided below. i)

WP1 will be automated for not normally manned operations, with personnel presence required for maintenance and restart following emergency shut down only. Sufficient operating data is to be communicated to ZPQ to monitor the status of safety and production critical systems.

ii)

Main equipments such as test separator manifold and wellhead control panel will be located on the lower deck.

iii)

All systems will be controlled and monitored from ZPQ complex SCADA via Fiber Optic Cable (FOC).

iv)

Maintenance and other activities will be performed by routine platform visits.

v)

All wells can be tested remotely via ZPQ control room, which can route the well fluid to test separator, prior to combining flows into the export pipelines.

vi)

Crane, wellhead control, power, and lay-down deck space requirements for Well Service operation.

vii)

Automated fire suppression systems with deluge provided via ZPQ.

viii)

Navigation light.

ix)

Appropriate Safety equipment as denoted by Safety Concept document (i.e. fire extinguishers, first aid kit, emergency escape device, and so on).

3.6.

Major Functional Requirement – WP2 AND WP3 The main functional requirements for production operations for the remote wellhead platform are provided below. i)

The remote wellhead platforms are to be automated for not normally manned operations, with personnel presence required for replenishing consumables (e.g., corrosion inhibitor, diesel etc), maintenance and restart following emergency shut down only. Sufficient operating data is to be communicated to ZPQ to monitor the status of safety and production critical systems.


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Main equipments such as test separator, manifold, wellhead control panel and PLC/ SCADA system will be located on the lower deck.

iii)

The frequency of regular visits to the remote wellhead platforms for operator visit is once in every two weeks for replenishment of consumables by supply vessel.

iv)

All systems will be remotely controlled and monitored from ZPQ complex via WiMax.

v)

Maintenance and other activities will be by campaign, not routine platform visits.

vi)

All wells can be tested remotely via ZPQ control room, which can route the well fluid to test separator, prior to combining flows into the export pipelines.

vii)

Crane, wellhead control, power, and lay-down deck space requirements for Well Service operation.

viii)

Helideck design shall be in accordance with CAP 437 requirements and suitable for Sikorsky S76C+ and Agusta Westland (AW-139) aircraft.

ix)

Navigation light.

x)

Appropriate Safety equipment as denoted by Safety Concept document (i.e. fire extinguishers, first aid kit, emergency escape device, and so on).

xi)

A ‘burn-down’ philosophy will be used, whereby no automated fire suppression system will be installed on the platform. Service water shall be provided for platform cleaning purpose only.


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MAJOR DESIGN FEATURES OF THE WELLHEAD PLAFORMS The concept of the Zawtika wellhead platform design is a minimal facility installation aimed to minimize the platform cost while ensuring maximum benefit can be obtained from the exploration/ production of reservoirs. WP1 is bridge linked to ZPQ, while WP2 and WP3 are identical remote wellhead platforms. Requirements for all three wellhead platforms are identical unless the stipulation is notified.

4.1.

Common Design Features of Wellhead Platforms WP1, WP2 and WP3

4.1.1.

Wellheads Description of Wellhead Systems The function of the wellhead is to maintain surface control of the well. The tubing string will be fitted with Down Hole Safety Valve (DHSV), Lower Master valve, Master valve (MV), Wing Valve (WV) and the choke valve. All actuated wellhead valves, including Choke Valves, will be hydraulically operated. The hydraulic oil required to operate these valves is supplied from the Hydraulic Power Unit (HPU) located in the WHCP. Each well shall be provided with pressure transmitter at upstream of wing valve and temperature (skin temperature type) transmitter at upstream of the choke valve for remote monitoring of the flowing pressure and temperature. For annulus casing pressure measurement, a common casing pressure transmitter (PT-01001 for WP1, PT-02001 for WP2 and PT-03001 for WP3) and dedicated pressure gauge (PG-01A05 for WP1, PG-02A05 for WP2 and PG-03A05 for WP3) for 7” annulus shall be provided. An additional common pressure gauge (PG-01A08 for WP1, PG-02A08 for WP2 and PG-03A08 for WP3) shall be provided for 9 5/8”, 13 3/8” casing. The pressure transmitter (PT-01001 for WP1, PT-02001 for WP2 and PT-03001 for WP3), located on the common tubing from all wellheads, will indicate the highest casing pressure of the wells connected to a common manifold and if an abnormally high pressure is detected then an alarm will be initiated in the WHP PLC and simultaneously in the ZPQ central control room (CCR). An operator will visit the platform to check which well(s) have high pressure and depressurize the casing to the closed drain sump vessel. The casing design pressure is greater than the well shut-in pressure and therefore there is a very low risk of loss of containment from the well casing, however it is desirable to maintain the casing pressure low to avoid loss of casing fluids (corrosion inhibited water) in case of the communication between the casing and the tubing. Loss of casing fluid may accelerate internal corrosion in the casing.


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No permanent methanol injection has been envisaged on the platform (Space and weight allocation only). The hydrate formation temperature downstream of the choke valve is sufficiently low due to the low operating pressure hence, there are less chances of hydrate formation due to Joule-Thomson cooling across the choke. An injection point has been provided upstream of the Wing valve which may be required during start up after a prolonged shut down to prevent hydrate formation. Based on current PTTEPI WHFT and WHFP some wells are predicted to cool sufficiently after the choke to form hydrates during normal operating conditions. This is due to the high WHFP at the start of field life, with wells at low flow rates which lowers the WHFT. PTTEPI will manage the wells to avoid this hydrate formation during normal operation. For both high temperature & Low temperature condition, maximum flow rate of 25 MMSCFD shall be considered for all possible cases. The table below shows the maximum and minimum predicted WHFPs and WHFTs with the corresponding WHFT and WHFP data furnished by PTTEPI, together with the pressures downstream of the choke. These conditions will be used to determine the operating temperatures downstream of the choke, via a process simulation isenthalpic flash to model Joule-Thomson cooling across the choke. These temperatures are to be used for equipment capacity calculations, hydrate inhibition requirements and the Heat & Material balances. A Design temperature of 115°C shall be used for mechanical design, due to uncertainty in the predicted wellhead conditions. A WHFT of 75°C will be assumed for remote wellhead platforms (WP2 & WP3), for sizing the wellhead cooler (Finned Tube Natural Draft Cooler).

