specification for instrumentation & control

Sakhalin Energy Investment Company, Ltd.Controlled Document

Sakhalin II Phase II Project Facilities Design

Document Number:

Project Origin Module Discipline Doc Type Doc No. Sheet No. Rev No.

1000 S 90 30 S 4031 00 043

Title:

SPECIFICATIONFOR

INSTRUMENTATION and CONTROLS

Custodian SEIC Instrument Technical Authority (TA/2)J Moore (SEIC)P Preliminary – For Comment/Information

Issue Purpose AFD Approved for Design AFC Approved for Construction T TEOC Approval Document

Rev Issue Purpose Description

Originator: Name (Company) Signature

Date Checked by: Name (Company) Signature

Approved by: Name (Company) Signature

K T R Fairall - (AMEC) KTRF 24th July 2001P1 P Issued for Comments J E Todman - (AMEC) JET 25th July 2001

E Holdstock - (SEIC) EH 25th July 2001

K T R Fairall - (AMEC) KTRF 31st Aug 200101 AFD Issued for Design J E Todman - (AMEC) JET 31st Aug 2001

And TEOC E Holdstock - (SEIC) EH 17th September

K T R Fairall - (AMEC) KTRF 1st March 2002

02 AFD Revised Issue for J E Todman - (AMEC) JET 1st March 2002

Design E Holdstock - (SEIC) EH 4th March 2002

KTR Fairall - (SEIC) KTFR 1st March 2003

03 AFD Revised Issue for E Holdstock - (SEIC) EH 4th March 2003

Design J Moore - (SEIC) JM 22nd April 2003

04 AFD Revised Issue for J Moore - ( SEIC) JM 8/12/03

Design J Swaffer - (SEIC) JS 8/12/03

J Moore - ( SEIC) JM 15/12/03

This document contains proprietary information and is intended for use by Sakhalin Energy Investment Company, Ltd. (SEIC) authorised personnel or companies only. The copyright of this document is vested in SEIC. All rights reserved. The contents of this controlled document shall not be altered without formal approval of the document Custodian.

SPECIFICATION FOR INSTRUMENTATION AND CONTROLS Rev 043

REVISION CHANGE DETAILS

Rev Location of Change Brief Description of Change

P1 Re-issued as an SEIC DocumentThis document was originally issued as AMEC document number3400-T-90-30-S-4007-00

01 Various Incorporates Clients & Parsons comments. Now covers Offshore and Onshore facilities.

02 Pages 7, 8, 13, 16, 39, 40, 46, 51 and 56

Various references to Rotating Equipment Monitoring and Data Acquisition System added (Clauses 1.2, 1.3, 4, 7 and 7.1).Reference to Enviromental and External Loads data sheets added (Clause 2.8). Latest IEC standards for Electromagnetic Compatibility added (clause 2.13)Inst/Elec cable minimum segregarion 500 mm (Clause 13.1).List of standard drawings added (Appendix A).

03Pages 6, 16, 17,23, 64 65

LNG scope clarification, Intools deliverables revision.I/S earth reference deleted, covered in referenced spec.

Environmental Spec. numbers deleted. General reference .Reference to Metering Strategy inserted.

SEIC Drawing Numbers AllocatedAlignment with BOD standards.

04 0 Section 2.1.2 – Swagelok inserted as standard supplier.Instrument tubing material aligned with BOD 6.0

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TABLE OF CONTENTS1. INTRODUCTION................................................................................................6

1.1 General................................................................................................................61.2 Abbreviations.......................................................................................................81.3 Control Philosophy..............................................................................................91.4 Definitions............................................................................................................9

1.4.1 Instrumented Protective Function (IPF)...............................................................91.4.2 Instrumented Protective System (IPS)................................................................91.4.3 Instrumented Protective Function Class..............................................................91.4.4 Executive Action................................................................................................111.4.5 Failure to safety.................................................................................................111.4.6 Safety Integrity Level (SIL)................................................................................111.5 References........................................................................................................11

2. INSTRUMENTATION.......................................................................................122.1 General..............................................................................................................122.2 Fieldbus.............................................................................................................132.3 Supplies.............................................................................................................132.4 Electrical Connections.......................................................................................132.5 Earthing.............................................................................................................132.6 Units & Scales...................................................................................................14

2.6.1 Units of Measurement.......................................................................................142.6.2 Scales................................................................................................................14

2.7 Hazardous Area Certification............................................................................152.8 Ambient Conditions...........................................................................................152.9 Environmental Protection..................................................................................152.10 Materials and Certification.................................................................................16

2.10.1 Materials..........................................................................................................162.10.2 Process Medium Interface...............................................................................162.10.3 Material Certification........................................................................................16

2.11 Tagging and Instrument Nameplates................................................................162.12 Impulse Lines and Air Lines - Tube, Fittings & Accessories...........................172.13 Electromagnetic Compatibility (EMC)................................................................18

2.13.1 Emissions........................................................................................................182.13.2 Immunity..........................................................................................................18

3. REQUIREMENTS FOR FIELD INSTRUMENTS..............................................193.1 Process Connections........................................................................................193.2 Flow Measurement............................................................................................20

3.2.1 Orifice Plates.....................................................................................................203.2.2 Meter Proving Facilities.....................................................................................21

3.3 Pressure Measurement.....................................................................................213.4 Level Measurement...........................................................................................22

3.4.1 General..............................................................................................................223.4.2 Level Transmitters.............................................................................................223.4.3 Level Switches...................................................................................................243.4.4 Level Gauges....................................................................................................243.4.5 Tank Gauging Systems for Product and Storage Tanks...................................24

3.5 Temperature Measurement...............................................................................253.5.1 Thermowells......................................................................................................253.5.2 Electronic Temperature Elements.....................................................................253.5.3 Pneumatic Temperature Transmitters...............................................................26

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3.5.4 Temperature Switches......................................................................................263.5.5 Temperature Gauges........................................................................................26

3.6 Process Stream Analysers................................................................................263.6.1 Analysers...........................................................................................................263.6.2 Analyser Houses...............................................................................................26

4. ACTUATED VALVES......................................................................................274.1 Control Valves...................................................................................................27

4.1.1 General..............................................................................................................274.1.2 Globe Valves.....................................................................................................284.1.3 Butterfly Valves..................................................................................................304.1.4 Ball Valves.........................................................................................................304.1.5 Self-Acting Regulators.......................................................................................304.1.6 Control Valve Bodies.........................................................................................304.1.7 Control Valve Packing Materials.......................................................................314.1.8 Control Valve Trims...........................................................................................31

4.2 Actuated Shut-Off Valves (incl. ESD and Blow-down Valves)..........................324.2.1 General..............................................................................................................32

4.3 Valve Actuators.................................................................................................334.3.1 Actuator Materials.............................................................................................334.3.2 Control Valve Actuator & Positioner..................................................................334.3.3 Choke Valve Actuator........................................................................................344.3.4 On/Off Valve Actuator.......................................................................................344.3.5 Actuator Sizing..................................................................................................354.3.6 Actuator Torque Requirement...........................................................................354.3.7 Stroking Times...................................................................................................354.3.8 Actuator to Valve Mounting..............................................................................36

4.4 Actuated Valve Accessories..............................................................................364.4.1 Handwheels......................................................................................................364.4.2 Limit Stops.........................................................................................................364.4.3 Air Supply Filters & Regulators.........................................................................384.4.4 Actuator Lifting Eyes.........................................................................................384.4.5 Pressure Gauges..............................................................................................384.4.6 Limit Switches....................................................................................................384.4.7 Solenoid Valves.................................................................................................394.4.8 Quick Exhaust Valves & Volume Boosters........................................................404.4.9 Lock-up Valves & Local Instrument Air Receivers............................................404.4.10 Local Instrument Air Receivers & Hydraulic Accumulators.............................40

5 PRESSURE RELIEF VALVES........................................................................415.1 General..............................................................................................................415.2 Conventional and Balanced Bellows Relief Valves...........................................425.3 Pilot Operated Relief Valves.............................................................................425.4 Small Relief Valves...........................................................................................425.5 Rupture Discs....................................................................................................435.6 Materials (Additional requirements for Relief Valves).......................................43

6. SHUTDOWN PHILOSOPHY AND HIERARCHY.............................................447. CONTROL AND SAFETY SYSTEM ARCHITECTURE...................................44

7.1 Process Control System (PCS).........................................................................457.2 HVAC Controls..................................................................................................46

7.2.1 HVAC Controls..................................................................................................467.2.3 Fire Dampers.....................................................................................................46

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7.3 Emergency Shutdown System (ESD)...............................................................467.3.2 I/O Card Status Diodes.....................................................................................487.3.3 Final Control Elements......................................................................................48

7.4 High Integrity Pressure Protection System (HIPPS).........................................507.5 Alarm & Annunciation Systems.........................................................................50

7.5.1 Operating Sequences........................................................................................507.5.2 Lamp/Window Colours......................................................................................50

7.6 Fire and Gas Control System (F&G).................................................................517.7 Rotating Equipment Monitoring and Data Acquisition.......................................52

8. TELECOMMUNICATIONS..............................................................................529. WELLHEAD CONTROL SYSTEM...................................................................5210. PACKAGED EQUIPMENT CONTROL PANELS............................................52

10.1 Unit Control Panels...........................................................................................52

11. LOCAL CONTROL PANELS...........................................................................5312. PANEL CONSTRUCTION...............................................................................54

12.1 General..............................................................................................................5412.2 Equipment Room Layout...................................................................................5412.3 Mechanical........................................................................................................5412.4 Electrical............................................................................................................55

13. INSTALLATION...............................................................................................5613.1 Instrument Installation.......................................................................................5613.2 Heat Tracing & Insulation..................................................................................58

14. INSPECTION AND TESTING..........................................................................5814.1 Inspection..........................................................................................................5814.2 Casting and Weld Testing and Inspection.........................................................5914.3 Functional Testing.............................................................................................59

14.3.1 Instruments......................................................................................................5914.3.2 Local Control Panels.......................................................................................5914.3.3 Plant Installation..............................................................................................59

14.4 Valves and Actuators........................................................................................6014.4.1 Actuator testing...............................................................................................6014.4.2 Actuator/Valve Assembly Tests & Inspections................................................60

14.5 Relief Valves......................................................................................................6014.6 QA Requirements..............................................................................................60

15. INSTRUMENT SYSTEMS TYPICAL BLOCK DIAGRAM................................61

APPENDIX A STANDARD DRAWINGSAPPENDIX B STANDARDS AND CODES OF PRACTICE APPLICABLE TO INSTRUMENS

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1. INTRODUCTION

1.1 GENERAL

This document describes the minimum requirements for instrumentation & control systems to be installed on the Sakhalin Phase II Project. Comprising of two new platforms PA-B, Lun-A, an existing platform PA-A, sub-sea pipelines, Onshore Production Facility (OPF), main onshore oil and gas pipelines, two oil booster stations, two gas compressor stations, pipeline take-off connections and valves for future domestic gas supply near Boatasyn, Oil Export Terminal (OET), Liquefied Natural Gas (LNG) plant and a marine Tanker Loading Unit (TLU).

Note: LNG have their own minimum requirements Ref. 7000-S-61-37-S-0002 (General Instrument Requirements)

The PA-B platform will produce oil and associated gas from the Piltun reservoir and will be equipped with Process, Utilities, Living Quarters and full drilling capability. The Lun-A platform will produce gas and condensate from the Lunskoye field and will be equipped with first stage separation facilities, Utilities, Living Quarters and drilling capability.

Crude oil, gas and condensate will be delivered from the offshore platforms by pipelines to the OPF. The gas from the OPF will be supplied to the LNG plant via a gas pipeline and compressor stations. In the future gas will be tapped off the pipeline near Boatasyn for domestic supplies. The oil from the OPF will be supplied to the OET via an oil pipeline and oil booster stations where it will be stored and then pumped to tankers via the TLU.

Engineering will be in accordance with applicable Statutory Regulations, National and International Codes and Standards.

Instrumentation and control requirements are defined on the Process and Utilities Engineering Flow Sheets (PEFS & UEFS) specifically developed for the project.

The design shall ensure that all instruments and controls required for correct operation are provided and shall ensure safe, reliable and convenient start-up, automatic operation and controlled shutdown of the process and utility facilities.

Computer based design tools will be used on the project to produce instrumentation documentation as follows:

INtools (typical) Instrument IndexInstrument Data sheetsI/O SchedulesProcess Hook-UpsLoop DiagramsTermination DiagramsCable SchedulesMTOs

Reliability of all offshore instrumentation and control equipment to operate at all times is essential. Only equipment for which the Supplier can demonstrate satisfactory experience shall be supplied, prototype equipment will not be considered.

The design life of all instrumentation shall be 30 years minimum.

All instruments shall be given a unique tag number. Tag numbers will be allocated in accordance with the Specification for Tag Numbering Instrument and Fire and Gas Devices, 1000-S-90-37-S-4004-00. All instruments shall be identified and physically

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tagged by the Supplier, using the specified labelling system in accordance with the standard drawing in Appendix A.

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1.2 ABBREVIATIONS

The following abbreviations are used in this document :ac - alternating currentdc - direct currentCCR - Central Control RoomDEP - Design Engineering PracticedBA - Decibel AbsoluteESD - Emergency ShutdownF&G - Fire and GasFAR - Field Auxiliary RoomGRP - Glass Reinforced PlasticHC - HydrocarbonHIPPS - High Integrity Pressure Protection SystemHVAC - Heating Ventilation and Air ConditioningI/O - Input / OutputI/P - Current to PneumaticICSS - Integrated Control & Safety SystemIPF - Instrumented Protective FunctionIPS - Instrumented Protective SystemLAN - Local Area NetworkLC - Lock ClosedLCP - Local Control PanelLNG - Liquefied Natural GasLO - Lock OpenLUN-A - Lunskoye – A PlatformMER - Main Equipment RoomMPI - Magnetic Particle ExaminationMTBF - Mean Time Between FailureMTTR - Mean Time To RepairOET - Oil Export TerminalOPF - Onshore Processing FacilityPA-A Piltun Reservoir - A Platform (Molipack)PA-B Piltun Reservoir - B PlatformPCS/PSD - Process Control System/Process Shutdown SystemPEFS - Process Engineering Flow SchemePES - Programmable Electronic SystemPFD - Probability of Failure on DemandPLC - Programmable Logic ControllerPSD - Process ShutdownPSV - Pressure Safety ValvePUQ - Process, Utilities and QuartersRDAS - Rotating Equipment Monitoring and Data Acquisition

SystemRTD - Resistance Temperature DetectorRTU - Remote Telemetry UnitSCADA - Supervisory Control and Data AcquisitionSIL - Safety Integrity LevelTCP/IP - Transmission Control Protocol/Internet ProtocolUCP - Unit Control PanelVDU - Visual Display UnitUPS - Uninterruptible Power SupplyUV - Ultra Violet

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1.3 CONTROL PHILOSOPHY

The control and safety system for each facility will comprise an Integrated Control and Safety System (ICSS), comprising of the Process Control System (PCS/PSD), the Emergency Shutdown (ESD) System and the Fire and Gas (F&G) System.

All instrumentation and control equipment shall be suitable for use in an onshore/offshore environment and shall be manufactured from materials compatible with the process and ambient conditions specified.

All instrument electrical circuits and pneumatic loops shall be designed for fail-safe action on loss of supply, with the exception of line monitored Fire and Gas related equipment which should be clearly identified.

Transmitters, rather than switches, are preferred for alarm and trip functions and shall be used wherever feasible. Trip functions shall be provided with pre-alarms derived from separate initiating devices (i.e. two transmitters, one for indication, control and pre-alarms, the other for trip function). For SIL 1 and above Instrumented Protective Functions, process shutdown devices shall have a dedicated process impulse line connection.

The normal operator interface for control of process and utility facilities and packages will be via the PCS. The control of package plant shall be performed either by the PCS or by the package supplier’s control panel, as specified on the PEFS.

Package instruments and controls shall be interfaced with the Process Control System (PCS/PSD), Emergency Shutdown (ESD) System, Fire & Gas (F&G) System and the Rotating Equipment Monitoring and Data Acquisition System as shown on the PEFS and/or defined in the package inquiry and attachments.

Package Unit Control Panels (UCP) shall be mounted either locally, in the FAR (onshore), or in the MER (offshore), as specified in the requisition. The package control system shall be interfaced with the PCS, ESD and F&G systems so that package operation is pre-empted by the ESD and F&G systems via hard wired “package shutdown” signals.