Table 4.1: Zawtika Phase 1A Development (Offshore Facilities) Upstream of Choke

Downstream of Choke

Maximum Temp. [°C] (3) @ D/s of Choke

WP1

Description

WGR = 0 Minimum Wellhead Flowing Temperature Maximum Wellhead Flowing Temperature WGR = 45 Minimum Wellhead Flowing Temperature Maximum Wellhead Flowing Temperature

WHFT [°C]

WHFP [Barg]

Maximum (barg)(1)

Minimum (barg)(2)

Case 1

Case 4

38.0

169.0

25.5

22

-6.2

-13.7

66.0

128.7

25.5

22

37.7

33.6

48.9

154.0

25.5

22

32.7

29.5

73.0

99.0

25.5

22

62.3

60.9


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Downstream of Choke

Maximum Temp. [°C] (3) @ D/s of Choke

WP 2 & 3

Description

WGR = 0 Minimum Wellhead Flowing Temperature Maximum Wellhead Flowing Temperature WGR = 45 Minimum Wellhead Flowing Temperature Maximum Wellhead Flowing Temperature

WHFT [°C]

WHFP [Barg]

Maximum (barg)(1)

Minimum (barg)(2)

Case 1

Case 4

38

185.2

41

30

-1.9

-8.54

66

136.9

41

30

41.9

38.2

46.1

163.7

41

30

31.5

28.7

72.7

103.8

41

30

64.6

63.4

Notes: 1. 1.0 bar pressure drop is considered for flow line loss (e.g. line loss, fitting loss, and block valve loss etc.) for Test Separator simulation. 2. Black start-up at 0 barg downstream of choke shall be checked for minimum metal design temperature. 3. Maximum temperature at the downstream of choke corresponds to maximum pressure (25.5 barg for WP1 & 41 barg for WP2&3) at choke downstream (for both case 1 and case 4 compositions). Each wellhead is provided with three in-line actuated safety valves; Wing valve (WV), Master Valve (MV) and Downhole Safety Valves (DHSV). Downhole Safety Valve (DHSV) can only be opened locally from the WHCP and closed either from WHCP or ZPQ-CCR. Master valve & Wing valve can be opened or closed from respective wellhead platform HMI or remotely from ZPQ (Note-1). The table below show the details of Christmas tree rating and matrix of the key Christmas tree valves and identifies from where they can be opened or closed. Table 4.2: Wellhead Design Summary for WP1, WP2 & WP3 Parameter Wellhead Rating: Maximum WHSIP

WHP Functional Requirement API 5000#

(2)

225 barg (3263.35 psig)

Maximum WHSIT

100 oC for WP2 & WP3 and 75 oC for WP1

Maximum Number of Wells

20

Maximum Number of Slots

20

Maximum Gas Flowrate per Well

25 MMSCFD

Maximum Condensate Flowrate per Well

20 STBPD


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Maximum Water Flowrate per Well

2000 BPD (Actual)

Tubing size

3.5” OD and 2.99” ID, 1500 m Length

Valves

Open

Close

Comment

DHSV

WHCP

WHCP, HMI (WHP), ZPQ

ESD 1

Master Valve

HMI (WHP), (1) ZPQ

HMI (WHP), ZPQ

ESD 2

Wing Valve

HMI (WHP) , (1) ZPQ

HMI (WHP), ZPQ

Operational, ESD 2

Production Choke

HMI (WHP) , ZPQ

HMI (WHP) , ZPQ

Fully Close

Notes: 1. Master valve can be opened remotely from ZPQ, if ESD 2 is originated from ZPQ. 2. The choke valve will be designed for design Pressure of 225barg with additional 10% margin. 4.1.2.

Flow lines, Test and Production Manifolds Description of Flow line and Manifolds The flow lines will be fabricated for sour service. The piping shall be SITP rated (ASME class 2500#). Each flow line shall be connected to the production, test manifold and booster compressor manifold (future) with actuated manifold valve to allow remote testing and operation of the platform. The production and the test manifold will be derated and hence a safety valve of adequate capacity will be provided on the export line to protect the production manifold as well as export/sea line. As per PTTEPI previous project experience, the PSV on production manifold will be sized for full flow relief for WP1; for remote wellhead platform (WP2 & WP3) PSV will be sized for two wells failing to close upon high pressure. In order to protect the test manifold as well as test separator, a safety valve of adequate capacity will be provided on the test separator. The test and production manifolds are designed for a pressure of 70 barg. A temporary connection for well clean up and well servicing (temporary burner boom) shall be provided on Test Manifold and outlet gas line of the Test Separator. Tie-in point for future LP (Booster Compressor) manifold shall be provided on each flowline. The connection of tie-in point shall be swivel flange compatible to actuated compact ball valves completed with blind flange. The choke valve actuators are double acting and will remain in the last position during a shutdown. The choke valves shall be linear, hydraulically operated and without hand wheel. Moreover, in case choke valve is malfunctioning, a guide shall be provided to install hand wheel on the choke valve. However, the choke valves shall be driven to


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the closed position after the respective well wing valves are closed. This shall be included in the PLC logic. Once the well safety valves are opened, then the operator shall open the choke valve slowly from the panel located in the CCR to allow the well to flow. Slow opening of the well choke is desired to avoid sudden flow changes, which may cause pipeline liquids to be discharged to the ZPQ in large quantities. The choke valve shall be located close to manifold. This is to optimize the space utilization in the well bay area and provide better access. Pressure transmitter (PT-01A07 for WP1, PT-02A07 for WP2 and PT-03A07 for WP3) shall be provided upstream of each wing valve and Temperature transmitters (TT01A10 for WP1, TT-02A10 for WP2 and TT-03A10 for WP3) shall be provided upstream of each choke valve for remote monitoring of the flowing pressure and temperature and also the shut-in tubing pressure (WHSIP). In addition, each well shall be monitored remotely for the flowing pressure downstream of choke valve via a pressure transmitter (PT-01A09 for WP1, PT-02A09 for WP2 and PT-03A09 for WP3). Based on the PTTEPI earlier experience, the target tees should be installed on all flow lines at first elbow downstream of wing and choke valve to avoid erosion. Intrusive type sand monitoring shall be provided for sand monitoring on each well. Remote temperature indication will also be provided by a skin temperature indicating element. 3D pipe bends and 5D pipe bends shall be used for topside and subsea bends respectively. The table below shows the main design features of flow lines and test/ production manifolds. Table 4.3: Design Parameters for Flow lines and Test/Production Manifolds Description

WP1

WP2 & WP3

inch

6

4

MMSCFD

25

25

STBPD BPD Actual barg

20

20

2,000

2,000

225

225

115/-46

115/-46

Duplex SS / K4N

Duplex SS / K4N

Flow lines Diameter Gas Flowrate Condensate Flowrate Water Flowrate Design Pressure Design Temperature

o

C

Material / Pipe Spec. Production Manifold Size

inch

10

16

Operating Pressure

barg

22-25.5

30-41(2)

(-)14 / 60

(-)9 / 62

Operating Temperature

o

C


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Description Design Pressure

WP1

WP2 & WP3

70

70

115/-29

115/-29

Duplex SS Required (1) One Operating One Standby

Duplex SS Required (1)One Operating One Standby

inch

6

4

barg

22-25.5

30-41

C

(-)14 / 60

(-)9 / 62

barg

70

70

115/-29

115/-29

Duplex SS

Duplex SS

barg o

Design Temperature

C

Material Pressure Safety Valve Test Manifold Size Operating Pressure

(2)

o

Operating Temperature Design Pressure

o

Design Temperature

C

Material Notes:

1. For WP1, Pressure safety valve shall be sized for platform full flow relief while for WP2 & WP3, PSV shall be sized for two wells failing to close on high pressure. 2. During pigging operation, the maximum operating pressure will be around 52 barg. Design Criteria for Flow lines and Manifolds Design Margin 10% Design margin will be considered on maximum flow rates for all topside main line sizing. But no margin will be considered for sizing of flow line. Velocity Criteria Following velocity criteria will be applied for line sizing. a. Single Phase Flow Velocity: General vapour lines & Liquid line and gravity line will be sized based on PTTEPI General Specification “Process Sizing Criteria” (ZGS-PRO-101). b. Multiphase Flow Velocity As per API recommended practice 14E for multiphase line sizing will be based on erosion velocity criteria. The erosion velocity is determined by the following empirical equation: Ve Where: Ve

=

=

C √ρm

erosional velocity in ft/s (m/s in SI units)


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PTTEP International Limited ρm

=

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gas / liquid mixture density at flowing conditions in lb/ft3 (kg/m3 in SI units)

C

=

Empirical constant. Value equal to 150 to 170 (183 to 207.43 in SI units). C value up to 200 (244 in SI units) for corrosion resistant alloy steels can be considered on peak flow rate only in case of absence of abrasive (solid) particles such as sand. Proper sand mitigation programme should be developed by PTTEPI to minimise erosion on topside piping.

A philosophy of regular inspection and replacement of flow lines for corrosion/ erosion is assumed to unexpected sand loading. As sand is expected in the wellhead fluid API RP 14E recommended C values should be used cautiously; hence a different approach using SALAMA 2000 erosional velocity is agreed to be used: ER

=

1 Sm

*

W.Vm2 ρm

*

d D2

With: ER

=

Erosion rate, in mm/year

W

=

Sand flow rate, in kg/day

Vm

=

Fluid mixture velocity, in m/s

D

=

Sand size, in micron (the effect becomes negligible above 400 microns. Therefore, for d>400, the limit of 400 is used). However, as per sand distribution data, 90 micron will be considered for Zawtika Wellhead)

D

=

Internal pipe diameter, mm

ρm

=

Fluid mixture density, in kg/m3

Sm

=

Geometry factor (equals to 5.5 for pipe bends)

If sand is present in process fluid, the erosion rate of the piping will be limited to 0.1 mm/yr as per requirement of PTTEPI. 4.1.3.

Test Separator Description for Test Separator The main function of the Test Separator is to enable testing of each individual well to determine production parameters such as gas and liquid flow, pressure, temperature and fluid composition. The Test Separator will be a 2-phase horizontal separator. Water cut meter shall be installed in series with Coriolis flow meter. This will enable


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the operator to determine the water and condensate rates in the combined liquid stream. Sampling point for water-condensate composition will be provided at Test Separator liquid line and sampling would be required to establish which WHP or well is producing significant condensate. The Test Separator shall be designed for remote operation from ZPQ Central Control Room (CCR) SCADA. In well test mode, the Test Separator receives well fluids from the test manifold and separates the inlet mixture into a gas stream and liquid stream. The gas phase and the liquid phases are individually measured and recorded before the streams are recombined and discharged to the export pipeline. However, a 2” pressurization/pressure equalization line from the production manifold to test manifold is provided for pressure equalizing the test manifold as well as test separator during initial start-up of well testing, this will act as permissive to open the respective flow arm actuated valve to test manifold. In addition, after completion of well testing test separator shall be depressurized to 3 barg to minimize the hydrocarbon inventory. A provision has been kept for a future booster compressor and accordingly the wells that are diverted to the compressor can also be tested. In the booster compressor mode the test separator will operate in the same way as in the well test mode. However, the gas and liquids will be discharged to the booster compressor suction instead of production header. Another possible use for the test separator is to clean-up wells/blowdown during well services operations. However, preference will be given to open up the wells directly to the pipeline. If the wells will be cleaned up through the Test Separator, the gas is routed to temporary flare burner and liquid separated in the test separator is routed to temporary liquid burner. This procedure allows a well to be cleaned-up without the need to install the well clean-up separator, diesel tank and pumps. After the well has been cleaned up, the well fluid is diverted to the production header. If large quantities of solids are expected to be produced by the well and it is not possible to open up the well directly to the pipeline, the well services well clean-up separator and temporary burner boom should be used to clean-up the well to avoid solids depositing inside the test separator. Well clean-up separator, temporary flare & liquid burner and temporary burner boom will be supplied by well clean-up services. During late-life of field, well can produce significant quantities of water which may accumulate in the production tubing and create back pressure on the well which may eventually cause cessation of the well production. Well unloading is the operation of removing this column of the water from the production tubing and restoring normal gas Zawtika Development Project , Phase 1A EPCIC of Zawtika Wellhead Platforms 1, 2 and 3 with Sea Lines \\Netstore-blr\10038\C10038\PROC\Final\DOCUMENTS\Design Basis\Rev C1\MM-ZTK-1A-WP-PRO-BOD-0100.doc

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production from the well. Well unloading operation shall be carried out using the containment volume of the test separator and the closed drain sump vessel. When well unloading process will be carried out, initially the test separator will be de-pressurized to 10 barg pressure and then receive the well fluids. After achieving a level of LAHH in Test separator it shall be further de-pressurised to 2-3 barg pressure and then hydrocarbon liquid shall be transferred to closed drain sump vessel. The closed drain sump pump may also be started at the same time to transfer the liquids to ZPQ Closed Drain Sump for WP1 or the export header for WP2 & WP3. Permissive interlock to allow draining liquid from Test Separator to WHP Closed Drain Sump shall be provided. Restriction orifice to limit gas blow by to closed drain sump shall also be provided. Adequate measures shall be considered to avoid water seal blow-off provided on the hazardous open drain systems. The main design parameters for the Test Separator are tabulated below in Table 4.4. Table 4.4: Design Parameters for Test Separator Description

WP1

WP2 & WP3

2 Phase

2 Phase

Horizontal 1.45 m ID x 2.5 m T/T 25

Horizontal 1.45 m ID x 2.5 m T/T 25

20

20

2,000

2,000

70

70

C

115/-29

115/-29

barg

22-24.5

30-40

(-)14 / 60 CS with SS316L cladding Required

(-)9 / 62 CS with SS316L cladding Required

Phase Orientation Size Gas Flowrate Condensate Flowrate Water Flowrate Design Pressure Design Temperature Operating Pressure Operating Temperature

m MMSCFD STBPD BPD Actual barg o

o

C

Material Pressure Safety Valve (1) Notes:

1. Pressure safety valve shall be sized for one well design flow rate. Design Criteria for Test Separator The test separator is a two-phase horizontal vessel and is sized for the following target performance specifications. The minimal internals are provided to meet the specification of gas from test separator.


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PTTEP International Limited •

Page 29/50

The liquid content of the gas outlet stream shall not exceed 0.1 US gallons/ MMSCF

•

Liquid droplet removal shall equal or exceed 90% of droplets greater than 5 microns and 95% of droplets greater than 10 microns;

•

10% design margin will be considered for test separator sizing, the margin considered includes both surge & swell factor. No separate margin for surge & swell will be considered.

•

The Test Separator shall be designed for a maximum flow of one well; with residence time of 3 minutes between LAL & LAH or minimum distance of 300mm between LAL & LAH, whichever is greater as per ZGS-PRO-101.

•

The ρmvm2 for test separator inlet, gas outlet and the Liquid velocity will be as given below, The minimum inside diameter of the feed inlet nozzle should be equal to the inside diameter of the inlet pipe and if required sufficiently large to satisfy the following momentum criteria, 1) If no inlet device is used ρmvm2 ≤ 1,400 Pa 2) If half pipe is used as inlet device ρmvm2 < 2,100 Pa 3) If a Schoepentoeter is used as inlet device ρmvm2 < 8,000 Pa Where: ρm is the mean density of the mixture in the feed pipe Vm is the velocity of the mixture in the feed pipe. •

For the separator gas outlet nozzle, the minimum inside diameter should be equal to the inside diameter of the outlet pipe and also sufficiently large to satisfy the momentum criteria of ρgvg2 ≤ 4,500 Pa Where: ρg is the gas density vg is the velocity of the gas

•

The liquid outlet nozzle should be sized for maximum liquid velocity less or equal to 1 m/s, with a minimum diameter of 2 inch.