1.4 DEFINITIONS

1.4.1 Instrumented Protective Function (IPF)A function composed of one or more initiators, an Instrumented Protective System and one or more actuators for the purpose of preventing hazard.

1.4.2 Instrumented Protective System (IPS)The (electrical and/or electronic and/or programmable electronic) logic solver component of the Instrumented Protective Function complete with input and output equipment.

1.4.3 Instrumented Protective Function ClassClassifications from I to VI and X, detailing the requirements for the Instrument Protective Function. The Shell IPF methodology will be applied to determine SIL categories. IPF class I & II will be implemented in the PSD and will not have a SIL category.

The following are possible implementations of IPF Classes related to un-revealed failures. ( Equivalent IEC 61508 Safety Integrity Levels SIL indicated in brackets1 )Class I [SIL a1] PFD >10-1

Initiator No special equipment.IPS No special equipment.Actuation Alarm & manual action or switching function.

Class II [SIL a2] PFD >10-1Initiator No special equipment.IPS No special equipment.

1 SIL a1 and a2 terminology are Shell Group specific and are not referenced in IEC 61508

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Actuation Switching function.

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Class III [SIL 1] PFD >10-2 to <10-1Initiator Separate from control.IPS PLC or solid state, (TÜV approved AK3).Actuation Valve: Separate from control, unless demand on IPF cannot be

caused by a failure of the control valve and tight shut off is not required.

Pump stop circuit: No special equipment.Class IV [SIL 2] PFD >10-3 to <10-2Initiator Separate from control.IPS PLC or solid state, (TÜV approved AK4).Actuation Valve: Separate from control, un-revealed failure robust (back-up may be a

control valve tripped by a solenoid, if tight shut off is not required). Pump stop circuit: No special equipment.

Class V [SIL 3] PFD >10-4 to <10-3Initiator Separate from control, un-revealed failure robust.IPS PLC or solid state, (TÜV approved AK5).Actuation Valve: Separate from control, un-revealed failure robust (back-up may be a

control valve tripped by a solenoid, if tight shut off is not required).Pump stop circuit: No special equipment, un-revealed failure robust.

Class VI [SIL 3] PFD >10-4 to <10-3Initiator Separate from control, un-revealed failure robust.IPS Solid state, (TÜV approved AK6).Actuation Valve: Separate from control, un-revealed failure robust, diverse (back-up

may be a control valve tripped by a solenoid, if tight shut off is not required).

Pump stop circuit: No special equipment, un-revealed failure robust.

Class X [SIL 4] This classification should be avoided. Change to a safer design.

1.4.4 Executive ActionAn executive action describes a physical control function performed by the ESD/F&G Systems e.g. de-pressurisation, plant shutdown, electrical isolation etc.

1.4.5 Failure to safetyFailure to safety is the automatic reversion to the least hazardous condition upon ESD System failure, signal failure or loss of actuator power.

1.4.6 Safety Integrity Level (SIL)Safety Integrity Levels are as defined in IEC 61508.

For further details on SIL Levels refer to:Platforms PA-B, Lun-A, Tanker Loading Unit TLU

3400-T-61-30-S-4033-00 - Safety System Philosophy (PSD/ESD/F&G/HIPPS)

OPF and Booster No. 1.6000-P-61-04-S-7001-1 - Emergency Shutdown and Emergency

Depressurisation Philosophy.OET, Booster No. 2 and Gas Distribution

5600-Y-90-30-S-4015-00 - Control and Safety System Philosophy

1.5 ReferencesApplicable Regulations, Codes and Standards are listed in Appendix B.

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2. INSTRUMENTATION

2.1 GENERAL

All field and in-line instruments throughout the onshore and offshore facilities shall be selected, according to service and process conditions, from the Suppliers on the Qualified Vendors List.

The upper and lower pressure and temperature limits of the instrument pressure containing parts shall meet at least the requirements of the piping class or the vessel design limits to which it is connected.

In general all instruments will be of the electronic type, fully-floating in the field, powered and earthed by the system to which they are connected.

Analogue measurements are preferred and shall use 4 - 20 mA signals with a nominal 24 Volts isolated dc power supply.

For process services the primary measurement shall be performed using an electronic transmitter with the switching being carried out by the PCS or ESD system. Trip

settings shall be between 10% and 90% of the adjusted range.

Direct connected two-wire 4 to 20 mA dc signal format will be used for all shutdown and critical control loops.

Transmitters in ESD service should have the same instrument range, adjusted range and accuracy as the corresponding process transmitter in order to facilitate measurement comparisons.

Transmitters in ESD and HIPPS service shall be identified with red nameplates.

Where speed of response is not critical, electronic transmitters shall be ‘SMART’ type with Foundation Fieldbus capability, online diagnostics and a means of remote re-ranging. This may take the form of either a special communication tool or a set of re-calibration software and standard interface leads to enable the instrument to be re-calibrated in the field via an IBM compatible PC, located in a safe area. A “Windows” based software package shall be provided.

Electronic transmitters may be fitted with local output signal indicators where specified on datasheets. For pressure services, where they are meant to replace local pressure gauges, they should be configured to display in engineering units, to match the range of the transmitter. For level services they should be configured to read from 0 - 100% linear and for flow services they should be configured to read from 0 - 10 square root. If digital displays are not available then analogue indicators shall be provided. Failure of the output meter shall not cause failure of the measurement signal output to the control system.

All digital I/O signals shall be powered from the respective control system at 24 Volts dc. Digital input signals connected to the PCS or ESD systems shall be via volt free contacts powered by the PCS or ESD system.

ESD digital inputs shall be hardwired. Digital inputs used for monitoring purposes shall be multiplexed in the field on a system to be agreed with the MAC Supplier.

Contacts shall be of noble metal, suitable for use in the low-power circuits typically found in modern electronic control systems.

For purely local control loops (i.e. not requiring operator intervention at the CCR) pneumatic devices may be considered.

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The ICSS systems shall perform an orderly and safe shutdown (Unit Shutdown) of the process and utility facilities if the instrument air system supply pressure falls below the minimum pressure.

2.2 FIELDBUS

Transmitters and control valves used for simple regulatory control and monitoring loops will use the internationally recognized Foundation Fieldbus format. For loops that require fast response times, (e.g. compressor anti-surge loops) or process critical loops (SIL 1 and above), the traditional 4-20 mA analogue signal transmission technique should be used. Intelligent instruments will be used on condition that they provide the necessary speed of response.Where a loop is identified as being process critical the use of redundant configuration of fieldbus devices shall be evaluated.

2.3 SUPPLIES

Instrument Electrical Power Supply:PCS - 230 Volts 50 Hz UPS Dual Uninterruptible Power Supply

Hold up time after shutdown of all power generation - 1 hour.

ESD and F&G (including acting PCS window)- 230 Volts 50 Hz UPS Dual Uninterruptible Power Supply

Hold up time after shutdown of all power generation - 3 hours.

Panel Lights and Heaters - 230 Volts 50 Hz Normal Supply

Solenoid Valves - 24 Volts dc

Derived from Instrument supplies within the system controlling the solenoid valve.

Hydraulic Power Unit - 230 Volts 50 Hz Normal Supply

+ 230 Volts 50 Hz Essential Services Supply

Hydraulic supply to - 160 – 207 bargvalves (not wellhead)

Instrument Air Supply Ranges : (As Specified on Data Sheets)Minimum Pressure 3.5 barg to 4.2 barg

Operating Pressure: 7.0 barg to 8.5 bargDesign Pressure: 10.0 barg to13.0 bargDew Point @ Operating Pressure: –60 °C

2.4 ELECTRICAL CONNECTIONS

All electrical cable entries shall be M20 x 1.5 mm ISO (female) and connections shall be by screw terminals.

Flying leads shall be avoided wherever possible. Equipment with flying leads shall be provided with a separate junction box for termination of the leads, if not armoured, the flying leads shall be protected by a flexible conduit.

2.5 EARTHING

Earthing shall be in accordance with Specification for Instrument Earthing, 1000-S-90-30-S-4036-00.

Individual instruments housings and junction boxes will be earthed through the mechanical mounting/fixing to plant steelwork. Cable glands shall form a good earth bond between the cable armour, the instrument and/or junction box.

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Screens will be cut back and insulated at the field device and will be connected to the Instrument Earth at the panel/marshalling rack end.

Panels and marshalling cabinets shall be provided with a Safety Earth bar and an insulated Instrument Earth bar.

Stainless steel cable tray will be insulated from supports to prevent electrolytic actionbetween dissimilar metals and earthed at suitable locations.

2.6 UNITS & SCALES

2.6.1 Units of MeasurementAre defined in project Specification 1000-S-90-01-S-0005-00.

Units of measurement shall be as follows:Density kg/m3

Mass flow rate kg/hVolumetric flow rate for liquids m3/hVolumetric flow rate for gas Sm3/h at 15°C and 1.013 baraVolumetric flow rate for air/N2 Nm3/h at 0°C and 1.013 baraMolecular weight kg/kg molPressure, gauge barg, mbarg, mm wg

absolute bara, mbara, mm wgdifferential bar, mbar, mm wgvacuum mbar

Temperature °CLevel %, m, mmViscosity dynamic cP = mPa.s

kinematic cSt

2.6.2 ScalesScales should have the following graduations:Variable ScalesFlow (differential pressure) 0-10 sq.rtFlow (linear signal) 0-100 uniformLevel 0-100 uniformPressure Direct readingTemperature Direct readingOther variables Direct readingCombination of flow Direct reading(differential pressure and other variables.)

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2.7 HAZARDOUS AREA CERTIFICATION

All field mounted Instrumentation should be certified to CENELEC standards as being suitable for use in a Zone 1, Gas Group II B, Temperature Class T3 hazardous environment.

The allowable methods of hazardous area protection for Zones 1 and 2 are listed below: flameproof, type EEx(d) or explosion proof (Preferred for Onshore) increased safety, type EEx(e) or equivalent intrinsic safety, types EEx(i)a and b, or equivalent (Preferred for Offshore) special protection, type EEx(s) or equivalent

Where the only means of protection for the application is EEx(i), galvanic isolator protection devices shall be used.

Instrumentation equipment installed in areas classified as hazardous shall be selected and installed in accordance with IEC 60079.

2.8 AMBIENT CONDITIONS

Instrumentation shall be able to withstand shock accelerations generated during transport and the seismic generated accelerations and forces of a Seismic event.

Offshore equipment will additionally be subjected to moving ice induced vibration..

Process plant areas will be partially enclosed and heated to reduce the worst effects of weather and wind chill. However situations will arise, for example at start-up, when the outside ambient conditions will apply.

Instrumentation located in process plant areas shall be suitable for installation in ambient conditions as specified on the Environmental Data Sheet.

All instrumentation shall be designed to survive a cold soak test at –40oC.The Central Control Rooms and Equipment Rooms will be air-conditioned.

For further details refer to project specific environmental data sheets and external load data sheets

2.9 ENVIRONMENTAL PROTECTION

All plant located instrumentation including junction boxes and local control panels shall be weatherproof to IP 65 rated in accordance with IEC 60529. Cables entries to field junction boxes and local panels shall be bottom entry.

Instruments impulse lines in external areas will be thermally insulated and where appropriate electrically heat traced. Instruments located in external areas will be fitted within heated enclosures.

Instruments, actuators, instrument housings, junction boxes, cable tray etc., shall be 316 stainless steel, Instrument enclosures shall be G.R.P. Aluminium materials are not acceptable.

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2.10 MATERIALS AND CERTIFICATION

2.10.1 MaterialsBodies of in-line instruments (e.g. control valves) shall be manufactured from materials suitable for the service, as defined by the relevant piping specifications and piping material classes or better. Bodies of other instruments (e.g. pressure transmitters, thermowells etc.) and all wetted components shall be manufactured from 316 stainless steel or better if it is required by the piping specifications, or the instrument Manufacturer's standard material if this superior and has a higher corrosion resistance. e.g. Hastelloy, Monel, etc

Where piping or vessel specifications require compliance with NACE MR-01-75 (latest edition) then the requirement shall be extended to instrumentation and components in contact with the process fluid.

2.10.2 Process Medium Interface“in-line” instruments that are mounted directly into process/utility lines or vessels/equipment. Material certification is required. Typical examples of in-line instruments are control valves, shut-off valves, vent/de-pressurising valves, relief valves, vortex meters, thermowells, orifice/restriction plates, turbine flowmeters, level transmitters, level switches, analyser sample probes etc.

“on-line” instruments that are in direct contact with the process medium, but are not an integral part of the process/utility lines or vessels/equipment. Material certification is required. Instruments are deemed to be not directly connected if they are connected via small (max. 1” NB) piping spec., block valves and instrument impulse tubing. Typical examples of off-line instruments are pressure gauges, pressure transmitters, D.P. type flow transmitters, analyser sample system instruments (but not the sample probe) etc. Pressure gauges that screw directly into small piping specification. multiple valve assemblies, typically double block and bleed manifolds, shall also be deemed as “on-line” instruments.

“off-line” instruments that are not in direct contact with the process medium. Material certification is not required. Typical examples of off-line instruments are resistance temperature elements, bi-metal thermometers, signal converters and receiver instrumentation and instrument air service.

2.10.3 Material CertificationFull material traceability and certification is required for “in-line” and “on-line” instrumentation to the same standard as that specified for the line or vessel to which they are connected. Material certification shall be provided for all pressure retaining parts to EN 10204 3.1B. If the application is for sour service then the materials shall additionally meet the requirements of NACE MR-01-75 (latest edition). This shall include non-wetted parts such as valve bonnet/body bolting, internal parts such as valve trims, relief valve springs, etc., (which are pressure retaining when the valve is closed), blow-out proof stems etc.

Instrument impulse pipe, tube and fittings shall be subject to the same material certification requirements as “in-line” instrumentation. In addition for sour service applications hardness values shall meet the requirements of NACE MR-01-75 (latest edition), be suitable for use with compression fittings.

2.11 TAGGING AND INSTRUMENT NAMEPLATES

All items of instrument equipment will be identified with a tag number. This number will be shown on the PEFS and listed in the instrument index and respective instrument requisition. The instrument tag number shall be shown on all relevant documents and drawings.

All instruments, system cabinets, junction boxes etc. shall be provided with nameplates showing either the full tag number and service description or just tag number. The type of nameplates shall be as defined on Standard Drawing (see Appendix A).

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Service descriptions shall be in dual language, English and Russian

Each individual field instrument shall have shall have a stainless steel tag engraved with the full instrument tag number attached permanently either stainless steel rivets or with 0.7 mm stainless steel wire.

The location of all field instruments shall be identified by tag number and service description on a laminated plastic nameplate fixed adjacent to the instrument. For instruments on local panels, nameplates with the tag number and service description shall be mounted on the panel face with the tag number repeated behind the panel. Labels for ESD instrumentation (second letter in the tag number function identifier is Z) shall be Black letters on a Red background. All other labels shall be Black letters on a White background.

Field-mounted instruments, local panel-mounted instruments and junction boxes should have a nameplate type A;

Panel-mounted ancillary equipment, such as switches, running lights, etc. should have a nameplate type B;

Panel-mounted instruments should have a nameplate type C mounted at the rear of the panel adjacent to the instruments.

2.12 IMPULSE LINES AND AIR LINES - TUBE, FITTINGS & ACCESSORIES

For all general offshore applications, tube shall be manufactured from 316L317 grade stainless steel. Fittings and accessories, Instrument Valve Manifolds, Quick-Exhaust Valves etc. shall be manufactured from 316 grade stainless steel. Instrument tubing should be procured in straight lengths with ends sealed and not coiled. Threads on all pipe connection fittings shall still be NPT. Tubing sizes and minimum wall thickness are as follows:

Instrument Impulse Lines 12.0 mm O.D. x 2.0 mm Wall Thickness.& Hydraulic Lines

Instrument Air Lines to users 6.0 mm O.D. x 1.0 mm Wall Thickness.

All tube fittings shall be compression, twin-ferrule type to metric dimensions. A single fitting supplier shall be used throughout the project. For all SEIC projects this supplier shall be SWAGELOK

To prevent seizing of the pipe-threaded connections of male stud couplings, PTFE or other suitable liquid or paste sealant, shall be applied prior to assembly.

For seawater applications, stainless steel is not suitable, materials should be as follows, or equivalent :-

Tubing Copper Alloy ASTM B706/UNS C69100 (“Tungum Alloy” or equal) Tubing fittings Monel 400 Valves Copper alloy to EN CC492K with Monel trims ASTM/UNS N04400.

For marine exposed applications materials should be as follows, or equivalent :- Tubing, Copper Alloy ASTM B706/UNS C69100 (“Tungum Alloy” or equal) Tubing fittings 316 Stainless Steel Valves 316 Stainless Steel

For other corrosive (non-sea-water), applications where Copper Alloys and/or stainless steel is not suitable, other materials, such as:-

Monel ASTM/UNS N04400, Duplex ASTM/UNS S31803, Hastelloy ASTM/UNS N10276

etc., should be selected using the relevant process piping standard as a guide to suitable materials.

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2.13 ELECTROMAGNETIC COMPATIBILITY (EMC)

All equipment or systems containing electrical or electronic apparatus shall satisfy the following requirements of electromagnetic compatibility.

2.13.1 EmissionsEmissions performance shall be in accordance with IEC 61000-6-2 - Electromagnetic compatibility (EMC) – Part 6: Generic standards – Section 2: Immunity for industrial environments.

2.13.2 ImmunityImmunity performance shall be in accordance with IEC 61000-6-4 - Electromagnetic compatibility (EMC) – Part 6: Generic standards – Section 4: Emission standard for industrial environments.

Performance criterion A as applied to immunity of measuring instruments to radiated interference is hereby defined as allowing a degradation in performance not exceeding +/- 0.1% of the output span with the instrument enclosures (covers) in place and not exceeding +/- 0.5% of the output span with the instrument enclosures (covers) removed.

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3. REQUIREMENTS FOR FIELD INSTRUMENTS

3.1 PROCESS CONNECTIONS

The process instrument connections shown in the table below shall be used.Table 1Description Primary Isolation Instrument ConnectionOrifice taps ¾ inch branch, concentrically

reduced to ½ inch with ½ inch flange to appropriate piping class isolation valve

Mating flange with machined½ inch NPT female connection

Pressure 1 inch branch concentrically reduced to ½ inch with ½ inch flange to appropriate piping class isolation valve.2 inch double block & bleed composite valve on H.P. services.

Mating flange with machined½ inch NPT female connection.

Mating flange with machined½ inch NPT female connection.2 inch flange for transmitters with flanged seals and capillaries

Level gaugesMagnetic

1½ inch branches on bridles, piping class isolation valves2 inch direct mounting on vessels,piping class isolation valves

1½ inch flanged

2 inch flanged.

Level gaugesGlass

1½ inch branches,concentrically reduced to ¾ inch with ¾ inch flanges piping class isolation valves

¾ inch flanged

Leveldisplacers (external)

2 inch flanged valve to appropriate piping class

2 inch flanged (Side, Side)(Side, Bottom where sediment or sand might be present)

Level switches(if approved)See 3.4.3

2 inch flanged valve to appropriate piping class

2 inch flanged

DP cells forlevel, with flanged seals and capillaries

3 inch or 4 inch flanged valve to appropriate piping class. Size as required by the seal flanges

3 inch or 4 inch flanged

Stilling Well(for internallevel displacers)

4 inch flanged to appropriate piping class

Thermowells Flanged to appropriate piping class

With cover flange to piping class and Standard Drawing (see Appendix A)

Close coupled instrument connections should be considered with consent of the Principal.

Individual connection(s) should be provided for each instrument on process piping and equipment.

Each process connection shall have an isolating valve except for instruments, which are: installed in the piping, such as vortex, positive displacement or turbine meters and

control valves; installed internally in vessels; separated from the process fluid by means of a thermowell.

Isolation/equalisation/vent/calibration valve manifolds shall be used on all instruments, close-coupled and remotely mounted. Multi-valve instrument manifolds & single instrument valves shall be rated at 2500lb. Vent ports shall be plugged if they are not piped to a safe location.

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Instruments process connections on systems rated ANSI class 600 and above shall be fitted with double block and bleed isolation valve assemblies in accordance with respective piping specification at the point of primary isolation, this shall be in addition to any remotely mounted calibration valve manifold.

Isolation valves shall have a straight through trim and conform to the piping specification.

Primary isolation valves having a flanged connection on the process side and a ½ inch threaded NPT female connection at the "Instrument Connection" side may be offered for those cases in Table 1, requiring a mating flange with 1/2 inch NPT female connection providing that the valves comply with all other requirements of the project piping specifications.

2 valve manifolds shall have ½ in NPT screwed inlet and outlet connections whilst 3 & 5 valve manifolds shall have ½ in NPT screwed inlet connections and flanged outlet connections, suitable for direct bolting to differential pressure transmitters.

Flange rating and finish for process instrumentation connections shall be in accordance with the requirements of the relevant piping specification for or pressure class associated vessel.

Boltholes of flanges shall straddle the normal horizontal and vertical centre lines of the pipe. Gasket types shall conform to the requirements of the project piping standard.

3.2 FLOW MEASUREMENT

Flow measurement requirements are identified in SEIC document 1000-S-90-37-T-4001.Alternative methods to be considered shall be vortex, ultrasonic (“time-of-flight” only, Doppler type shall not be used), electromagnetic, turbine, differential pressure or coriolis. Selection shall be based on the suitability for the specific service application including process conditions, turndown, access, installation and total cost of ownership.

The use of variable-area flowmeters shall be restricted to armoured metal tube types in simple local indication only loops e.g. purge lines, cooling fluid flows and analyser sample loop flowmeters. Glass tube type variable area flowmeters and positive displacement type flowmeters are not to be used.

Where in-line meters are not suitable differential pressure devices such as averaging pitot tubes or square-edge orifice with flanged taps as defined in ISO 5167, may be offered.

3.2.1 Orifice PlatesThe following criteria shall apply in the sizing of orifice plates;

Orifice plates should be sized so that the normal design operating flow falls between 6 and 8 on a 0-10 square root chart but as near 7 as practicable. The orifice/pipe diameter ratio, Beta, should lie between 0.2 and 0.75.

The preferred differential pressure range for liquid flow orifice meters is 250 mbar. Maximum differential pressure should not normally exceed 500 mbar. For gas or vapour flow orifice meters the maximum differential pressure range

should be limited dependent on the static operating pressure as follows:Static Pressure

(barg)Differential Pressure

(mbar) 0.35 to 2.5 0 - 50 2.5 to 6.0 0 – 125 above 6.0 0 – 500

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The exact orifice bore shall be calculated based on the above criteria with the selected differential pressure and used for transmitter range adjustment.

Piping straight length requirements shall be in accordance with ISO 5167 recommendations.

Orifice Plates and flanges shall be in accordance with standard drawings listed in Appendix A.

Orifice plates installed in insulated lines shall have the handle extended sufficiently beyond the flange insulation such that the information required, stamped on the upstream side of the handle, can be read without removing the insulation.

Orifice flanges shall be located in horizontal lines and instrument connection primary process isolation valves shall be in accordance with Section 3.1. The location of tappings for flow meters in vapour/gas service shall be above the horizontal with the instrument impulse lines rising from the tapping point to the instrument. However, when a flow meter is installed in liquid service the tappings should be taken from below the horizontal with the impulse lines falling towards the instrument.

Pressure equalising three-valve manifold blocks shall be used on close-coupled instruments and pressure/equalising five-valve blocks shall be used on remote mounted instruments.

If one flow measuring element is used for two independent measurements, four tappings shall be provided to obtain segregation. ie. If a control and ESD transmitter share the same measuring element.

For pipe sizes of DN 15 to DN 40 fabricated meter runs shall be used.

Transmitters with integral orifice assemblies in line sizes less than DN 15 shall not be used.

3.2.2 Meter Proving FacilitiesMeter proving facilities shall be provided for all flow meters used for custody transfer or fiscal measurements.

Where valves are used to redirect the flow through the meter prover, these should be tight shut-off (Class V or Class VI as per IEC 60534-4), arranged as ‘double block and bleed’ type and provided with facilities to check their tightness.

Where master meters are used, calibration facilities shall be available either at the Principal's site or from an authorised third party.

Piston type provers are not acceptable

Where small volume provers or conventional provers cannot be used or are not allowed by the local authorities, meter prover tanks shall be provided.

3.3 PRESSURE MEASUREMENT

Operating RangesRanges for pressure instruments should be approximately double the normal operating range. Suppressed zero ranges may be used for transmitters in control loops where necessary to ensure proper readability and control.

Pressure Transmitters (Including Differential Pressure Transmitters for Flow and Level)

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Except for simple local control loops where pneumatic transmitters may be considered with the consent of the Principal , transmitters shall be electronic and shall have an overall accuracy of better than + 0.5% of calibrated span. Repeatability should be 0.1% of calibrated span or less. Switching shall be carried out by the system, which is powering the transmitter.

Where the process fluid in impulse lines could freeze in the event of power loss to heat tracing, diaphragm and capillary seals may be used (with Principals consent) to remove the requirement for heat tracing. The seal flange shall be to the pipe rating and of the instrument manufacturer’s standard size, as per table 1.

Pressure Switches

Pressure switches shall be avoided wherever possible.

Pressure GaugesIndicating pressure gauges shall be of the heavy-duty precision type and shall be readable from deck or platform. Gauges shall have stainless steel movements. Dials shall be 100 mm diameter, white with black numerals.

Standard ranges should be used for all pressure gauges.

All cases shall be constructed of stainless steel and shall be of the safety pattern. All gauges shall be equipped with blow-out backs and shall be so installed that mounting arrangements do not prevent the functioning of the blow-out device. All gauges shall have heavy-duty shatterproof glass.

Pressure gauges for severely pulsating services shall have a helical gearless type movement with micro-range adjustment and dampener. Pressure gauges for applications subject to vibration shall be liquid filled and shall be equipped with a top filling plug. Particular care shall be taken in specifying liquid fill to prevent freezing in worst case ambient conditions.

Pressure gauges with diaphragm seals should be used for applications where general purpose gauges are not suitable due to corrosion plugging, etc.

Pressure gauges shall have ½ in NPT male threaded bottom connections. Receiver gauges shall have ¼ in NPT male connections.

Gauges should have an accuracy of better than +/- 1.0% of span including hysteresis, linearity and repeatability. This accuracy should be maintained after momentary over-pressure and cycling up to 1.25 times the maximum scale.

3.4 LEVEL MEASUREMENT

3.4.1 GeneralDepending on the process conditions level measurement by differential pressure, capacitance, admittance, radar, microwave, ultrasonic or displacer type instruments shall be used for control or remote transmission services.

External bridles (stand pipes) shall only be used where the number of connections to the vessel would be significantly reduced. Control instruments and ESD initiator instruments shall not be mounted on the same bridle. Where ESD initiator instruments are mounted on an external bridle, no isolation of the bridle from the vessel shall be possible.

Level connections, for both instruments or their bridles shall be made directly into the vessel. Connections into process pipework, inlet or outlet nozzles, cause errors in measurement and are not permitted.

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3.4.2 Level TransmittersDifferential pressure transmitters shall be the preferred method for level measurement. Diaphragm and capillary seals or flange-connected transmitters shall be used to remove the requirements for heat tracing of impulse lines. The seal flange shall be ANSI B16.5 to the vessel rating and of the instrument Manufacturer's standard size, normally 3 in. or 4 in.

For pressurised vessels, a pressure correction/compensation connection, (in accordance with Section 3.1), is required at a location on the vessel above the maximum operating liquid level.

Displacer chamber connections shall be as per table 1. The instrument head should be rotatable and where appropriate have insulation and/or a torque tube extension to the Manufacturer's recommendations dependent on operating temperature. Where there is a risk that sediment or sand might collect in the bottom of the displacer chamber connections shall be “side and bottom”.

Displacer ranges shall be 356 mm (14 in.) 813 mm (32 in.) or 1219 mm (48 in.). Accuracy shall be +/- 0.5% of calibrated span or better. Repeatability shall be 0.1% of calibrated span or less.

The location of all displacement-type instruments relative to the surrounding equipment and structure should be arranged to give adequate space above the instrument to allow easy removal and reinsertion of the displacer and its hanger.

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3.4.3 Level SwitchesLevel switches (float switches) shall be avoided wherever possible.

3.4.4 Level GaugesMagnetic level gauges are preferred and shall be provided in association with control and measurement instruments and where local indication only is required. Level gauge indication/visible length shall cover the complete operating range of levels, including the spans of level measurement and switching transmitters.

All fittings to level gauges shall normally be of stainless steel.

Glass level gauges shall only be used if magnetically coupled level gauges are unsuitable for the application. Glass level gauges if used should be of the transparent flat-glass type. The Tubular Pyrex glasses and reflex gauge glasses shall not be used.

In corrosive services special devices such as Kel-F coated glasses etc. should be applied.

Gauge glasses with frost protectors shall be used for process operating temperatures below 1°C.

Gauge glasses, when required shall be backlit with wedge-type gauge illuminators, giving an evenly diffused light over the entire length of the glass. These shall be certified for use in the relevant hazardous area zone.

Gauge isolation valves should be of the offset type with union bonnet. They shall be furnished with ball-type blow-out check units. Each level gauge shall be provided with a half-inch gate valve or a sleeve-packed plug cock for drainage and glass cleaning.Isolation gate valve stems shall have hand-wheel and quick-closing thread with double seated plunger to permit re-packing in service. Valve bodies shall be of forged steel with the plungers, seats, plugs stems etc. in AISI 316 stainless steel as a minimum.

The maximum centre-to-centre dimensions of process connections for glass level gauges shall be 1230 mm, incorporating 3 glass sections. If a longer range is required, a combination of multiple gauges should be made.

Multiple-gauge installations may be mounted on a dedicated “gauges-only” standpipe with block valves at the vessel only, except for interface gauges, which shall be connected directly to the vessel without standpipes.

3.4.5 Tank Gauging Systems for Product and Storage TanksThe use of a stilling well is recommended for all tanks with high accuracy level measurements requirements.

Tank gauges for custody transfer shall be of the radar type or the servo-motor operated (surface seeking) type, with remote checking facilities.Tank gauges for custody transfer shall have an approval certificate from an independent body, which is recognised by the authorities involved.

Servomotor operated type tank gauges for custody transfer shall be installed in the gauge pole. The gauge pole shall be installed in a perfectly vertical position.

Where the storage tanks require an averaging temperature detector, this shall form part of, and be connected to, the tank gauging system. The average temperature detectors shall be fixed multiple elements (resistance or thermocouple).

Where spot reading temperature detection is required, this shall be provided in the lower part of the tank. The temperature measuring device shall be a thermocouple or resistance element.

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3.5 TEMPERATURE MEASUREMENT

3.5.1 ThermowellsAll temperature detectors shall be installed in thermowells except bearing metal temperature detectors.

When operating constraints prevent selection of a suitable thermowell, application of surface mounted resistance thermometers or thermocouples shall be considered.

Thermowells used in copper-nickel piping in seawater service, shall be made of Monel or other suitable material in accordance with the project piping specification.

All process thermowells shall be the flanged type in accordance with Standard Drawings in Appendix A.

For application in large ducting, e.g. heating and ventilating or flue gas ducts, the thermowell may be an integral part of the thermocouple assembly in accordance with Standard Drawing in Appendix A.

Wake frequency calculations shall be provided for all thermowells located in piping.

The calculated vortex shedding frequency shall not exceed 80% of the natural frequency of the thermowell.

For high pressure service welded thermowells to Standard Drawings in Appendix A shall be provided.

Temperature points shall never be installed directly downstream of flashing or cavitating valves, due to the risk of breakage as a result of excessive vibration, nor directly upstream of flow meters requiring a straight length.

3.5.2 Electronic Temperature ElementsFor remote temperature indication, resistance temperature detectors (RTD) should be used. Resistance temperature detector (RTD) elements are preferred for measurements between –200°C to +500°C and shall be of platinum. The characteristic shall be in accordance with IEC 751, nominal resistance at 0 °C to be 100 Ohms with a fundamental interval of 38.5 Ohms.

Thermocouples should be of the mineral insulated, metal-sheathed type and be in accordance with EN 60584-1. For temperatures between +500°C and +1000°C, chromel-alumel [Type K] thermocouples shall be used. For temperatures above +1000°C, platinum-rhodium [Type R] thermocouples shall be used. Purchaser’s written approval is required for the use of thermocouples outside of these temperature ranges.

Where the temperature elements are measurement inputs to the supplier’s control system or IPS then local transmitters are not required for RTDs or thermocouples. However for all temperature elements that perform measurements for the Purchaser’s PCS or ESD, “smart” programmable head-mounted temperature transmitters shall be provided. Standard requirements for transmitters shall apply (i.e. fully-floating 4-20 mA output). Accuracy shall be 0.5% of temperature measurement span or better. Output signals shall be proportional to temperature, and not mV or resistance input.