•

The calculated critical sand rate of 1.31 kg/day for the WP 2 & 3 and 3.790 kg/day for the WP1 is based on the mixed density as well as fluid mixture velocity. This is a maximum value of allowable sand loading (in API 5000# wells) considered for design of flow lines based on required erosion rate of 0.1mm/yr). However suitable measures for sand management shall be implemented by PTTEPI to limit the sand in the flow line to 50% of above critical sand rate mentioned.


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4.1.4. Temporary Flare and Liquid Burner Connection Description Connections to temporary (removable type) burner boom to well service gas burner and liquid burner for well clean up will be provided at all three wellhead platforms (WP1, WP2 & WP3). Tie-in points from test manifold and from test separator at West sides of the platform shall be provided for the temporary burner on all of the WPs. Tie-in points at test manifold will be connected to well service separator before being routed to the boom. Design Criteria The length of temporary burner boom shall be decided based on permissible radiation limits (Radiation Criteria: 4.73 kW/m2 (1500 BTU/h/ft2) at corner of the well bay). 4.1.5.

Booster Compressor (Future) A Booster Compressor is expected to be installed in the future for all wellhead platforms to boost production when the well pressure has dropped. The dedicated space for Booster Compressor, manifold, flow lines and associated instruments and piping shall be provided. The design parameters of future booster compressor will be confirmed in the future development phase by PTTEPI.

4.1.6.

Drain System

4.1.6.1. Hazardous Open Drain System Being a gas platform, only small amount of liquid drains are expected during the maintenance of the equipments which shall be routed to the closed drain sump vessel through the drip pan. For WPx the open hydrocarbon drain header to the closed drain sump vessel shall be provided with a NRV, isolation valve and liquid seal. A water seal shall also be provided at drip pans to prevent back flow during normal operation. For WP1 the hazardous open drain header to closed drain sump vessel shall be provided with two dissimilar check valves, isolation valve and liquid seal to prevent water seal blow-off during the gas blow-by from the test separator liquid outlet SDV-01120 to the closed drain sump vessel. 4.1.6.2. Non-Hazardous Open Drain System Deck drains are classified as non-hazardous which will be directed to overboard.


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4.1.6.3. Closed Drain System Description Hazardous open drain header and closed drain header are segregated but both will be routed to a Closed Drain Sump Vessel. The maintenance drains into the closed drain system will be routed only after depressurization of the connected equipment/ line. No hard piped drains will be provided from the flow lines, production manifold, test manifold & booster compressor manifold. These lines will be depressurized to vent and then drained from low point to a bucket to dispose off any liquids in the lines. There will be a single 150# ANSI network. Design Criteria The minimum gradient of the horizontal piping for gravity type drains for offshore application will be 1:100. 4.1.7.

Closed Drain Sump Vessel

4.1.7.1. Description for WP1 The closed drain sump vessel is required to collect liquids drains from equipments and lines for maintenance purposes and also for collected liquids during well blowdown / unloading operation. Closed drain vessel normally receives depressurized discharges from test separator. For bridge linked WP1 the closed drain sump vent will be connected to LP flare header at ZPQ. 4.1.7.2. Description for WP2 & WP3 The closed drain sump vessel is required to collect liquids drains from equipments and lines for maintenance purposes and also for collected liquids during well blowdown / unloading operation. Drains from test separator, HP vent header stand-pipe, Pig Launchers and Receivers will be routed to Closed Drain Sump Vessel. In addition, it will also receive continuous discharges from the filter/coalescer, Pipe separator, Utility gas KOD (Instrument Gas System). For remote platforms the closed drain sump vent will be connected to the LP vent header. 4.1.7.3. Design Criteria for WP1, WP2 & WP3 The closed drain vessel will be sized based on the governing volume between total liquid hold up in the production tubing of one well or total volume in the test separator from BOV to LALL. The following production tubing will be assumed to be full of liquid: Length: 1500 m, Tubing Diameter: 3.5" NB, inner diameter 2.99" Zawtika Development Project , Phase 1A EPCIC of Zawtika Wellhead Platforms 1, 2 and 3 with Sea Lines \\Netstore-blr\10038\C10038\PROC\Final\DOCUMENTS\Design Basis\Rev C1\MM-ZTK-1A-WP-PRO-BOD-0100.doc

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For sizing the WP1 vessel, credit will also be taken for additional storage volume in the main ZPQ Closed drains vessel. The liquid hold up volume will be considered between LALL to LAH for closed drain vessel sizing. Closed Drain Vessel for WP2 and WP3 are designed (8.5 barg design pressure) to withstand back fire pressure, since the vent boom is not provided with the flash back protection. Table: 4.5 Design & Operating Conditions of Closed Drain Sump Vessel Description Design Pressure

WP2 & WP3

3.5 / FV

8.5 / FV

C

115 / (-)29

115 / (-)29

barg

0.1+ Full of Water

0.25 + Full of Water

(-)15 / 60

(-)11 / 63

barg o

Design Temperature Operating Pressure

o

Operating Temperature 4.1.8.

WP1

C

Closed Drain Sump Pump

4.1.8.1. Description for WP1 The closed drain sump pump shall be diaphragm type pump and will be utility air driven. The liquid from the closed drain sump vessel shall be routed to the main ZPQ closed drain drum via the bridge link, under automatic level control. The pump start / stop command can be initiated remotely from ZPQ CCR as well as WP1 HMI. 4.1.8.2. Description for WP2 & WP3 The closed drain sump pump shall be positive displacement Plunger pump. The sump pump discharge shall be routed to the export pipelines upstream of the pig launcher under automatic level control. The closed drain sump tank pump will be driven by utility gas. The pump start / stop command can be initiated from ZPQ & HMI. 4.1.8.3. Design Criteria for WP1, WP2 & WP3 A 10 % design margin or as per project particular requirement will be applied in setting the design flow rate (defined as duty or Best Efficiency Point). No margin shall be added to the differential head. The NPSHa calculation for closed drain sump pump will be based on mixed fluid vapour pressure. Table: 4.6 Design & Operating Conditions of Closed Drain Sump Pump Description WP1 WP2 & WP3 Design Pressure Design Temperature Discharge Pressure Operating Temperature

barg

10

70

C

115 / (-)29

115 / (-)29

barg

2.6

41 - 53

22 / 60

22 / 63

o

o

C


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4.2.

Design Features Specific to Bridge Linked Wellhead Platform, WP1

4.2.1

Chemical Injection System Chemical Injection System for WP1 only consists of injection points for Methanol and Anti-foam/Demulsifier. The corrosion inhibitor system is not envisaged for the WP1 topside because of corrosion resistant alloy. The well fluid line from downstream of wing valve to the tie in at production manifold (ZPQ) is of Duplex stainless Steel (DSS).

4.2.1.1

Antifoam / Demulsifier Injection Only injection point will be provided at the inlet of the test separator. No permanent facilities are envisaged under the present scope of work.

4.2.1.2

Methanol Injection The injection point will be provided on Christmas tree flange upstream of wing valve in order to facilitate injection during first start-up or after prolonged shutdown to minimize hydrate formation. No permanent facilities are envisaged under the present scope of work. Space allocated for future booster compressor package shall be utilized for methanol injection package.