Measuring elements shall be spring loaded within the head of the transmitter/termination chamber to ensure physical contact between the element and the thermowell tip.

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3.5.3 Pneumatic Temperature TransmittersPneumatic temperature transmitters shall only be used in local control loops where the use of electronic transmitters is impracticable and require the approval of the principal.

3.5.4 Temperature SwitchesExcept for ancillary services such as the control of electric heat tracing, anti-condensation heaters etc., direct-acting temperature switches shall not be used.

For process control or protection services, primary measurements shall be performed using an analogue transmitter with the switching being carried out by the PCS or ESD or by a package control or protection system.

3.5.5 Temperature GaugesFor local indication of temperature up to 400 °C, bi-metallic dial thermometers shall be supplied.

Temperature gauges shall be, ‘every angle’ type Dial with black characters on a white background, 316 stainless steel heavy-duty hermetically sealed, weatherproof to IP 66 as defined in IEC 60529.

Temperature gauges shall have an accuracy of +/- 1% of measurement span or better.

Ranges shall be selected from the following so that the normal operating temperature is between 50 to 75% of full scale:

-30 to +60 oC, 0 to 60 oC, 0 to 250 oC, 0 to 400 oC

3.6 PROCESS STREAM ANALYSERS

3.6.1 AnalysersProcess Stream Analysers will be completely automatic and will be purchased from suppliers as total systems.

On-line process stream analysers will include, but not be limited to, the following: moisture analysers for the outlet of the instrument air dryers and for the hydrocarbon

gas outlet of the glycol contactors. chromatograph and density analyser(s) for the pipeline flow measurement packages. Oil-in-water analysers for produced water services. BS&W analyser on crude oil export service. Vapour pressure analysers on crude oil and condensate service.

Process stream analysers will be equipped with manual sample points, for both laboratory testing and calibration sample injection.

Process stream analysers will in general be equipped with local indicators.

3.6.2 Analyser HousesThe main purpose of an analyser house is to ensure continuity of operation of analyser systems at a specified rate of reliability by providing a suitable operating environment for analysers which cannot otherwise operate properly, i.e. if exposed to outdoor, ambient conditions.

The operating environment may be affected by requirements concerning. area classification. environmental conditions, mainly temperature and humidity. sample handling and conditioning. effective maintenance.

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As analyser houses are complex and therefore expensive in both CAPEX and OPEX, they contribute significantly to the Total Cost Of Ownership. They should therefore only be erected when strictly required and their size shall be optimised.

In selecting the measurement methodology it shall therefore be borne in mind whether the required operating environment can only be provided by an analyser house.The suitability of cheaper alternatives, e.g. a walk-in shelter, shall be checked. The selection of either a walk-in shelter, a site-erected analyser house or a pre-fabricated analyser house (with all analyser systems installed) shall be evaluated in terms of Total Cost of Ownership.

Analyser houses shall be located in a non-hazardous area or a Zone 2 area. Analyser houses shall not be located in a Zone 0 area or a Zone 1 area.

Additional to the requirements of IEC 61285, the location: shall be at least 15 m away from furnaces. shall be such that the vibration level does not exceed that specified for the

equipment accommodated inside the analyser house. shall be free from spills of water and process liquids.

NOTE: Locations under pipe bridges or other structures should be avoided.

4. ACTUATED VALVES

4.1 CONTROL VALVES

4.1.1 GeneralControl valves with actuators and ancillary equipment, supplied as part of packaged units, shall be obtained from one of the control valve suppliers nominated for the project.

Control valve, process connections shall be in accordance with the relevant piping specification of the associated process pipework, but shall have a minimum flange rating of 300# for process service.

Valve body and trim materials shall, as a minimum, conform to the requirements of the respective piping materials specification.

Valve failure action shall be as defined on PEFS.

Unless otherwise specified or dictated by its application, the selection of a type of valve should be in the following order of preference:

Globe valve (linear motion) or Rotary valve (eccentric plug or segmented ball). Butterfly valve. Ball valve. Other types.

The required control valve characteristic should be obtained through a characterised trim. Control valve characteristics should generally be equal percentage, however in any of following cases, the control valve shall have a linear characteristic:

Level control. Compressor anti-surge control. Split range control. Where, for increasing the rangeability, two control valves are applied in parallel. Control valves that are only operated via a manual control station. Minimum flow protection for pumps.

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When split range is programmed within the PCS or other remote electronic system, the control valve may also have an equal percentage characteristic.

Due to the unavailability of an equal percentage characteristic for the miniature type of control valve, these types of control valves may have a linear characteristic.

On-off control valves should have a quick closing characteristic. Other characteristics may be required, such as modified equal percentage to avoid or reduce the consequences of pressure shock in the piping systems.Unless otherwise required, on-off and control valves used as a back-up emergency shut-off valve should be specified and installed as "flow-tending-to-close". For throttling control applications with unbalanced valves, the direction should be "flow-tending-to-open" in order to avoid a very large unstable force in the nearly closed position.

For angle valves, the direction should be "flow-tending-to-close" in order to avoid high velocity and turbulence in the valve body.

The calculated Cv value shall be in accordance with IEC 60534-2-1, with noise prediction calculation and testing in accordance with IEC 534-8. The Supplier shall provide control valve sizing and noise calculations for review by the Purchaser.

All control valves shall be sized to provide adequate rangeability in accordance with IEC 534-2-4.

Control valves should generally be sized to operate within the limits of 15% (minimum flowrate) and 85% (maximum flowrate) of maximum capacity. For normal flowrate control valves shall operate between 30% and 70% of maximum capacity.

If the calculated noise level of a standard control valve exceeds the allowable limits, a control valve with special low noise internals shall be selected. The maximum sound pressure level at 1 metre distance from continuously operating control valves shall not exceed 85 dBA. For intermittent emergency operations, e.g. equipment blowdown to flare, the allowable noise levels may be increased to 96 dBA. In such cases the valve equivalent noise level taken over an eight hour operating period shall not exceed the maximum continuous noise level. Only If, for technical or economic reasons, low noise valves are not practical, acoustic containment techniques may be applied.

Low noise restriction plate(s) downstream of the control valve shall be avoided.

If cavitation is predicted the first solution should be the re-design of the process. If this solution is not possible then hardened trim materials shall be applied and special anti-cavitation trims shall be provided. For applications where anti-cavitation trims are not available, two valves in series may also be considered.

4.1.2 Globe ValvesGlobe valves (linear motion, rotary/eccentric plug or rotary/segmented ball) shall be used for all services except where the allowable pressure drop is so low that a globe valve would not function.

Cage guided globe valves shall not be used for fluids that contain solid particles.

Throttling globe valves should not be used if a Class V or Class VI shut-off is required (as per IEC 534-4), as these shut-off classes cannot be maintained over a prolonged period. If a Class V or Class VI shut-off is required, a dedicated tight shut-off valve (i.e. ball valve) should be installed in series with the control valve. As this is an expensive solution, the requirement for these shut-off classes should be examined with care.

An exception is made for de-pressurising valves where, for safety reasons, two valves in series shall not be applied.

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When selecting three-way globe valves, special attention shall be paid to the Cv sizing of each flow path of the valve.

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4.1.3 Butterfly ValvesButterfly valves shall comply with the piping class and shall be considered for the following circumstances:

if the required size (usually due to high flow rate with a low pressure drop) would make it economically attractive or if it is impossible to apply globe valves.

for corrosive services, where body lining of globe valves becomes economically unattractive.

Spring-opening butterfly valves should not be of the wafer or lug type but should have a flanged valve body (in order to allow removal of the valve from the piping system). If a wafer or lug type butterfly valve is used, spool pieces (upstream and downstream) shall be fitted to permit removal of the valve.

To prevent tampering, the rotary intermediate linkages between a butterfly valve and its actuator shall be of the integral type, enclosed in a protective metal housing.

4.1.4 Ball ValvesBall valves shall be considered for on-off service. Unless equipped with a special trim, i.e. anti-cavitation or low-noise design, care should be taken with the selection of ball valves for high differential pressures.

Ball valves supplied with an actuator for remote on-off operation, shall comply with the piping class requirements for manual valves. The type of actuator shall be as specified for Shut-off valves in section 4.2.

Ball valves for use in erosive service etc. should be equipped with a scraper type of seat construction.

Ball valves should not be used in throttling service.

4.1.5 Self-Acting RegulatorsSelf-acting regulators shall only be considered for clean fluids in simple utility applications, such as pressure reducing, back pressure and temperature regulation (e.g. for reducing instrument air supply pressure or for gas blanketing of storage tanks).

Regulators in gas blanketing service shall be installed on the blanketing inlet connection of the relevant tank.

Special attention shall be given to the application of self-acting regulators, with internal, self-relieving capability.

For details of tank blanketing, refer to API 2000.

4.1.6 Control Valve BodiesNon-standard sizes of control valve bodies shall not be used on process duties, (e.g. 1¼”, 2½”, 5” & 7” NB) select from the range of pipe sizes listed in the piping specification.

Body size less than 1” shall not be used.

Control valve bodies shall not be fitted with bottom drain plugs. A bottom flange shall be provided for valves that require bottom access for trim removal.

Valve bonnets shall be of bolted construction with fully retained gaskets.

The face-to-face dimensions of flanged globe-body control valves shall be in accordance with IEC 534.

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4.1.7 Control Valve Packing MaterialsPacking materials should be:-

PTFE-based for non-hydrocarbon services with packing temperatures below 200oC; Graphite-based, metal-reinforced, fire-safe type for all hydrocarbon services and

non-hydrocarbon services with packing temperatures between 200oC and 600°C.

Packing shall not contain asbestos and external lubricators or grease nipples shall not be applied.Extended bonnets shall be provided, if required, to keep the temperature at the stuffing box at an acceptable value for the applied packing. An extended bonnet shall also be provided if the operating differential pressure across the valve could otherwise cause freezing of the stuffing box/packing and/or ice formation on the trim. For example, this may be the case for compressor recycle (anti-surge) valves or de-pressurisation valves. The stuffing box shall be on top of the extended bonnet and shall be provided with an adjustable, bolted gland flange and gland follower.

Bellows-sealed bonnets shall be applied where control valves are used in toxic gas services. The bellows shall be of AISI 316 type stainless steel, unless otherwise specified in the requisition. Bellows-sealed bonnets shall not be applied above ANSI rating class 300.

For bellows-sealed control valves an additional stuffing box with the appropriate packing material shall be included. For leak detection and venting purposes, the seal extension shall be provided with a screwed connection between the bellows seal and the packed gland.

4.1.8 Control Valve TrimsThe trim and particularly the seat ring(s) shall be of the replaceable type. All internal clearances shall be designed such that sticking cannot occur at minimum and maximum operating and ambient temperatures.

For trims, which are not of the one-piece type, the plug and stem construction shall be provided with a locking device to prevent accidental separation. The locking device may be either a special fluted pin, driven through a hole, which is simultaneously drilled in the plug guide section and stem, or it may be of a welded construction.

The seat-ring(s) should be clamped or backed-up via a seat ring retainer. Special attention shall be paid to fixing of the seat ring in order to prevent loosening due to vibration. Adhesive compounds shall not be used for the locking of seat rings.

Where soft (resilient) inserts are required for meeting the specified leakage rate, the inserts should be of glass-fibre-filled or graphite-filled PTFE; the selection shall be based on the suitability for the specified process conditions. The resilient insert shall be properly clamped between metal parts and/or locked in position to prevent blow-out in the closed position. For globe valves, soft seats can deteriorate quickly and should be avoided as far as possible.

Hardened (e.g. Stellite-coated) or solid Stellite closure member and seat rings shall be selected for the following applications:

Erosive services. Wet gas or steam service with a pressure drop greater than 5 bar. Other services in which the pressure drop is greater than 10 bar at design conditions.

For economic reasons, if suitable for the specified process conditions, hardened AISI 440C type stainless steel (Brinell hardness approximately 550) may be considered as an alternative trim material.

Angle valves for erosive services should be equipped with a chrome plated venturi seat ring, unless other materials are required for the process conditions.

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4.2 ACTUATED SHUT-OFF VALVES (INCL. ESD AND BLOW-DOWN VALVES)

4.2.1 GeneralShut-off valves shall be in accordance with the project piping class specification and tight shut-off (bubble tight at rated pressure) where specified to be tight shut-off ( TSO)

Valve actuators shall be either hydraulic or pneumatic spring return or double acting. In onshore locations where no instrument air supply is available electric or hydraulic actuators shall be used. The requirements of clauses 4.3 and 4.4 shall apply.

On the offshore facilities shutoff valves 10” and above shall be fitted with hydraulic actuators, shutoff valves below 10” shall be fitted with pneumatic actuators.

For onshore locations where an instrument air supply is not available electric, hydraulic or electro-hydraulic actuators will be used. Where hydraulic actuators are used a hydraulic accumulator will be provided with each actuator, an electro-hydraulic powerpack will be provided with each valve or group of valves. Electro-hydraulic actuators will be self-contained units comprising actuator, electric driven hydraulic pump, reservoir, accumulator and controls integrated into one unit of modular design. Solenoid valves may only be considered for applications in instrument air signal lines or on-off control in hydraulic utility services, such as the hydraulic control systems for well-head control panel logic units.

Valve Failure action shall be as defined on the PEFS.

ESD and Blow-down Valves shall use hydraulic or pneumatic actuators with spring return failure action.

ESD and Blow-down Valves shall be fire-safe. If the valve is located within a high fire risk area the actuator shall be either fire-safe or enclosed within a fire-safe enclosure.

Where shut-off valves are used as the final control elements for IPFs, the requirements of section 7.0 shall also apply.

For Shutdown applications the actuator shall be fail-safe and arranged such that in event of removal or loss of the control signal, the valve will be driven to the least hazardous (usually closed) position. This should be by spring return action. Where spring return actuators are not possible or practical, double acting actuators may be used to drive the valve to the safe position using lock-up valves and local hydraulic accumulators. See Actuated Valve Accessories section 4.4 for the requirements regarding local hydraulic accumulators. For General duty applications the actuator may stay-put in the event of removal or loss of the control signal.

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4.3 VALVE ACTUATORS

4.3.1 Actuator MaterialsThe materials of the actuator assembly including case, yoke, spring housing and gearbox shall be steel. Aluminium materials shall not be used in actuators. Brass or copper alloys may be used in non-exposed areas.

The actuators may be used in exposed locations in the offshore environment and will be subject to seawater deluge and hosing down. It is therefore essential that the actuators are designed such that the level of ingress protection is sufficient to prevent corrosion within the actuator, particularly on the spring, bearings, guides and cylinder surfaces. Actuators, including all field mounted ancillaries and junction boxes, shall be rated IP 65 to IEC 60529 (including prevention of entry to the actuator and ancillaries of fingers, hands, etc.).

The actuator spring shall be fully enclosed and permanently treated to resist atmospheric corrosion.

The diaphragm material shall be nylon-reinforced neoprene or Buna N rubber. Piston or cylinder actuators shall have O-ring sealing and shall be designed to minimise shaft and piston friction.

Protective compounds and durable coatings shall be used to prevent corrosion in the event of water condensing inside the various housings in addition to protection of external parts. For shutdown applications, the spring housing shall be hermetically sealed to prevent ingress of air or moisture and should contain preservative.Carbon steel parts should be painted in accordance with the Project Painting Specification. Where alternative equivalent painting systems are proposed, details of these shall be submitted for approval.

Nickel plating should be used for sealing surfaces and the inside surface of cylinders to provide resistance to wear and corrosion. The underlying surface material must be treated to provide corrosion resistance. Carbonising/Nitrating surface treatment processes may be used on internal parts such as piston rods, tie bars etc.

For General duty applications (i.e. non-shutdown applications) only, PTFE type coatings may also be used for the inside surface of air cylinders. The underlying surface material must be treated to provide corrosion resistance.

Local valve position shall be shown by a moving pointer attached to the valve stem/shaft and indicating on a fixed scale.

4.3.2 Control Valve Actuator & PositionerControl valve actuators should be pneumatic spring-opposed diaphragm or pneumatic spring-opposed short-stroke piston type.

The yoke shall be of the open type to allow access for adjustment of the packing gland follower.

Piston type actuators shall be provided with adjustable end-limit travel stops in both directions. Bolt adjustment type limit stops shall be applied with a locking facility, e.g. a locking nut, to prevent tampering. The construction shall be leak-tight, with seal gaskets.

For large high pressure control valves that require forces that are too great for diaphragm actuators, double-acting, spring less, piston actuators should be provided complete with lock-up valves and local instrument air receiver, to achieve the required action in the event of instrument air failure.

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Modulating control valves shall be fitted with electro-pneumatic SMART valve positioners (input signal 4 - 20 mA), unless otherwise requested in the requisition for a specific application. Positioners on valves used for simple regulatory control will be Foundation Fieldbus format. The positioner output action shall be direct, and shall not be provided with a bypass valve. The positioner shall have a weatherproof enclosure with a degree of protection of at least IP 65 in accordance with IEC 60529. The valve positioner shall have sufficient capacity in both directions for pressuring and venting the actuator to prevent response time limitations.

Where the combination of a separate electro-pneumatic converter and a pneumatic valve positioner is unavoidable, the output capability of the converter and the input required on the pneumatic valve positioner shall be checked in order to prevent possible instability.

Input, output and supply pressure gauges, graduated in Barg, shall be provided on the valve positioner and/or I/P converters. Valve positioners and I/Ps shall be provided with an identification plate, marked with air supply pressure and input signal.

The connection of the valve stem to the actuator stem shall be adjustable and shall allow positive locking of the adjustment. Actuators shall be equipped with a direct-coupled adjustable travel or position indicator for local status indication. The position shall be indicated by a permanent mark on a reversible scale with the words 'open' and 'shut' at the travel limits, or by unambiguous symbols such as:-

_ V _ = open –V– = closed.

4.3.3 Choke Valve ActuatorWellhead choke valves shall be fitted with electric motor driven actuators. The actuators shall incorporate a stem position transmitter (feed back to the PCS), a de-clutchable hand wheel, local open/stop/close push buttons and a local/remote selector.

Domestic gas take-off valves at Boatasyn shall be fitted with electric motor driven actuators. The actuators shall incorporate a stem position limit switches (feed back to the PCS), a de-clutchable hand wheel, local open/stop/close push buttons and a local/remote selector.

4.3.4 On/Off Valve ActuatorThe actuator internals shall be packed for life with suitable lubricants. However, access facilities shall be provided to allow inspection and re-packing of the actuator in-situ on the valve.

A pre-requisite of supply shall be that Shutdown Actuators offered for supply shall have been subjected to Comprehensive Type Tests carried out by the actuator manufacturer and witnessed independently, brief extracts are as follows:-

Design certification by an approved independent authority such as Lloyds. Spring visual, dye-penetrant examination and load tests before and after 10 cycles at

maximum torque. Cylinder pressure test at 1.5 times the maximum operating pressure for a minimum

of 6 hours. full-load performance test to measure and record the variation in Static Torque of the

actuator in both directions over the full curve. 6,000 cycle operational test under 95% load, = 3,000 cycles at -40°C, & 3,000 cycles

at +55°C. Repeat full-load performance test to measure and record the variation in Static

Torque of the actuator in both directions over the full curve. Stroke the actuator leaving the spring in the compressed position for 2 weeks. Repeat full-load performance test to measure and record the variation in Static

Torque of the actuator in both directions over the full curve.

Type approval is only required once to pre-qualify an actuator type. Re-qualification will only be required if significant design changes or extensions to the range have taken place.

One (or more) suppliers may be nominated as ¼-turn actuator supplier(s).

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4.3.5 Actuator SizingThe maximum process differential pressure for actuator sizing shall be taken to be the maximum upstream pressure, with the valve fully closed and the downstream pressure as atmospheric.As a minimum requirement actuators shall be sized to provide sufficient torque or thrust to hold in position and fully stroke the valve against the maximum process pressure differential, within the times specified, with an air supply of 4.2 barg or less. Sizing at instrument air pressures above 4.2 barg require the consent of the principal. Particular attention shall be paid to unbalanced dynamic forces on the valve plug. The actuator design shall be able to withstand the maximum instrument air supply pressure.

4.3.6 Actuator Torque RequirementFor rotary valves the torque available from the actuator at any point in the stroke shall be a minimum of 1.5 times the valve torque requirements to operate a new valve for both the spring closing and externally powered opening (or vice versa for fail-open applications) strokes including breakaway and process induced dynamic forces with the valve under maximum design differential pressure and at maximum design pressure. Minimum air supply pressure of 4.2 barg should be used for deriving actuator torque figures unless otherwise required. Actuators requiring an instrument air supply pressure above 4.2 barg shall not be used unless approved by the Principle.

Sheer torque capability for valve stem/shaft shall be 1.5 times the maximum torque.

Additionally, for shutdown applications, the actuator torque shall be a minimum of 1.5 times the torque required to close the new valve from the open position with the valve bore at the maximum operating pressure and with the valve cavity at atmospheric pressure.

Calculations of the maximum torque that could cause the shearing of the valve stem by the actuator shall be based on:

limit stops fully adjusted maximum air pressure (as achieved with the pressure relief valve fully open, i.e.

110% of relief valve set pressure). maximum spring force

This maximum "Shearing" torque shall not cause yield in any component of the actuator and drive train.

4.3.7 Stroking Times

4.3.7.1 Control ValvesFor control valves stroking time must suit the required speed of response for process control accuracy and stability.

Valves used for on/off service or control valves with a back-up trip function shall have stroking times as required for the individual application. In particular special care shall be taken for compressor anti-surge valves, with respect to the required fast stroking time. Where the stroking time requirements in any one direction cannot be met, a volume booster or a quick exhaust valve (subject to stability considerations) shall be employed. If air pressure is used, under emergency conditions, to close the valve or to assist the spring force, the size of the air signal line and fittings and the air capacity of the accessories shall be suitable to ensure the required stroking time.

4.3.7.2 Actuated Shut-Off Valves The maximum stroking times for the actuator/valve combination at the specified supply pressure range and ambient condition range are as follows:

Tripping One second per inch of nominal valve bore; Resetting Three seconds per inch of nominal valve bore.

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In order to avoid pipeline surge, speed control facilities may be provided to restrict the discharge of the operating medium from the actuator. These shall be arranged such that the risk of causing blockage of the flow of operating medium from the actuator shall be minimised. Mechanisms that are integral to the cylinder are preferred to external ones.

4.3.8 Actuator to Valve MountingThe actuator mounting on the valve shall not cause excessive stress on the valve stem arrangement. Any requirement for additional supporting of the actuator other than that provided by the valve adapter shall be clearly identified. The control system shall be directly mounted on the valve where practicable. Where this is not practicable a freestanding control system shall be provided for installation adjacent to the valve.

The arrangements for fitting the actuator to the valve shall be such that the operating torque is transmitted to the valve without any distortion, over stressing or slipping of the coupling, mountings or bolting. Any extension pieces, spool pieces or adapters required to fit the actuator to the valve shall be fully enclosed and fitted with pressure relief facilities to prevent over pressure in the event of stem seal leakage. Valve and actuator assemblies for cold service (e.g. blow down) may require extended bonnets to ensure the actuator remains within it’s design temperature limits.

The design shall prevent leakage from the diaphragm/piston from over pressurising the adjoining actuator body or spring housing.

The allowable stresses on the valve flange, flange bolts and the valve stem shall be specified by the valve manufacturer.

4.4 ACTUATED VALVE ACCESSORIES

4.4.1 HandwheelsActuated valves will only be provided with a handwheel when indicated on the PEFS. If a handwheel is provided, the following are the minimum requirements:

The handwheel shall be provided with position indicators. The operating force shall not exceed 200 N on the rim of the handwheel. The transfer from actuator operation to handwheel operation shall be possible in all

stem positions. The handwheel should be de-clutchable, side mounted type with a clearly marked

neutral position. An instruction plate, explaining how the declutching facility is used, shall be fitted to the actuator.

4.4.2 Limit StopsLimit stops shall be mechanical devices mounted on the actuator, but they shall not form part of the handwheel mechanism (if provided).

To prevent tampering, the limit stops shall be fitted with a locking facility, e.g. a locking nut and shall be protected against unintentional adjustments

4.4.2.1 Control ValvesLimit stops, where fitted, shall be indicated on the flowsheets. Adjustable limit stops shall not be used to restrict the throughput of the valve in order to limit the capacity of downstream relief valves.

Where fitted, limit stops shall be screwed bolt-type, e.g. on the actuator stem, adjustable over the full length of the stroke. Bolts screwed in the body shall not be used as a limit stop.

4.4.2.2 Actuated Shut-Off Valves Adjustable limit stops shall be fitted to the actuator. Limit stops shall be adjustable by a minimum of ±2.5° at both the 0° and 90° positions. Limit stops shall be field adjustable without dismantling the actuator from the valve.

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4.4.3 Air Supply Filters & RegulatorsAir filters shall be installed in the supply lines to the individual actuators in order to protect the actuator from entrained abrasive particles and moisture in the air supply

Air filter regulators shall be installed in the supply lines to the solenoid valves; positioners and/or I/P converters, in order to filter and regulate the instrument air supply pressure.

The make of filter regulator shall be as specified in the requisition.

The air filter shall be fitted with a drainage facility.

The air filter regulators shall be of the reducing-relief valve type, with drainage facility and bolt adjustment provided with a locking facility, e.g. a locking nut, to prevent tampering.

The air filter cartridges shall be of the rigid structure type to resist channelling, rupturing, shrinkage or distortion and shall have a maximum mesh size of 20 m.

The capability, e.g. output capacity and required spring range, of the filter-regulator shall be checked against the instrument air requirement of the particular positioner and/or I/P.

The actuator Manufacturer/Supplier shall specify the air consumption and the air filter requirements for the elements that are supplied with the valve.

Glass (bowl-type) filter regulators shall not be used.

4.4.4 Actuator Lifting EyesWhere necessary, the actuator shall be fitted with suitably located lifting eyes. The Supplier is to confirm that these are suitable for mounting and de-mounting the actuator in-situ with the specified valve orientation. Where fitted a minimum of two and a configuration providing redundancy is required. In addition, where specified, additional lifting eyes shall be provided on the spring cans to allow the removal of these with the actuator on the valve in the position specified.

4.4.5 Pressure GaugesPressure gauges shall be provided as follows :-

incoming supply actuator control supply all regulated pressures in the control system.

Pressure gauges shall be in accordance with section 3.3, except they may be reduced to 50 mm diameter dial.

4.4.6 Limit SwitchesActuators for shutdown valves and on-off control valves shall be fitted with a minimum of two limit switches, one at the fully open position and one at the fully closed, plus any other intermediate positions as required for valve test purposes. Modulating control valve limit switches shall be fitted only as necessary and should be indicated on the PEFS.

The switches shall be such that the closed limit switch circuit is closed when the valve is in the closed position and the open limit switch is open circuit and visa versa when the valve is fully open. Each end of travel switch shall operate within 3% of the end of travel (open or closed) and additionally, any intermediate position switch shall be adjustable by 10%. All position switches shall be repeatable to 0.5%. Mechanical protection (preferably by mounting inside a box), shall be fitted to prevent any disturbance/malfunction of the limit switches caused by inadvertent impingement of portable tools and equipment. The switches shall be of the proximity type, rated IP 66 to IEC 60529 and suitable for use in the hazardous area classification specified.

The mounting instructions supplied by the limit switch manufacturer shall be applied by the valve manufacturer.

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4.4.7 Solenoid ValvesSolenoid valves shall only be considered for applications in instrument air signal lines or on-off control in hydraulic utility services, such as the hydraulic control systems for wellhead control panel logic units.

Solenoid valves installed in hazardous areas shall be EEx (d) certified (I.S. solenoid valves are not acceptable). Normal operation shall be via normally energised solenoid valves driven via 24V dc. coils. On loss of signal, the actuator spring shall drive the valve to its fail-safe position.

Solenoid valve manufacturer and type are to be approved by the Purchaser.

Solenoid valves activated as part of a trip system (IPF), shall be provided with a local manual reset facility. The solenoid valve reset facility shall consist of a field reset enable pushbutton, located adjacent to the solenoid valve, together with field inputs returning to a healthy state will allow the operator to perform unit and individual logic resets. The field reset enable push buttons will be provided for logically grouped sections of the plant and will be located in suitable areas such that the process operator can visually verify plant safety prior to operating the field reset enable push button. After local reset has been achieved the CCR operator can reset the ESD logic and bring the plant back on-line in an orderly and safe manner.

Solenoid valves for general or control service shall be auto reset.Solenoid valves shall be provided with a disc and/or seat of resilient material to give a tight shut-off feature. They should be suitable for installing on a mounting plate. The air passages in the solenoid valves shall be large enough to achieve the opening or closing time of the valve as stated in the requisition. If this would lead to unrealistically large passages and consequently high power consumption of the solenoid valve, consideration should be given to the use of quick exhaust valves.

The capability of the solenoid valve (e.g. capacity, pressure rating) shall be checked against the instrument air requirement of the particular actuator.

The minimum port size in the solenoid valve shall be stated by the manufacturer and this shall be taken into account for the stroking time calculations.

Solenoid valves shall be without exhaust port protectors but, to prevent plugging (e.g. during freezing periods), shall be provided with a piece of tubing bent downwards with the end cut off at an angle of 45 degrees.

All electrical cable entries shall be M20 x 1.5 mm ISO (female) and connections shall be by screw terminals. Flying leads should be avoided wherever possible. Solenoid valves with flying leads shall be provided with a separate junction box for termination of the leads and, if not armoured, the flying leads shall be protected by a flexible conduit. The junction box shall be compatible with the electrical hazardous area classification of the solenoid valve.

To prevent high voltage induction, solenoid valves operating on direct current shall be provided with anti-surge diodes.

For emergency shut-off valves, the solenoid valve shall be installed directly on the valve actuator.

For control valves with a valve positioner, the solenoid valve shall be installed between the positioner output and the actuator.

Solenoid valves shall be direct operated; in-pilot operated solenoid valves are not allowed.

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4.4.8 Quick Exhaust Valves & Volume BoostersQuick exhaust valves and volume boosters may be provided for services, which require to operate faster than is achievable with the standard accessories.

Pilot-operated, quick-exhaust valves shall not be used.

The minimum port sizes shall be taken into account for stroking time calculations.

Quick exhaust valves shall be installed without port protectors but, to prevent plugging (e.g. during freezing periods), shall be provided with a piece of tubing, bent downwards, with the end cut off at an angle of 45 degrees.

Quick exhaust valves shall be fitted directly to the port of the actuator.

Volume boosters shall be provided if needed to achieve the stroking times specified in the requisition. Volume boosters for pneumatic actuators shall be of the high capacity type with fast throttling facilities to control the required capacity.

4.4.9 Lock-up Valves & Local Instrument Air ReceiversLock-up valves (a snap acting valve which seals in the instrument air pressure to the actuator/receiver if the supply falls below a predetermined value) shall have a bolt adjustment provided with a locking facility, e.g. a locking nut, to prevent unintentional adjustments. A separate nameplate shall be provided to indicate the range and the set values.

The lock-up valves shall be set at a value above the minimum air supply pressure required by the valve actuator bearing in mind the capacity limitations of the local air receiver.

The lock-up valve shall be installed between the positioner output and the actuator. If lock-up valves are applied on valves operated by a solenoid valve, this solenoid valve shall be installed between the lock-up valve and the actuator.

4.4.10 Local Instrument Air Receivers & Hydraulic AccumulatorsThe local instrument air receiver or hydraulic accumulator shall be sized to maintain sufficient supply pressure at the actuator controls to allow for at least three full valve strokes (ie. one open, one close, one open for a fail to close valve) within 30 minutes.

The local instrument air receiver capacity shall be sized consistent with operating and minimum pressures as stated in section 2.3

The hydraulic accumulator capacity shall be sized for a starting pressure of 200g barg and a minimum pressure of 160 barg.

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5 PRESSURE RELIEF VALVES

5.1 GENERAL

The selection, sizing and design of relief valves or rupture discs shall be in accordance with API RP 520, API RP 521. A Data Sheet shall be prepared for each safety relief valve, giving all the process data required to properly size and select the valve, construction and physical size. The data sheet shall also indicate other relevant factors where applicable, e.g. possible solids formation, dangerous fluids, fluctuating back pressure, mixed-phase flow etc.

Relief valves, both conventional, balanced bellows and pilot operated types, shall be supplied in accordance with API 526.

Calculation sheets shall be provided for each safety relief valve. Noise calculations for each safety relief valve in dBA at full lift shall also be submitted. The sound pressure level at 1 metre distance from the safety relief valve shall not exceed 110 dBA.

Relief devices in gas or vapour service should normally be connected to either the vessel vapour space or the outlet piping.

If part of a system containing a liquid can be blocked in by valves and the internal pressure can rise above the maximum allowable working pressure of the piping system due to ambient influences, a thermal expansion relief valve shall be provided.