4.2.2

Relief & LP / HP Flare Header

4.2.2.1

Description There shall be two flare headers HP flare header and LP flare header. HP flare header is provided to accommodate high pressure relief mainly from relief valves, manual / automatic depressurization, Test Separator, Production Manifold and future booster compressor relief which will be routed to the main ZPQ HP flare header via the bridge link. The LP flare header collects the low pressure vent from closed drain sump vessel which will be routed to the main ZPQ LP flare header via the bridge link. The required purge gas for the HP / LP flare header shall be supplied from ZPQ during start-up and normal operations to prevent oxygen ingress in to the flare header.

4.2.2.2

Design Criteria for Pressure Safety Valves The Pressure safety valve selection will be based on maximum allowable back pressure exerted on PSV. If Maximum allowable back pressure is < 10% conventional type PSV will be used.


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If Maximum allowable back pressure is in the range of 10% to 50%, balance type PSV will be used.

•

If Maximum allowable back pressure is > than 50% Pilot operated, PSV will be used.

•

No margin on the calculated relief flow will be applied. Relief valves will be designed in accordance with API RP520/521.

Maximum allowable Over Pressure, •

For relief case other than fire

10 %;

•

For fire case relief

21 %.

When multiple relief valves are required to achieve the required relief area, the allowable over pressure for relief valves (other than fire case) will be 16% with the set pressure for the additional valves set at 5% above the first valve set pressure. For the line sizing, the maximum capacity of the PSV (recalculated with the selected orifice) will be considered even if this figure exceeds the actual maximum flow rate due to process limitations. PSV on continuous service will be provided with two PSV (one online and one standby) and PSV on intermittent service will be provided with one PSV. •

Pressure drop between the protected equipment and the PSV to be kept less than 3% of PSV set pressure (API RP 520 Part II);

•

Upstream PSV line size > Diameter of PSV inlet;

•

ρV2 ≤ 25,000 kg/m/s2 for line ≤ 2”;

•

ρV2 ≤ 30,000 kg/m/s2 for Pressure ≤ 50 bar g;

•

ρV2 ≤ 50,000 kg/m/s2 for Pressure > 50 bar g.

4.2.2.3 Design Criteria for Depressurization Device (BDV's + RO) •

Minimum line size 2”

•

ρv2 criteria are the same as for PSV's.

Lines downstream of relieving devices, flare and cold vent headers and sub-headers •

Minimum line size 2”;

•

Back pressure is compatible with the installed relieving device;

•

ρv2 < 100,000 kg/m/s2

As noted above the design of relief and depressurization system will be in accordance with API 520 part I, II and also API 521. Zawtika Development Project , Phase 1A EPCIC of Zawtika Wellhead Platforms 1, 2 and 3 with Sea Lines \\Netstore-blr\10038\C10038\PROC\Final\DOCUMENTS\Design Basis\Rev C1\MM-ZTK-1A-WP-PRO-BOD-0100.doc

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Relief valve outlet line size

Page 35/50 : Maximum allowable velocity 0.8 Mach;

& sub headers •

Main Headers

: Maximum allowable velocity 0.5 Mach

The HP flare system for WP1 is designed to cater for emergency relief and the capacity is based on the full production flow: Gas 100 MMSCFD, Condensate 60 STBPD and Water 4500 Actual BPD. The LP flare system shall be designed to provide low pressure to minimize the back pressure on the closed drain sump vessel and other low pressure sources. 4.2.3

Condensate Handling & Disposal (Permanent Liquid Burner)

4.2.3.1

Description The permanent liquid burner shall be installed on WP1 to burn the condensate disposal from ZPQ. The boom length is designed based on thermal radiation criteria of 2 kW/m2. The permanent liquid burner will be designed to flare a continuous load of 130 STBPD. The composition of the condensate is given in Table 3.2. Condensate will be pumped from ZPQ by dedicated high pressure pump to achieve a pressure of 20.7 barg (300 psig) at burner nozzle to ensure effective atomisation of the liquid droplets without the requirement of atomising air / gas to breakdown the condensate. Smokeless operation will be achieved through effective atomization of the condensate during normal operation and turndown. Liquid burner shall be provided with the swivelling type arrangement and will consist of a pilot that uses fuel gas for initial ignition. The pilot gas required for the burner shall be fed from the ZPQ fuel gas system. Two pilots shall be provided which will be used in case of failure of one pilot sensor. During start-up and in case of unavailability of fuel gas supply from the ZPQ, propane gas will be used as a backup pilot gas. Flame front type ignition system is provided to light the pilots.

4.2.3.2

Design Criteria The length of the boom shall be based on the radiation criteria such that the edge of Upper deck should not exceed 2 kW/m2 during continuous load.


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Diesel Fuel System WP1 does not require diesel tote tank, only diesel day-tank is provided. Diesel supply & distribution system shall be provided from ZPQ.

4.2.5

Other Features Specific to WP1 The following utilities shall be provided from ZPQ to WP1 via. the bridge-link: •

Diesel

•

Instrument Air

•

Utility Air

•

Inert gas (Nitrogen)

•

Wash water

•

Provision of space & weight for future produced water injection line

•

Firewater network

•

Condensate (from condensate transfer pump, ZPQ) for permanent liquid burner

•

Fuel gas for permanent liquid burner to ignite the pilot

The following hydrocarbon lines shall be routed to ZPQ via the bridge-link: •

LP flare gas to LP flare header at ZPQ;

•

HP flare gas to HP flare header at ZPQ;

•

Closed drains hydrocarbon liquid to ZPQ.

4.3

Design Features Specific to Remote Wellhead Platforms, WP2 & WP3

4.3.1

Chemical Injection System

4.3.1.1. Antifoam / Demulsifier Injection Only injection point shall be provided at the inlet of the test separator. No permanent facilities are envisaged under the present scope of work. 4.3.1.2. Methanol Injection The injection point shall be provided on Christmas tree flange upstream of wing valve in order to facilitate injection during first start-up or after prolonged shutdown to minimize hydrate formation. No permanent facilities are envisaged under the present scope of work. Only space will be provided.


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4.3.1.3. Corrosion Inhibitor System The corrosion inhibitor shall be injected into the production manifold to reduce the corrosion rate of the carbon steel pipeline. The corrosion inhibitor injection system shall consist of portable tote tanks, 2 x 100% utility gas driven injection pumps and all necessary piping and instrumentation. The rated capacity of each pump shall be 6 L/hr. The tote tank capacity will be 2 x 2.2 m3; and shall be equipped with level monitoring and alarm function. The pumps should have provision for remote start/ stop. The local capacity adjustment will be achieved by operator during bi-weekly platform visit. Remote flow indication is provided with low low flow set point to stop the pump in operation and start the stand-by pump. The 2 x 100% corrosion inhibitor injection pumps shall be provided on wellhead platform (WP2 & WP3) and capacity of corrosion inhibitor injection pumps shall be 6 L/hr. Space shall be provided for additional pump for future booster compressor. 4.3.1.3.1 Design criteria: Corrosion Inhibitor Tote Tank The tote tank will be sized for minimum of 30 days of continuous rated consumption of 6LPH. Table: 4.7 Design & Operating Conditions of Corrosion Inhibitor Tote Tank Description Design Pressure Design Temperature Operating Pressure Operating Temperature