All relief valves shall be accessible from deck level or a permanent platform.

Isolation valves shall be fitted where spare relief valves are installed, and their lock key release system shall be such that pressure relief protection is provided at all times. When pressure relief valves are fitted with isolation valves, these shall be of full bore type, be indicated on P & I diagrams and appropriately identified with either the symbol 'LO' (Locked Open) or 'LC' (Locked Closed) and their status, i.e. open or closed, shall be clearly evident from visual inspection.

Piping for relief valves shall be arranged to avoid pockets. Piping on the exhaust side of relief devices shall be designed or braced to ensure that exhaust reaction loads or moments do not exceed that specified by the relief valve Manufacturer. The outlet line from a relief valve shall be self-draining.

The inlet flange rating shall match the inlet process piping specification. Outlet connections shall be suitable for the design pressure and temperature conditions of the downstream pipework; outlet flanges shall be ANSI Class 150# minimum rating.Vent pipe must not allow backpressure build up due to liquid accumulation.

Valves shall be of the enclosed spring type. Where bonnets are vented to atmosphere, a screen and/or shield shall be fitted to prevent the ingress of dirt, moisture or foreign objects.

Safety relief valve seats shall normally be metal to metal. Where a tighter shut-off is required, the use of elastomeric seals suitable for the service conditions may be considered. All soft seats shall be renewable. Metal to metal seats shall be of ample proportions, so as to permit several lapping or re-machining operations. For high temperature applications in excess of 200°C, metal-to-metal seats shall be used. For high pressure drop applications in excess of 70 bar, stellited trim shall be used.

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5.2 CONVENTIONAL AND BALANCED BELLOWS RELIEF VALVES

Conventional relief valves are to be used for most duties because of their relative simplicity and reliability.

Conventional relief valves shall be in accordance with "direct spring-loaded" valves as specified in API 526.

Valves shall be full nozzle type, so that the nozzle and seat are the only parts in contact with the process fluid when the valve is closed.

A balanced bellows may be specified as an addition to a conventional relief valve. This device isolates the spring, bonnet space and internals from the inlet and outlet fluid. Where fluctuating imposed back pressure is possible, or where built up backpressure may exceed 10% of set pressure, a balancing bellows shall be used. It may also be specified to prevent corrosive, dirty or hazardous fluids contacting the valve top works, or leaking to atmosphere.

Where a balanced bellows is fitted, the bonnet shall be vented, either locally or to safelocation depending on the nature of the fluid. Means shall be provided to monitor theintegrity of the bellows. In cases where bellows failure would cause a dangerous conditiondue to backpressure as described above, a balancing piston shall also be specified. Thisfunctions as a back-up device to the bellows and ensures proper valve operation in the event of bellows failure.

5.3 PILOT OPERATED RELIEF VALVES

Pilot operated relief valves provide a tighter closure than conventional valves and may be considered where the operating pressure is greater than 90% of set pressure where conventional valves might experience seat leakage. Because of possible problems with blockage of the small-bore pilot valve or tubing, their use shall only be considered in clean dry gas service.

These valves shall be generally in accordance with API 526. Non-standard valves may be considered on an individual basis for special applications.

In the event of failure of the pilot valve system, the main valve shall still open at an increased over-pressure.

The preferred configuration for pilot piping shall be pickup from a connection on the main valve inlet, and discharge to a connection on the main valve outlet. The Supplier shall review the backpressure conditions and advise where the pilot valve discharge piping should route to atmosphere for satisfactory main valve operation. If atmospheric discharge is essential, the Supplier shall advise the fluid volume which would be vented under relieving conditions.

Pilot operated safety relief valves shall be constructed to provide a facility for tamper proof sealing, preferably by wiring of screw cap and body on the pilot valve and lead sealing, to ensure setting integrity.

Pilot valves shall be of the non-flowing type, and shall be spring loaded and soft seated where the temperature permits. All materials shall be compatible with the process fluid. Pilot tube and fittings shall be stainless steel and shall be 12 mm O.D. minimum. Fittings shall be twin-ferrule compression type. Flared tube fittings shall not be used.

5.4 SMALL RELIEF VALVES

Small safety relief valves having inlet sizes of 3/4" or below shall only be used for very low flow applications, such as thermal relief of liquid inventories or protection of small air receivers or positive displacement pumps. Inlet and outlet connections may be threaded, where permitted under the piping specifications, for non-hazardous services, but shall be flanged for all process or hazardous fluids.

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These valves are not covered by any national standard for constructional details. Full supplier drawings and parts lists shall be provided for each individual valve. Capacity certification shall be to ASME requirements, or to other equivalent national.

Fixed blow-down type may be used where the operating pressure is less than 75% of set pressure. For higher operating pressures, adjustable blow-down shall be provided.

In normal operating mode i.e. valve closed, the only valve parts contacting the fluid shall be of stainless steel type 316 or better to meet process requirements.

The maximum orifice size for this type of valve shall be 71 sq. mm.

5.5 RUPTURE DISCS

Rupture discs will only be used where quick reaction time and large capacity discharge is required. However, where applied, rupture disks subject to vacuum as well as to pressure will be reverse buckling type with vacuum supports. All rupture discs installations shall be fitted with leak and rupture detection and alarm facilities.

Rupture disks will not be installed in series with safety valves.

5.6 MATERIALS (ADDITIONAL REQUIREMENTS FOR RELIEF VALVES)

Materials of construction for major components shall be specified on the data sheet for review by the Purchaser before order placement.

Care must be taken in specifying the materials for safety relief valves subjected to temperatures below 0°C. The low temperature may be as a result of process conditions or caused by pressure drop through the safety relief valve.

Relief valve springs shall be manufactured from corrosion resistant alloys, suitable for the specified service and environmental conditions. Plated or painted carbon steel springs are not acceptable. For all hydrocarbon services springs shall have Type 3.1.B (minimum) material certification to DIN 50049.

An ASME code stamp is not required, but capacities of valves shall be certified by the manufacturer using the methods outlined in ASME code section VIII and API 520.

Valves to be dry before packing for shipment.

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6. SHUTDOWN PHILOSOPHY AND HIERARCHYFor details of the Philosophy and Hierarchy refer to:

Offshore 3400-T-61-30-S-4033-00 Safety Systems Philosophy

OPF & Booster Stn 1 6000-P-60-04-S-7001-1 Emergency Shutdown and Emergency Depressurisation Philosophy

Booster Stn 2 5200-Y-90-04-T-7008-00 BS#2 General Safety Design Concept

Gas Distribution 5300-Y-90-04-S-7001-00 GD Safety Specification

OET 5500-Y-90-04-T-7008-00 OET General Safety Design Concept

7. CONTROL AND SAFETY SYSTEM ARCHITECTUREThe facilities will include a number of interconnected control and monitoring systems:

Integrated Control and Safety System (ICSS) comprising subsystems:Process Control System (PCS)Emergency Shutdown System (ESD)Fire & Gas System (F&G)High Integrity Pressure Protection System (HIPPS)

Electrical Switchgear/Motor Control Centres Unit Control Panels - Equipment Dedicated (See Section 9.0) Local Control Panels (See Section 10.0) Rotating Equipment Monitoring and Data Acquisition System (See Section 7.7)

The major elements of the control systems shall be interconnected to the CCR through the communications network.

The PCS shall be used as the main control system for the platform, with the operators in the CCR supervising all process and utility controls.

The CCR shall be provided with operator control consoles, which shall house the Control and Safety System VDUs and their associated keyboards for platform displays and controls including PCS, ESD, F&G, electrical switchgear/MCC status and third party package equipment systems. The man machine interface in the CCR will be further augmented by report and event printers.

The design of control and safety systems shall take into account the potential failure modes of equipment and shall, wherever practical, ensure that equipment "fails safe". In addition the design shall identify all common mode failure points and, where practical, these shall be eliminated.

The ICSS controlling communications network shall be fully dual redundant and diversely routed throughout and capable of single network failure survival. For package equipment UCPs that interface to the ICSS the preferred communication is Ethernet, where the Supplier is unable to provide this then the alternative is via serial links. Where control and or ESD data or status is transmitted dual redundant links shall be used. Where only non-critical indication or status is transmitted a simplex redundant link may be used. The supplier shall arrange the data registers in a compacted form so as to maximise the efficiency/performance of the data transfer interface. Data message designs shall minimise the number of transactions required for the ICSS to gather data.

The interface between the electrical power management system, switchgear/MCCs and the PCS for monitoring and status displays shall be via serial links.

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The ICSS TCP/IP monitoring communications network shall be duplex and shall provide terminal facilities and allow the sharing of peripheral devices such as report printers, event printers, etc., by third party, supplier package equipment (see Section 10). In addition all data and displays available at the supplier’s control panel shall be available at the ICSS control console. This communication shall be via Ethernet Transmission Control Protocol/Internet Protocol (TCP/IP). All hardware and software required to remotely access this data for display on a remote PC based Windows NT workstation shall be supplied by the supplier:

Hardware Ethernet Board or built-in connection. Software Software Driver for TCP/IP, compatible with Windows NT.

The allocation of TCP/IP addresses will be agreed with the ICSS systems supplier.

TCP/IP is a layered set of protocols. The standardisation of the protocol across all its layers, including those that provide terminal emulation and file transfer, allows different makes of computing equipment to exist and communicate with each other on the same cable.

7.1 PROCESS CONTROL SYSTEM (PCS)

The PCS consoles will be used by the operators to monitor and control process and utility facilities plus equipment packages, including sequencing, start up, including starting or stopping motors, adjustment of control settings and the monitoring of major equipment.

The ICSS will provide the operator with all the necessary interfaces to efficiently and safely operate the process and utilities from the CCR. The interfaces will include but not be limited to:

Alarm Annunciation (including repeats of ESD/F&G events) Monitoring of variables Supervisory control & monitoring of equipment. Control and monitoring of process, utility and heating, ventilating and air conditioning

systems.

The operator will be able to execute all normal control operations from ICSS operator control console, including starting and stopping motors, adjustment of control settings and the monitoring of main equipment.

Typically the following operations are NOT foreseen as being executed from the ICSS operator control console:

Main Power Generator Gas Turbine run-up sequencing & combustion controls and Generator synchronisation sequences & electrical controls (executed from the UCP). Facilities should be provided in the UCP to allow the remote initiation of the starting, stopping and auto-synchronisation sequences by the ICSS.

Gas Export and LP/MP Compressor starting & Anti-Surge control (executed from the UCP). Facilities shall be provided in the UCP to allow for remote start permissives and the remote initiation of the starting and stopping sequences by the ICSS.

Throughput of the compressor packages will be regulated by the package control to maintain a set point provided by the ICSS. Future control of the load sharing between compressors shall be by the package control system.

The PCS will display machinery monitoring data for all rotating equipment packages at the ICSS operator consoles. The PCS will transmit all rotating equipment package related operating and process data (i.e. process pressures, temperatures, etc.) to the Rotating Equipment Monitoring and Data Acquisition System. Machinery monitoring data (vibration, axial displacement, etc.) will be transmitted direct from the monitors to the Rotating Equipment Monitoring and Data Acquisition System via a single Ethernet link

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7.2 HVAC CONTROLS

7.2.1 HVAC ControlsControl of the HVAC shall be performed by the ICSS specifically the PCS, or, in the case of onshore facilities, a dedicated HVAC panel in each building and shall be responsible for the control and monitoring of the following :

Fans. Heaters. HVAC Control Dampers Pressure Dampers Humidity

7.2.3 Fire & Gas Tight DampersFire & Gas Tight Dampers shall be controlled directly by the F&G System and position indication shall be provided in the CCR via the ICSS operator console.

7.3 EMERGENCY SHUTDOWN SYSTEM (ESD)

The ESD System is essential to meeting the Safety requirements of the installation.

The equipment package protection and shutdown system will be either contained within a package UCP or within the ESD, as defined in the package requisition.

SIL 1,2 and 3 will be implemented within the ESD system. The F&G system may also be required to implement SIL 1, 2 and 3 functions.

The ESD System will use 'fail safe' technology. Loss of power, system failure or malfunction will result in shutdown.

Reliability is a prime requirement of trip systems. Every effort shall be made to ensure that the system functions correctly and is free from spurious shutdowns. Nevertheless, each component of a trip system shall be incorporated in such a way that the system will go to the 'safe' position in the case of a component failure.

The ESD system will also provide all control of blow-down valves. The control facilities being located on the operator interface in the CCR.

Initiating devices for, and Emergency Shutdown & Blow-down valves activated by, the ESD System shall be dedicated only to that service.

IPS hardware and system software, versions and releases, shall be evaluated and certified by TUV.

IPF reviews shall be conducted as necessary during the IPS life cycle in accordance with the Facility IPF Management plan, IPF Classification, Implementation and Test interval Studies.

IPS maximum cycle time shall be 300 ms.

All measurement devices, trip initiating contacts and circuitry logic systems and final trip actuating circuits and devices (including actuated valves) for SIL 1, 2 & 3 shall be hardwired and completely separate from the normal control and alarm systems.

All components of a trip system shall be energised under normal operating conditions and the contacts of initiating devices shall be closed under normal operating conditions. Open contact or loss of power shall result in the system going to a 'safe' position.

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The ESD System will be provided with centralised monitoring facilities and the means to perform executive actions, apply and remove inhibits and overrides from the operator console in the CCR. Indication of individual override status will be provided in the CCR on the operator console. A means will be provided in the CCR to remove all overrides for an entire system or a plant area in an emergency situation by the use of a single push-button or keyswitch.

The ESD System shutdown logic will contain start-up override facilities, which will be initiated from the CCR and will be reset automatically when the quiescent process condition is reached within a pre-set time. Should the normal operating condition not be met in the time period then the shutdown action will occur for that specified abnormal condition.

Cause-and-effect diagrams shall be prepared to define the requirements for shutdown of the process and utility systems when abnormal conditions occur.

The trip system shall use either the uninterruptible single-phase ac or, if available, the dc supply.

Outputs for solenoid valves or switchgear relays shall be hermetically sealed with gold-plated contacts rated for 2.0A at 30V dc. Relay coils shall be fitted with surge suppression diodes. If metal can type relays are used, the cans shall be earthed.

Where justified by the number of inputs/outputs and/or the complexity of the logic system, either of the following techniques may be considered:

Systems which incorporate self-checking logic and which utilise hard-wired solid-state circuits

A programmable logic controller (PLC).

In all cases each input shall have a conditioning unit to provide filtering and to eliminate spurious initiation due to contact bounce or other short-duration intermittent/transient conditions. A trip initiation shall not be executed until the input signal (opening contact) has been present for at least 50 milliseconds. Longer delays may be provided to avoid spurious trips due to transient conditions.

Variable time delay relays may be provided in the input circuitry for those monitored conditions, which do not result in a dangerous situation when the abnormal state is of a short duration. The setting of the time delay shall match the characteristics of the process.

7.3.1 Operator/Maintenance Facilities

In addition to the general facilities for the automatic operation of trip systems a number of special facilities may be required for operational or maintenance purposes. The requirements for these special facilities are dependent on the type of equipment being protected.

Operational FacilitiesTypically these facilities will include start-up bypasses, manual trips, manual reset, etc.

Start-up bypass shall be applied only to the inputs affected by the specific process/equipment condition, all other channels being left fully operational. The start-up bypass shall automatically cancel when the process/equipment condition becomes normal or after a time delay that will be set in value to match the characteristic of the process/equipment condition being monitored. The operation of the start-up bypass shall be displayed at ICSS consoles.

Manual tripping switches shall be of the mechanically latching push-and-turn type reset with indication and protection to prevent accidental operation e.g. flap-guards.

Systems or equipment simply requiring an ICSS "permit to start" may be reset remotely and the system shall be designed to accept a remote reset command signal.

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Maintenance FacilitiesTypically these facilities will include maintenance over-rides, on-stream testing, etc.

Except when the alternative arrangement of three independent voted channels is provided or shutting down the protected unit does not adversely impact the availability of the facility, maintenance override facilities shall be provided for all process inputs except manual trips on an individual basis to allow on-stream testing, maintenance on the input circuitry and/or re-adjustment of the set-point.

Overrides shall be applied by activating the shutdown unit maintenance override permissive keyswitch after which the maintenance override can be set from the ICSS workstation. For packages with stand-alone shudown systems the override facilities will be at the UCP. Removal of the maintenance override permissive keyswitch will remove all overrides for that shutdown unit.

Actuation of the maintenance override shall only defeat the trip function being maintained and not the associated alarm or any other trip. Indication of of switch and bypassed element status shall be displayed at the ICSS consoles (and UCP).

All components of a trip system shall be capable of being tested 'in-situ'. Except for the final shutdown device(s), facilities shall be provided to enable all the components to be tested without shutting the package down.

Partial closure testing of ESD valves will be achieved as follows:

Each ESD shutdown unit will have a test permissive keyswitch which when activated will allow the operator to select a valve for test via the ICSS operator workstation. Selection of a valve will set the relevant ESD logic to the valve test mode. The test is activated by a push button located in the field adjacent to the valve. On completion of the test, which is logged on the PCS, the operator will de-select the valve that has been tested & remove the keyswitch permissive.

7.3.2 I/O Card Status DiodesTypically colours of Light Emitting Diodes (LEDs) shall be as follows:

Description Status WarningInput signal status Red Input is abnormal/tripStart-up bypass Amber Input is bypassedLine fault Red Fault on input circuitComputer input/logic output Red Computer/Logic faultRelay status Green Relay in normal operating stateSupply available Amber Supply voltage healthyOverride On Red Override switch in override positionTripped/abnormal Red Input/Output in tripped stateHealthy/normal Green Input/Output in healthy state

A LED test facility shall be provided.

7.3.3 Final Control ElementsTrip functions shall, as appropriate, operate shutdown valves installed in the appropriate process or utility piping (via a suitable solenoid valve) or shut down electric equipment (via interposing relays to the motor starter circuit).

Each solenoid valve shall be separately fused and have surge suppression diodes fitted across the coil.

Modulating control valves shall not be used for shutdown purposes . However an additional measure of safety may be provided by tripping a modulating control valve in addition to operating the emergency valve to meet SIL 2 requirements.

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7.4 HIGH INTEGRITY PRESSURE PROTECTION SYSTEM (HIPPS)

Where it is identified that a High Integrity Pressure Protection System (HIPPS) is required it shall comprise of an instrumented system independent of the alarm and trip system, provided to isolate the piping and equipment from a pressure source.

HIPPS systems shall be designed “fail safe” such that the system will revert to a pre-determined safe state in the event of a failure of any part of the system. These include:

Loss of power to any of the components Break or rupture of instrument air piping or cabling Loss of hydraulic pressure Failure of 2 channels in a 2oo3 arrangement or failure of 1 channel in a 1oo2

arrangement

Each HIPPS shall be functionally separate from any other safeguarding system but may be interfaced with the PCS via digital communication links. Malfunction of these communications links shall not affect the safety integrity of the system.

The use of dedicated maintenance and/or operational overrides is not permitted. For 2ooN (N>2) voting systems, maintenance/testing of one channel should be interpreted by the system as that channel being in the trip mode.

Signals from HIPPS field devices and other safety systems shall not be combined into common multicore cables. Dedicated field cables from HIPPS field devices shall be directly terminated on the HIPPS control cubicle/cabinet and shall not be routed via a common marshalling facility.

Diversity of components is required within each HIPPS to alleviate the possibility of common failures resulting in unavailability of the system. Typically transmitters will be from the same vendor but valves, solenoid valves etc. will be from different vendors.

The system integrity of the HIPPS is directly related to the design test frequency of the total system. Functional testing of the system is therefore required to verify and maintain the system integrity and to detect normally unrevealed failures.

Reliability and Availability calculations shall be produced for each separate HIPPS.

7.5 ALARM & ANNUNCIATION SYSTEMS

Alarm annunciation system input circuits shall be normally energised, i.e. input contacts go to open-circuit to initiate an alarm.

Alarm sequences will be in accordance with ISA S18-1

The output circuitry for operating the audible alarm shall be by means of a relay with double-pole contacts suitable for an inductive load of 0.4A at 230V ac. or 4A at 24V dc.

7.5.1 Operating SequencesThe following sequences shall be used for alarm displays:

Alarm only: Code F2A in ISA S18-1 Alarm with first-up facilities: Code F3A in ISA S18-1

7.5.2 Lamp/Window Colours Alarm Amber Trip Red Switch in override position Amber Valve open, motor running Green Valve closed, motor stopped Yellow Permissive Blue Spare Window White

7.6 FIRE AND GAS CONTROL SYSTEM (F&G)

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All areas of each facility will be monitored by a fire and gas detection system. This system will provide warnings to defined control points and will automatically raise specific alarm warnings. In defined cases the F&G System will activate protective systems; i.e. fire water deluge, and initiate equipment shutdowns via the ESD System.

The F&G Control System will be capable of monitoring and initiating protection systems either automatically or manually:

The F&G Control System will be capable of monitoring the following F&G detecting devices: Gas Detectors Heat Detectors Smoke Detectors Flame Detectors Manual Call Points

The F&G Control System will report and display, via the ICSS operator consoles, the status and any alarm signals from the F&G detection and protection systems and gas concentrations, on a fire zone basis, including monitoring the equipment for fault conditions. Reporting will discriminate between single and two or more detections.

The F&G Control System will initiate the following protection systems either automatically or manually:

Extinguishant Release Fire Pumps Electrical Isolation via ESD System Process Shutdown via ESD System Status Lights and GPA Alarms via Telecoms Fire dampers.

The F&G Control System will interface with the ESD System to initiate the following actions: Process Shutdown Levels Equipment Shutdowns Electrical Isolations.

Inhibits and overrides on the F&G systems will be performed from the CCR. Individual override status will be provided at the ICSS operator console.

The number, type and location of fire and gas detectors used for fire zone will take into account the types of combustible material, hazardous area status, operating performance, speed of response and the environmental conditions as well as existing operational experience and the requirements for maintenance and calibration.

Manual alarm call points shall be provided throughout the platforms to initiate alarms.

To minimise compatibility problems between the sensors and the input cards, the detectors that interface to the main Fire and Gas system will be provided by the F&G system supplier and free-issued to the package supplier for mounting and cabling to the skid marshalling box. Typically these will be the sensors that monitor the internal air spaces & equipment of acoustic or weatherproof enclosures and/or their ventilation systems plus the combustion air intake sensors. Additionally the system will monitor the status of associated self-contained systems, which use their own dedicated detectors, such as those used for turbine protection and fire pumps.

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For further details refer to facility specific Fire & Gas System Design Philosophy.

7.7 ROTATING EQUIPMENT MONITORING AND DATA ACQUISITION

Rotating equipment packages will each be provided with a Machinery Condition Monitoring System, which will interface to a Rotating Equipment Monitoring and Data Acquisition System at each facility. Each facility system will in turn interface with a project wide system. Machinery monitoring requirements and interfaces are defined in specification: 1000-S-90-37-S-4024-00 ‘Specification for Rotating Machinery Monitoring Equipment.

8. TELECOMMUNICATIONSThe project telecommunications systems requirements are defined in specifications:1000-S-74-71-S-5002 Telecommunications Systems Specification’.

9. WELLHEAD CONTROL SYSTEMThe Wellhead Control Systems (WCS) will provide stand-alone control of the Production Wing Valves (PWVs), Upper Master Valves (SSVs) and Sub-Surface Safety Valves (SSSVs).

Each WCS will comprise stainless steel wellhead control panels, with pneumatic and hydraulic controls, plus hydraulic power packs. Also included will be wellhead pressure measurement, sand probes on producing wells, plus interfaces to both the relevant PCS/PSD and ESD systems for well status and well shutdown commands. The wellhead control panels will be located in the Wellbay Area.

Wellhead control panels will use a retractable drawer type system, to allow flexible allocation of well slots. Each drawer unit will control an individual well. Removable blanking plates will be included to cover unused drawers. The physical arrangement of each WCS, with respect to using one combined panel or several separate panels, will be decided during the Project Definition phase.

It is currently envisaged that all the wellhead valves and Sub-Surface Safety Valves will be hydraulically actuated. Motive power for these valves will be derived from dual redundant electric or pneumatically driven hydraulic pumps. Additional backup will be provided from a hand driven hydraulic pump.

The Wellhead control panels will be equipped with electric space heaters, to help prevent freezing of the pneumatic circuits. In addition, electric heaters will be fitted to the hydraulic oil tanks, to help prevent high viscosity effects, particularly after prolonged shutdown and during a black start.

Hydraulic oil selection and wellhead control system design will take into account both the low ambient temperatures and both the high and low down-hole temperatures likely to be experienced.

Each flow line will be fitted with a sand probe, connected to the PCS/PSD.

Various wellhead control system alarms and status signals will be transmitted to the PCS. Fault monitoring of various key parameters will be provided

10. PACKAGED EQUIPMENT CONTROL PANELS

10.1 UNIT CONTROL PANELS

The Unit Control Panel (UCP) for each package shall include all the machine control functions, start-up and shutdown logic, condition monitoring equipment and machine

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protective systems. The Gas Compressor UCPs shall also include their anti-surge controllers master performance controller and provision for future load sharing.

UCP’s shall typically be connected to the ICSS by three levels of interface : Hardwired Signals - Trips, Critical Controls, Permissives and Interlocks. Duplex/Simplex Serial Signals - Operational data and alarms. TCP/IP Network Data - Functional Interface to UCP (generally read only). See 7.0

above.

The ICSS shall interface with other systems via either “Open” interfaces supporting DDE and OPC (OLE for Process Control) or Serial Links.

The ICSS shall utilise all interfaces in simplex or dual configurations as required to gather data from the UCPs to enable the CCR Operator to view all necessary indications and equipment status to effectively monitor and control the equipment.

The ICSS shall utilise the TCP/IP network connections to the UCPs to enable the CCR operator to view detailed status of the UCP. This interface shall enable the Operator to gain the functionality of the local UCP System and provide for supervision, control and monitoring facilities at the CCR.

The UCPs shall time tag data at source and, where practical, this shall be to the same resolution as the ICSS. First up alarm indication shall also be provided.

Each UCP shall be connected to the ESD via hardwired links, to enable the machine to be shutdown as required by the Shutdown Philosophy.

If the machine has its own stand-alone F&G system, this shall be connected via hardwired signals to the platform F&G for monitoring and control action purposes.

Each UCP shall be fitted with anti-condensation heaters.

11. LOCAL CONTROL PANELSThe use of Local Control Panels (LCP’s) shall be strictly limited in the design to those items of equipment, which are required to be autonomous or for which a degree of local control is desirable. Such a panel could be for a valve with local test facilities or wellhead controls.

The main equipment having LCP’s shall be the Fire Pumps, Emergency Power Generator and Air Compressor. These have to offer complete autonomy both for emergency conditions and for a black start of the platform. This equipment may therefore be started locally and operated without reliance on the ICSS.

Where a local panel is required for grouping together a number of local instruments or simple controls the following requirements shall apply.

Each local panel shall be fitted with anti-condensation heaters and internal lighting.

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12. PANEL CONSTRUCTION

12.1 GENERAL

Panels shall be completely piped, wired, assembled and furnished complete with all necessary instruments, nameplates, switches, push-buttons, lights, terminals, supports, trunking, supply distribution, extension cords, etc.

Panels shall be fitted with internal lighting and thermostatically controlled heaters.

Panels, which may be located in areas subjected to water-mist fire,deluge or CO2 protection, shall be weatherproof to IP 65 as defined by IEC 60529.

Panels, cabinets or consoles located in equipment rooms (MER / FAR / LER) and CCR which have a controlled HVAC environment shall be IP 42.

Unless otherwise agreed, local panels shall be mounted on the package base in such a location and in such a manner as to provide operation and maintenance access to all items mounted on the panel and also not to interfere with maintenance access to other equipment in the package.

There shall be no direct process connections to enclosed instrument panels.

Locations of panels and controls to be agreed with the Purchaser.

Electric cable and pneumatic tubing between skid-mounted junction boxes and remote-mounted panels will be supplied by the Purchaser.

Cable entry for skid mounted local panels shall be through the bottom.

Cable entry for Unit Control Panels installed in the MER (Offshore) or LER (Onshore) will be defined in the package requisition.

12.2 EQUIPMENT ROOM LAYOUT

The arrangement and location of panels located in the main equipment room shall ensure access to all other adjacent panels and equipment, also that opening a panel door does not impede safe access to, nor obstruct safety or escape routes.

12.3 MECHANICAL

Skid mounted panels shall be constructed from stainless steel to AISI 316 for all parts except internal secondary structures, which may be to AISI 304.

Panels located in the equipment rooms may be offered in pre-galvanised mild steel, finished with the Supplier's standard offshore paint scheme, for the Purchaser's consideration at the tender stage. External finish colour shall be Light Grey (RAL 7032). Internal finish colour shall be Matt White.

Panels located in the equipment room shall be a maximum of 800mm deep. If the panel is formed from a number of cabinets bolted together they shall be assembled on to one common plinth and shipped as one assembly.

Plastic type components manufactured from flame-retardant, non-hygroscopic, non-tracking materials may be offered for minor supports and internal secondary structures.

Each panel or cabinet shall be equipped with a minimum of two lifting eyes, certified for lifting weights in excess of the final assembly.

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All panel assemblies shall be provided with anti-vibration mountings at all attachment points to the floor, wall, skid etc.

Panels shall be rear and/or front access via hinged doors, as defined in the package requisition.

Panel sections up to 800 mm wide should have a single hinged door. The width of the door shall not exceed 750 mm. Enclosures wider than 800 mm shall have multiple doors each a maximum of 750 mm wide. Doors shall have heavy-duty type non-galling 316, or better, stainless steel lift-off hinges and latches.

All internal components of control panels shall be securely mounted and fixed to prevent damage during shipment and installation and, to minimise vibration in service. Internal tubing shall be neatly dressed and supported in electrically insulating stand-off clamps.

Instruments and related equipment shall be installed in such a way that they are easily accessible for maintenance adjustment, removal or replacement. Type numbers and other markings shall be clearly visible from both front and back.

Any instruments with direct connections to process fluids should be grouped in a separate panel, located on the package skid. However, a panel with a separate compartment may be provided subject to Purchaser approval. Piping to these instruments shall not traverse the other compartment(s) of the panel.

The Supplier shall group the connections to the panel into process, pneumatic, hydraulic, electric power, electric control and intrinsically safe connections.

12.4 ELECTRICAL

The Supplier shall supply all sundries and install and wire all electrical equipment, instrumentation and accessories. The instrument panel shall be complete and ready for site connection to power, earthing and in/ out-going field cables.

If required the panel will be provided with two 100% rated 230V ac power supplies from the facilities secure electrical supply system. Means of isolating each individual incoming power supply shall be provided. The switches shall be of two pole, padlockable type and shall be placed within the panel enclosure. Should the Supplier’s equipment require other voltage levels, the panel shall be provided with dual redundant power supplies and all power distribution and sub-circuit over-current protection.

Identification sleeves shall be fitted to each end of all wiring runs and shall be inscribed with the instrument tag number and terminal number.

All terminations shall be of the crimped-pin type utilising a proprietary crimping tool acceptable to the Purchaser; except where instruments are provided with screw-type terminals when the wire ends shall be provided with crimped-on spade lugs.

Only one core shall be terminated in a terminal. Where more than one core requires terminating propriety comb type links inserted on the panel side of the terminal strip shall be used.

Removable blank gland plates shall be provided for incoming and outgoing field cables. Cable clamps shall be supplied for the support of field and interconnecting cables. Where screwed entries are required they shall be threaded ISO 1.5 mm (size to be confirmed at drawing approval size). 25% spare capacity shall be supplied for all entries into terminal boxes, gland plates and clamps. The detachable un-drilled gland plates provided for the Purchaser's cable shall be designed such that they may be detached and drilled on site without disconnection of any Supplier cabling.

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All screens and spare cores shall be connected at terminals and provision shall be made for the termination of all spare cores in Purchaser’s interconnecting multicore cables. There shall be 25% spare terminals in excess of this requirement.

Panels shall be furnished with "Klippon" terminals, type SAKR or equal. 25% spare capacity shall be provided. Terminal strips and blocks shall be in single layers. Suitable removable link terminals shall be provided where linking is necessary. Looping wire shall not be used for this purpose.

A copper grounding bar of minimum cross-sectional area 75 mm2 shall be provided for the ac supply system. Suitable straps minimum of 2.5 mm2 cross-section shall be provided for earthing the doors. A similar separate grounding bar arrangement is required for dc and for signal circuits; these bars shall be electrically isolated from panel metal work.

External connectors for the Purchaser's ground connection shall be provided by the panel Supplier and dimensioned to take 10 mm2 bare stranded copper cable through a solderless connection.

All instrumentation specified to be grounded in the loop diagrams shall be connected to the grounding bar by direct wiring from the instrument terminal.