WP2 & WP3 barg

Atm + Full of Liquid

o

C

70

barg

Atmospheric

o

C

Ambient

4.3.1.3.2 Design Criteria: Corrosion Inhibitor Dosing Pump A 10 % design margin or as per project particular requirement will be applied in setting the design flow rate (defined as duty or Best Efficiency Point). No margin will be added to the differential head. Table: 4.8 Design & Operating Conditions of Corrosion Inhibitor Dosing Pump Description Design Pressure Design Temperature Discharge Pressure Operating Temperature

WP2 & WP3 barg

70

o

C

115 / (-)29

barg

45 - 58

o

C


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Vent Boom for Cold Venting

4.3.2.1

Description

Page 38/50

The remote wellhead platforms WP2 & WP3 shall be provided with both LP and HP vents for cold venting. The vents shall be fitted with stainless tip (pipe tip) to prolong the life of the tip in case of accidental ignition due to lightening. The vent boom length and height shall be designed based on permissible radiation limits for accidental ignition of vented fluid. HP vent header is provided to accommodate high pressure relief mainly from relief valves, manual depressurization from production Manifold, test separator and future booster compressor relief. HP vent header is routed to the standpipe, which is provided to accommodate the liquid and route the collected liquid to the closed drain sump vessel. A restriction orifice is provided on the liquid line to minimize gas blow-by. The LP vent header collects the low pressure vents from various equipments, closed drain sump vessel, exhaust from Closed Drain Sump Pump/Corrosion Inhibitor Pumps/Diesel Transfer Pump and instrument vents from valves. 4.3.2.2

Design Criteria As noted above the design of relief and depressurization system will be in accordance with API 520 part I, II and also API 521. •

Relief valve outlet line size

: Maximum allowable velocity 0.8 Mach;

•

Headers

: Maximum allowable velocity 0.5 Mach

The HP vent system for remote platforms WP2 & WP3 shall be designed to cater for emergency relief and the capacity is based on the two wells flow: Gas 50 MMSCFD, Condensate 40 STBPD and Water 4000 Actual BPD. The LP vent system shall be designed to provide low pressure to minimize the back pressure on the closed drain sump vessel and other low pressure sources. Rest of the criteria as mentioned in section (4.2.2) for WP1 will be followed for WP2 & WP3. 4.3.3

Pig Launcher A horizontal pig launcher shall be installed at the top of the riser to facilitate pigging operations using intelligent pigs. The pigging assembly is designed to launch pigs into the pipeline for cleaning, corrosion control purposes and measurement of pipeline internal wall thickness.


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The Pig Launcher is located on the lower deck. The Launcher closure, vent valve and pressure indicator can be accessed from the lower deck. A kicker line will be provided to supply gas from the production header to the Launcher during pigging operations. The two valves (ball valve and globe valve) located on the bypass line to the kicker line and kicker valve allow pressurization of the Launcher. The pig launcher will be provided with mechanical interlock system to open the valves including manual valves on the inlet/outlet/kicker/equalising/balancing lines in a sequence. The interlock also ensures that the quick opening closure can not be carried out when pig barrel is under pressure. Table: 4.9 Design & Operating Conditions of Pig Launcher Description Design Pressure Design Temperature Operating Pressure Operating Temperature

4.3.4

WP2 & WP3 barg

70

o

C

115 / (-)29

barg

24 - 52

o

C

(-9) / 63

Pig Receiver (Future) Provision of space for two future pig receivers shall be provided on WP2 and WP3 to cater for future Zawtika Phase 1B and 1C facilities. The receiver equalization valve, vent valve and pressure indicator can be accessed from the lower deck and the pig receiver access platform. The inlet valve, bypass valve and globe valve located on the inlet of the receiver to allow pressurization. The receiver closure is equipped with pressure safety interlock system to prevent opening under pressure. The gas in the receiver barrel can be vented to the HP vent system and to the atmosphere at safe location before opening the receiver to remove a pig. A drain line to the open and closed drain has been provided on the barrel to remove all liquids before opening the receiver. The pig receiver will be provided with mechanical interlock system to open the valves including manual valves on the inlet/outlet/equalising/balancing lines in a sequence. The interlock also ensures that the quick opening closure can not be carried out when pig barrel is under pressure. The operating and design conditions will be confirmed during the future phases.


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Instrument/Utility Gas System

4.3.5.1. Description for Instrument/Utility Gas System The purpose of the instrument gas system shall be to supply gas to operate all actuated valves (except the wellhead valves). During normal operation instrument gas shall be tapped off from the export line and run through a pipe separator (vertical stand pipe) to minimize water carryover. The gas shall be cooled (or warmed close to the ambient temperature, 22-33 ˚C) in a finned tube natural draft cooler and cool down the inlet instrument/utility gas to 10 ˚C above the design ambient air temperature (33 ˚C). The instrument gas from the Finned Tube Natural Draft Cooler shall be sent to a separator vessel (stand Pipe). The stand pipe will be designed to knock out the condensed liquid from wet instrument gas due to the cooling down of gas in finned tube natural draft cooler to avoid malfunctioning of self regulating pressure control valve (PCV-02303 A/B for WP2 & PCV-03303A/B for WP3) located downstream of stand pipe and separated liquid from stand pipe shall be sent to the closed drain sump vessel by operation of gap control valve. Gap action or on/off level control shall be designed to drain the liquid whenever liquid reaches the high level set point. The liquid shall be drained until level reaches to low level set point and the valve closes. A restriction orifice is provided in the drain line to control liquid drain rate and prevent high pressure in the closed drain vessel due to gas blow-by through the liquid level control valve from the stand pipe. The wet gas from stand pipe (assumed 50% efficiency of liquid removal) will then be fed to self regulating pressure control valve which regulates pressure to 9.0 barg before going into the utility gas knock out drum. The condensed liquid from the pressure regulating process (Joule-Thomson Process) is knocked out by the utility gas knock out drum. The separated gas from the utility gas knock out drum will then be sent to instrument gas filter/coalescer for further separation and smaller liquid droplets will be captured and removed by the instrument gas filter/coalescer element installed in top section of the vessel. The black start system will be used to start-up the platform after ESD1 and/or ESD 2 activation or during initial start-up of platform (during initial start-up nitrogen bottles will be required to operate the actuated valves and WHCP) when there are no fluids available at downstream of export line. During black start-up, the instrument gas system and fusible plug loop shall be pressurized using back-up gas from export pipeline. The back-up gas shall be taken from the export pipeline through 3” back-up gas line and ESDV-02214 for WP2 & ESDV-03214 for WP3 shall be opened using equipped nitrogen bottle. Once back-up gas starts flowing from export pipeline then Zawtika Development Project , Phase 1A EPCIC of Zawtika Wellhead Platforms 1, 2 and 3 with Sea Lines \\Netstore-blr\10038\C10038\PROC\Final\DOCUMENTS\Design Basis\Rev C1\MM-ZTK-1A-WP-PRO-BOD-0100.doc

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nitrogen shall be switched over to back-up gas. However, during initial start-up/first start-up of wellhead platform, nitrogen cylinders will be used to pressurize the system. The black start-up system will be provided with the following instrument: •

Self acting pressure regulator (PCV02335 for WP2 & PCV03335 for WP3) shall be provided to reduce pressure of the gas from export pipeline to 8.5 barg.

•

Pressure safety valve (PSV-02337 for WP2 & PSV-03337 for WP3) shall be provided to protect black start system from overpressure due to self acting pressure regulator (PCV02335 for WP2 & PCV03335 for WP3) fail open.

•

A 3-way manual valve (SDY 02338 for WP2 & SDY 03338 for WP3) shall be provided so that system can select the source of the gas either from back-up gas from export pipeline or from Instrument Gas System.

•

Another self acting pressure regulator (PCV 02336 for WP2 & PCV 03336 for WP3) shall be provided to reduce pressure of the gas from export pipeline to 3.5 barg which is used for pressurizing fusible plug loop.

The manual intervention is required to operate this system. Operator shall open 3” manual isolation ball valve (normally closed) located at the downstream of ESDV 02214 for WP2 & ESDV 03214 for WP3 and then open the ESDV 02214 for WP2 & ESDV 03214 for WP3 using equipped nitrogen bottle, then gradually open the 2” manual isolation ball valve (NC) at the inlet of black start system which will allow the gas from the export pipeline flow to black start system via 3” back-up gas line (this valve shall be opened slowly to avoid the pop-up of pressure safety valve PSV-02337 for WP2 & PSV-03337 for WP3 ). The self acting pressure regulating control valve (PCV) will regulate gas pressure to 8.5 barg for operating the shutdown valve (SDV02321 for WP2 & SDV-03321 for WP3) and then gas will pass through another self acting pressure regulating control valve (PCV), which will regulate the downstream fusible plug loop and ESD loop in WHCP at pressure of 3.5 barg. Once the gas in IG system is available the rest of the actuated valves, WHCP hydraulic valves can be started. The instrument/utility gas will be supplied to the following end users: •

As motive gas to the corrosion inhibitor pumps;

•

As motive gas to the pneumatic pumps (diesel transfer, closed drains sump vessel pump);

•

Hydraulic control unit;

•

As instrument gas to control valves/ shutdown valve, etc;

•

As fuel gas to the TEGs for power generation.


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4.3.5.2. Design Criteria The design is based on the Utility and Instrument gas vessels in series. This will reduce the risk of liquid carryover in the instrument gas system. Routing of all utility gas through the Instrument gas filter/coalescer is considered, this will also reduce the risk of liquid carryover in the pump motive gas, which can damage the pumps. 4.3.5.2.1 Utility Gas Knock Out Drum The Utility Gas Knock out Drum sizing will be based on achieving liquid content of the gas outlet stream, not exceeding 0.1 US gallon/ MMscf. The liquid droplets separation efficiency should be 99% for droplets of size 8 µm above. Table: 4.10 Design and Operating Conditions of Utility Gas Knock out Drum Description

WP2 & WP3

Design Pressure

barg

11 / FV

o


90 / (-)29

barg

8.0 - 9.0(Note 1)

o

Operating Temperature Flow rate

C C

(-5) / 48(Note 2,5)

MMSCFD

0.45

bar

0.2

Allowable Pressure Drop 4.3.5.2.2 Instrument Gas Filter/Coalescer

The instrument gas filter separator sizing will be suitable to achieve following: •

The liquid content of the gas outlet stream will not exceed 0.005 US gallons/MMscf at normal level;

•

Filter will remove 99% of particles larger than 0.3 micron;

•

The total solids in the gas outlet stream will be less than 0.1 g/m3 with 99% of solids larger than 0.3 micron.

•

Gas from Instrument Gas Filter/Coalescer should meet the instrument gas specification (Contaminated solid size is less than 0.01 micron and gas dew point is less than ambient temperature by 10°C)

•

The maximum oil/liquid carryover as specified below Inlet load

:

40 ppm (w/w)

Outlet

:

0.008 ppm (w/w)


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Table: 4.11 Design and Operating Conditions - Instrument Gas Filter/Coalescer Description

WP2 & WP3

Design Pressure

barg


C

90 / (-29)

barg

8.0 - 9.0(Note 1)

o

Operating Temperature Flow rate

11 / FV

o

C

(-5) / 48(Note 2,5)

MMSCFD

0.45

bar

0.3

Pressure Drop 4.3.5.2.3 Finned Tube Natural Draft Cooler

The finned tube natural draft cooler will be designed with 15 percent excess area. Minimum temperature approach of 10°C is recommended. Design ambient air inlet temperature will be considered at 33°C. Ambient air temperature varies in the range of 22°C to 33°C. The cooler is designed for a temperature approach of 10°C. Table: 4.12 Design and Operating Condition for Finned Tube Natural Draft Cooler Description Design Pressure Design Temperature Operating Pressure Operating Temperature

WP2 & WP3 barg

70 / FV

o

C

115 / (-29)

barg

40-52 (Note 4)

o

C

(-9) / 75

MMSCFD

0.45

Pressure drop

bar

0.2

Heat Duty

kW

12.93(Note 3)

Flow rate

Notes: 1. Minimum required instrument gas pressure is 80 psig (approximately 5.5 barg). 2. Instrument gas supply temperature shall be restricted between 65-80°C for major users (control valves, actuators), 65 °C for WHCP pump and 48.8 °C for Chemical Injection pump. 3. Instrument/Utility gas inlet temperature is considered as 75°C and will be cooled down to 43 °C by finned tube natural draft cooler. This will provide governing heat duty for finned tube natural draft cooler. Since 15% extra area is considered no margin on heat duty to be considered. 4. During pigging operation, the operating pressure will reach 52 barg 5. During pigging operation, the operating temperature at downstream of PCV-XX303 A/B will range from (-11.5) to 48°C.


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Diesel Fuel System Diesel storage tote tank capacity 2 x 2 m3 provided on the platform and the tote tank will supply diesel for the crane diesel engine day tank which is provided with the crane power unit skid for platforms WP2 and WP3. Filling of the crane diesel tank will be carried out using a permanent Instrument gas driven diesel transfer pump. The 1 x 100% diesel transfer pump will be provided on wellhead platform (WP 2 & WP 3) and capacity of diesel transfer pump will be 1.09 m3/hr. Table: 4.13 Design & Operating Conditions for Diesel Tote Tank Description Design Pressure Design Temperature Operating Pressure Operating Temperature

C

WP2 & WP3 Atm+Full of water column 70

barg

Atmospheric

barg o

o

C

Ambient

Table: 4.14 Design & Operating Conditions for Diesel Transfer Pump Description Design Pressure Design Temperature Discharge Pressure Operating Temperature

WP2 & WP3 barg

10

o

C

70

barg

2.5

o

C

Ambient

Table: 4.15 Design & Operating Conditions for Diesel Filter Description Design Pressure Design Temperature Operating Pressure Operating Temperature

4.3.7

WP2 & WP3 barg

10

o

C

70

barg

1.5-2.5

o

C

Ambient

Potable water/Fresh Water Fresh water tote tank of 2 x 2.0 m3 capacity shall be provided on the platform for the end users like potable diesel generator.


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Table: 4.16 Design & Operating Conditions for Potable/Fresh water tote tank Description Design Pressure Design Temperature Operating Pressure Operating Temperature 4.3.8

WP2 & WP3 barg

Atm+Full of water column

o

C

70

barg

Atmospheric

o

C

Ambient

Crane A box boom type, diesel engine driven, hydraulic pedestal crane shall be installed on the platform. The crane engine, diesel and hydraulic fluid tanks shall be located on the crane upper works to allow easy access by the crane operator. Crane capacity shall be based on the maximum lift requirements during well services operations.

4.3.9

Power Generation System DC power for the remote wellhead platform WP2 & WP3 shall be provided by a hybrid power system. The hybrid power system will consists of the combinations of Thermoelectric Generators (TEGs) and Solar power system (70:30) that will produce 24 VDC power for the instrumentation, control system, radios and battery float charging. The hybrid DC power system will be designed on the concept that both TEGs and Solar power provide continuous power supply during “sunlight” day while simultaneously maintaining the battery charge in the float charge mode. When the Solar system is not capable of generating power e.g. at night time or cloudy days etc., the platform power will be supplied by TEG and supplemented by battery banks. A mobile potable Diesel Engine Generator will provide AC power for lighting and small power loads during platform visits. Power system shall be able to supply all loads in WP. The number of TEG required shall be 10 (9 operating + 1 standby).

4.3.10

Nitrogen Nitrogen required during any shutdown or commissioning shall be supplied by Nitrogen cylinders.


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PROCESS DESIGN CRITERIA This section covers the process design criteria in brief for determining the design pressure and design temperature for major items applicable for the wellhead platforms. The minimum requirements for process sizing criteria are given in Zawtika General Specification – Process Sizing Criteria, ZGS-PRO-101.

5.1

Design Pressure

5.1.1

Wellhead System and Flow lines Well head pressure is a potential source of over-pressure. The design pressure for wellhead and associated tree including wing valve, are designed according to the requirements of reservoir. For conversion spool and flow line, the design pressure should be greater than the wellhead shut-in pressure (WHSIP). If the WHSIP is only marginally above an ANSI rating at the selected design pressure (at design temperature), then credit can be considered for temporary pressure excursions. In accordance with piping code ASME B31.3 for gas; design pressure may be exceeded by up to 33% above design pressure for 10 hours per upset event for up to 100 hours per year.

5.1.2

Piping The design pressure of the piping should not be less than: •

1.1 times the maximum operating pressure.

•

Set pressure of the relief valve when mounted on the line plus static head.

•

Set pressure of the relief valve mounted on equipment plus static head and friction loss.

•

Maximum pressure that an item of equipment can generate e.g. shut-off head of centrifugal pumps, stalling pressure of reciprocating compressors etc. (If applicable)

•

The pressure at the most severe condition of coincident internal/ external pressure and temperature.

5.1.3

Pressure Retaining Equipment Pressure retaining equipment other than vessels should be designed for a maximum operating pressure or expected upset, plus a safety margin. The safety margin should be at least 10% of the maximum operating pressure or 2 barg whichever is the greater. The minimum design pressure for equipment other than low pressure/atmospheric storage tanks shall be 3.5 barg.


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For gas disposal systems not considered for flash back protection should be designed for MAWP of 8.6 barg (125 psig) as per API14J. 5.1.4

Pressure Vessels Maximum operating pressure for vessels is defined as 1.1 times the maximum pressure under normal operation. Test Separators will be considered on an individual basis.

5.1.5

Atmospheric Tanks Storage tanks operating at atmospheric pressure which are vented should be designed as being full of water or the medium to be stored, whichever has the higher density.

5.1.6

Pipeline The design pressure of pipeline will be based on the design pressure of Production header or Booster Compressor (if installed) design pressure whichever is limiting.

5.2

Design Temperature

5.2.1

Maximum Design Temperature The maximum design temperature should be the greatest of the following: •

Maximum operating temperature plus at least 15°C or;

•

Black bulb temperature of 70°C unless the equipment is insulated or other mitigating action is taken.

Insulation for personnel protection should be provided for equipment/ piping having operating temperature of 70°C and above. When establishing the design temperature, consideration should be given to all abnormal operating conditions e.g. Start-up, relieving conditions, shut down, depressuring, regeneration etc. For process coolers, the downstream equipment should be suitably specified such that the maximum design temperature is not exceeded by the failure of the upstream cooling medium.

If instrumented systems are used to limit the temperature of

downstream equipment in this instances, then these trips should be via the ESD (or unit ESD) system. 5.2.2

Minimum Design Temperature The minimum design temperature should be the lowest of: •

Design temperature should be 5 °C below minimum operating temperature or


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Design temperature should be 10 °C below minimum temperature resulting from depressurization whichever is lower.

Depressurization calculations should be based on de-pressuring from highest operating conditions (PAHH) or settle out conditions (from normal operating condition); as appropriate as per guideline of API 521, and may take into consideration the thermal capacity of the vessel and atmospheric heat inflow. Consideration may be given to heat transfer from the surroundings, exchange of heat between the vessel or piping wall and the depressurized gas, and heat tracing of the vessel to limit the possible low temperatures.

Such cases should be justified by

calculation and approval obtained on a case by case basis prior to specifying low design temperatures. There is a risk that cold de-pressurized equipment may be re-pressurized while still cold. Consequently, consideration should be given to specify both the maximum and minimum design temperatures coincide with maximum design pressure. 5.3

Control Valves No margin need be applied to the rated flow rate or pressure drop for sizing control valves. The % opening of the control valves at normal and maximum flow rates should be calculated. Typically it is not expected that the valves would exceed 80% full opening at maximum flow rate.


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LIST OF CODES AND STANDARDS As a minimum, the latest versions of the following Codes and standards shall be used for design of the facilities: •

API RP 14E, American Petroleum Institute “Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems”, 5th Edition, October 1991; Reaffirmed March 2007.

•

API RP 14C, American Petroleum Institute “Recommended Practice for Analysis, Design, Installation and Testing of Basic Surface Safety Systems for Offshore Production Platforms”, 7th Edition, March 2001; Reaffirmed March 2007.

•

IP 15 Area classification code for installation handling flammable fluids;

•

API STD 520, American Petroleum Institute “Sizing, Selection, and Installation of Pressure Relieving Devices in Refineries”. Part I - Sizing and Selection Eight Edition, Dec 2008

•

API STD 521, American Petroleum Institute “Pressure-Relieving and depressuring Systems” Fifth Edition, Jan 2007(Includes ERRATA June 2007) Addendum May 2008

•

API RP 14J, American Petroleum Institute “Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities, 2nd edition, May 2001; Reaffirmed March 2007.

•

API RP 14G Recommended Practice for Fire Prevention and Control on Open Type Offshore Production Platforms, 4th Edition, April 2007.

•

API RP 2030, Guidelines for Application of Fixed Fire Water Spray Systems for Fire Protection in the Petroleum and Petrochemical Industries

3rd

Edition,

July 2005 •

National Fire Protection Agency (NFPA) Codes.

•

ASME B31.3-2010, ASME Code for Pressure Piping.


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REFERENCES The following documents are used as a reference: •

Wellhead Platform Design Basis (MM-ZTK-1A-WP-GEN-BOD-0001)

•

Zawtika General Specification - Process Sizing Criteria, Document no.: ZGSPRO-101.

•

Zawtika General Specification – Pressure Protection Relief & Hydrocarbon System, Document no.: ZGS-SAF-105

•

EPCIC Punch List For Work Package 3 Wellhead Platforms (MM-ZTK-1A-WPGEN-REP-0003).


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MM-ZTK-1A-WP-PRO-BOD-0100 Rev. C1.Process Design Basis.pdf

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