Intrinsically safe circuits, wiring, terminals, interface units, grounding and power supply units, shall be grouped together on a separate terminal rail. A mechanical barrier shall be provided between intrinsically safe and other electrical equipment.

All wiring shall be separated by duty and by voltage level. The respective terminal blocks shall be similarly grouped.

Intrinsically safe wiring, trunking and terminals shall be coloured blue.

Panel internal wiring should be run in trunking of flame retardant, non-hygroscopic, non-tracking material, flame-retardant materials may be substituted if suitable flame-retardant trunking is not obtainable. Ducts should have slotted sides with plain 'snap-on' covers and be sized to allow 50% additional cable. Power cables shall be suitably identified and segregated from signal cables. Wiring from trunking to instruments should be neatly run and clipped together using plastic strapping or plastic covered clips. Metallic cleats are not acceptable.

All internal cabling shall use flame-retardant, low-smoke, zero-halogen insulation materials.

Terminals carrying voltages higher than 48 Volts shall be protected against accidental contact with removable cover plates and be labelled to indicate high voltage.

13. INSTALLATION

13.1 INSTRUMENT INSTALLATION

The installation of instrumentation and associated equipment shall comply with the relevant sections of API RP 551.

Instruments, local instrument panels and gauge boards, and their connecting lines and cables, shall be so arranged as not to interfere with access to, or maintenance of, the process equipment and shall be protected from mechanical damage.

All field-mounted instrumentation, including junction boxes and in-line equipment, shall be accessible from a permanent access point. Indicating (and recording) instruments should be mounted at approximately 1350 mm above grade or walkway level shall be visible from a convenient location.

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Instruments shall be located as near to the point of measurement as practicable and mounted generally on instrument stands or brackets. Where convenient, on lines of 3-inch nominal size or larger, which are not subject to vibration, the instrument brackets may be supported from the line. On smaller lines, the instruments shall be separately supported from the base-frame on local gauge boards/or racks. Pressure gauges, where used, may be line mounted.

Instrument locations shall be selected to minimise the effects of vibration from adjacent equipment.

Where conditions prevent local mounting due to inaccessibility or high process vibration, lines shall be run to avoid mutual contact with plant and structure. Tubing clamps shall be of electrically insulating materials. Tubing in excess of 1000 mm in length should be supported every 1000 mm.

Care shall be taken to avoid the possibility of corrosion being caused by the interaction of dissimilar metals.

Drain and Vent points on all in-line equipment shall be provided with a blind flange. Screwed plugs are not acceptable on hydrocarbon services and may only be fitted on utility services where permitted under the piping specification.

Drain and Vent points on expanding gate and double block & bleed (DB&B) valves shall be provided with a valve where DB&B isolation is being provided.

For threaded connections the following shall apply: Threaded pipe shall have a minimum wall thickness of Sch.80 for sizes up to 2 in

NB, and Schedule 40 for 3 in and 4 in NB; All threads shall be NPT tapered unless otherwise agreed by the Purchaser, and

shall be clean cut and concentric with the OD of the pipe. Female thread ends shall be de-burred by reaming;

Threaded joints shall be thoroughly cleaned, PTFE (Teflon) paste applied to the male thread and the joint made up tight.

Threads shall not be seal-welded;

Fasteners Studbolts shall be used in preference to capscrews or bolts wherever possible. Studbolts and nuts shall be cadmium plated. Threads shall be liberally coated with Dow Molycote 1000 thread lubricant.

Alternative lubricants shall not be used unless approved by the Purchaser. Fasteners shall be tightened with torque wrenches on all hydrocarbon piping

systems, and utility systems of 300# rating and above. Fasteners shall be tightened to the minimum bolt stress required to achieve gasket

seating loads and the gasket stress required to retain design and hydro-test pressures.

Fasteners shall be tightened evenly, and in as close to a diametrically opposite sequence as possible, to apply uniform stress on the gasket and to avoid distortion or over-stressing of the gasket, flanges or bolts.

All field-mounted junction boxes shall be rated IP 65 to IEC 60529 and certified EEx e IIB, T3 as a minimum. Cable entries shall be in the bottom; upward facing cable entries shall not be used. Junction boxes shall be furnished with "Klippon" terminals, type SAKR or equal. 25% spare capacity shall be provided. Terminal strips and blocks shall be in single layers. Suitable removable link terminals shall be provided where linking is necessary. Looping wire shall not be used for this purpose.

Electronic instruments shall be fitted with an integral junction box having screwed terminals with cable entries screwed 20 mm ISO pitch 1.5.

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Segregation shall be maintained between intrinsically safe signal cables, other signal cables and electrical power supply/control cables and their junction boxes. All intrinsically safe signal cables shall be blue sheathed. Minimum segregation between electrical power cables and instrument cables when running in parallel shall be 500 mm.

All instrument cabling should conform to the Electrical Requirements for Cables, but in any event shall use flame-retardant, low-smoke, low-halogen insulation materials.

Emergency stop push-buttons shall be sited to avoid accidental operation, whilst remaining accessible from platform, deck or walkway.

13.2 HEAT TRACING & INSULATION

Instrumentation shall be suitably protected from the process and the environment. Heat tracing and/or insulation shall be applied as appropriate.Heat tracing shall be of the self-regulating type with sufficient rating to be able to heat impulse lines and instrument bodies to the minimum operating temperature from minimum ambient temperature prior to a plant start-up.

Where heat tracing is applied, attention should be paid to the following points: The tracing shall be so arranged that the instrument can be readily removed without

disturbing the tracing. Heating of (long) impulse lines of differential pressure instruments shall be such that

both legs are maintained at the same temperature. Insulation shall be applied over all items to be heated without the risk of overheating

the instrument.

Electrical heat tracing shall be selected, designed and installed in accordance with the Electrical Requirements for Cabling.

Heated enclosures shall be provided for instruments mounted in external areas.

14. INSPECTION AND TESTINGThe following inspections and tests, as a minimum, may be witnessed by Purchaser and/or his representatives, and shall be performed at an agreed time and location.

14.1 INSPECTION

All individual items of instrumentation and associated equipment shall inspected at the manufacturer's works. The associated documentation shall be submitted and approved prior to inspection.

Supplier shall perform all necessary ongoing inspection activities in accordance with the approved Supplier Quality Plan.

The Purchaser's Inspector shall perform the following inspection checks, as required : Verify against approved documents that all items have been supplied and assembled

correctly. Check equipment for accessibility for operation and maintenance. Check appearance, paintwork, dimensions and fixing points against final agreed

drawings. Verify that all cables are correctly terminated and that cable / terminal markers and

nameplates correspond to the documentation. Verify that calibration certificates / certification for all applicable instrumentation

equipment is available in accordance with Project specifications and requirements.

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Verify that hydrostatic pressure test, seat leakage, torque, material, MPI and hazardous area certificates / certification for all applicable instrumentation equipment, including impulse lines, is available in accordance with Project specifications and requirements.

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14.2 CASTING AND WELD TESTING AND INSPECTION

The Purchaser reserves the right to inspect visually all pressure containing components prior to assembly. Any component may be subjected to dye-penetrant or magnetic inspection at Purchaser's discretion:

All welds used for pressure retaining purpose shall be 100% radiographed. All butt-weld zones shall be 100% magnetic particle or ultrasonically inspected over

a width of 50 mm on both sides before welding. Sealing areas within the actuator body shall be completely inspected. Magnetic

particle methods are preferred, although dye-penetrate methods may be used. Pressure retaining castings e.g. valve bodies, actuator cylinders for ratings 2500#

ASME and above shall be subject to 100% Radiography. This shall only be carried out on 5% of the total number (minimum 1 off) of the same type and size manufactured from the same cast, in the critical areas as specified in ANSI B16.34.

MPI and Dye-Penetrant shall be carried out on the mounting boss of actuator gearbox housing.

Springs for major ESD valve actuators shall be completely inspected by dye-penetrant examination

Inspection Standards:ASTM E94 Recommended practice for radiographic testing shall be the procedure used

for radiography for all structural welding and pressurised castings. All radiographs shall be proved by ASTM E446.

ASTM E446 Reference radiographs for steel castings up to 2 in. (51 mm) in thickness. Defects in Categories A, B or C shall not exceed the severity level of Class 2. Defects in Categories D, E, F or G are not permitted at all.

ASTM E709 Practice for magnetic particle examination for all pressure retaining and torque transmitting steel parts and weld undercuts. No surface discontinuities shall be allowed.

ASTM E165 Recommended practice for liquid penetrant inspection method on all castings. No surface discontinuities shall be allowed.

ASTM A609 Specification for longitudinal-beam ultrasonic inspection for carbon and low-alloy steel castings on all pressure retaining and torque transmitting steel parts. The minimum level of acceptance shall be Quality 1.

14.3 FUNCTIONAL TESTING

14.3.1 InstrumentsAll individual items of instruments and valves and associated equipment shall be subjected to a full function and/or calibration test to an approved test procedure prior to dispatch from the suppliers works. Witnessing of these tests by the Purchaser or a representative shall be at the Purchasers discretion

14.3.2 Local Control PanelsFor local control panels a static wiring check and if practicable a function test shall be performed against an approved Test Specification and documentation. This shall include as a minimum, power & earthing system checks for continuity and isolation/insulation integrity and point to point wiring checks.

14.3.3 Plant InstallationInstalled Instruments, valves, associated equipment, cabling, tube and fittings shall be subjected to the following checks and inspection prior to commencement of pre-commissioning activities:

Verify instrument locations against Instrument layout drawings. Verify that all cables are correctly terminated and that cable / terminal markers and

cable markers correspond to the drawings. Check equipment for accessibility for operation and maintenance. Verify that all impulse tube, pipe and fittings are correctly installed and correspond to

the drawings.

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Conduct soapy water test on all pneumatic tube installations.

14.4 VALVES AND ACTUATORS

The actuator shall be inspected visually to ensure that the general engineering and paint finish is satisfactory and that lubricants and corrosion protection have been applied correctly. Should it be necessary to complete this inspection prior to final assembly of the actuator the Supplier shall be required to notify the Purchaser a minimum of one week in advance.

Before assembly of major ESD valve actuators the spring force of each individual spring can shall be measured and recorded at the open and closed position. This shall be used forperformance monitoring over the actuator's life, therefore each spring housing will require aunique serial number. This number shall be recorded on the test certificates.

Test requirements will be specified in the requisition and as a minimum will include the following:

14.4.1 Actuator testingThe following tests shall be carried out by the actuator manufacturer and witnessed by the Purchaser.

Cycle Tests Static Torque Curve Test Pressure Test (1.5 times maximum supply pressure)

14.4.2 Actuator/Valve Assembly Tests & InspectionsThe complete valve, actuator and control system shall be witnessed function tested. Function Tests shall include:a) Speed of opening with maximum and minimum supply pressure.b) Speed of closing under spring load (or with max. and min. supply pressure for non

spring return actuators).c) Leakage tests on controls and actuator.

Stall test to demonstrate that with the valve jammed the maximum actuator output does not damage the stem and drive train.

14.5 RELIEF VALVES

All relief valves shall be tested for seat tightness in full accordance with API 527, and the results of such tests shall form part of the certification requirements. For gas, vapour and air service, the test medium shall be air. For liquid service, the test medium shall be water. Where the configuration of the valve precludes tests to API 527, the supplier shall formally propose alternative testing procedures for acceptance by the Purchaser.

14.6 QA REQUIREMENTS

Suppliers will be requested to provide details of their QA systems and procedures when responding to the enquiry requisition.

The specific QA and documentation requirements for each instrument will be defined in the enquiry and purchase requisition and will include, as a minimum where applicable, drawings, data sheets, schedules, passports, C of G, calculations, test data, manuals, hazardous area and material certificates.

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15. INSTRUMENT SYSTEMS TYPICAL BLOCK DIAGRAM

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PROCESS CONTROL

SYSTEM

EMERGENCY SHUTDOWN

SYSTEM

FIRE & GAS SYSTEM

MCC

MAJOR MECHANICAL PACKAGES

MINOR MECHANICAL PACKAGES

INSTRUMENT PACKAGES

FIELD INSTRUMENTS

TELECOMMUNICATIONS BACK-BONE

PIPELINE LEAKAGE SYSTEM

FLOW MEASUREMENTS

Hard Wired Serial Link Fieldbus

ROTATING EQUIPMENT MONITORING AND DATA ACQUISITION

SYSTEM

SCADA SYSTEM


APPENDIX A

Standard Drawings:

Drawing Number Drawing Title

1000-S-90-30-D-4001-01 Instrument Name Plates

1000-S-90-35-D-4001-01 Thermometer Assemblies for Mounting in Thermowells

1000-S-90-35-D-4003-01 Bi-metallic Thermometer Assembly

1000-S-90-35-D-4002-01 Thermometer Assemblies for Surface Mounting

1000-S-90-32-D-4002-01 Square Edge Flow metering Orifice Plates for ANSI B 16.36 RF Orifice Flanges

1000-S-90-30-D-4002-01 Purge Orifice Nipple

1000-S-90-35-D-4006-01 Flanged Thermowell DN40 for ASME Classes Up To 1500 Incl.

1000-S-90-35-D-4007-01 Flanged Thermowell DN40 for ASME Classes Up To 900 Incl.

1000-S-90-32-D-4001-01 Restriction Orifice Plates for ANSI B 16.36 RF Orifice Flanges

1000-S-90-35-D-4008-01 Flanged Thermowell DN50 for ASME Classes up to 2500 Incl.

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APPENDIX B

STANDARDS AND CODES OF PRACTICE APPLICABLE TO INSTRUMENTS- For Comprehensive Standards Listing refer to 1000-S-90-01-P-0003-00 (BOD)

Number Title

American Gas Association

AGA 9 Measurement of Gas – Ultrasonic Meters

American National Standards Institute

ANSI 16.5 Pipe flanges and Flanged Fittings

ANSI B16.34 Valves, Flanged, Threaded and Welding End

ANSI/ASME B40.1 Gauges - Pressure Indicating Dial Type - Elastic Element

ANSI/ASME B46.1 Surface finish for Flanges

ANSI/FCI 70.2. Quality Control Standard for Control Valve Seat Leakage

ANSI/ISA S84.01 Application of Safety Instrument Systems for the Process Industries

American Petroleum InstituteAPI (MPMS) (Chapter 3.3)

Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Pressurized Storage

API (MPMS) (Chapter 4.2)

Conventional Pipe Provers


Measurement of Liquid Hydrocarbons by Turbine Meters


Accessory Equipment for Liquid Meters


Lease Automatic Custody Transfer Systems


Pipeline Metering Systems

API (MPMS) (Chapter 14)

Natural Gas Fluids Measurement

API 6A Specification for Wellhead and Christmas tree equipment

API RP 7 Recommended Practice for Design and Installation of Electrical Systems for Offshore Production Platforms

API RP 14C Recommended Practice for Analysis, Design, Installation, and Testing of Basic Safety Systems for Offshore Production Platforms (Sixth Edition, March 1998)

API RP 14FRecommended Practice for Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Division 1 and Division 2 Locations (Fourth Edition)

API 17D Subsea Wellhead & Christmas Tree Equipment,

API RP 520 Recommended Practice for Sizing, Selection, and Installation of Pressure-Relieving Devices in Refineries, Sizing and Selection, Sixth Edition

API RP 521 Recommended Practice for Pressure-Relieving and Depressurizing Systems, Fourth Edition

API RP 526 Flanged Steel Pressure Relief Valves

API RP 527 Commercial Seat Tightness of Safety Relief Valves with Metal to Metal Seat

API RP 551 Process Measurement Instrumentation

API RP 552 Transmission Systems First Edition

API RP 553 Refinery Control Valves First Edition

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APPENDIX B continued

STANDARDS AND CODES OF PRACTICE APPLICABLE TO INSTRUMENTS

Number Title

American Petroleum Institute continued ….

API RP 554 Process Instrumentation and Control First Edition

API RP 555 Process Analyzers First Edition

API RP 556 Instrumentation and Control Systems for Fired Heaters and Steam Generators First Edition

API 598 Testing and Inspection of Valves

API 670 Vibration, Axial-Position, and Bearing Temperature Monitoring Systems, Third Edition

API 2000 Venting Atmospheric and Low Pressure Storage Tanks:

API Publ. 2031 Combustible Gas Detector Systems and Environmental and Factors Influencing Their Performance

American Society of Mechanical Engineers

ASME PTC 19.3 Part 3. ASME PTC (Performance Test Code), Temperature Measurement

American Society for Testing and Materials Standards

ASTM A 269 Standard Specification for seamless and Welded Austenitic SS Tubing

Canadian Standards Authority

CSA C22.2 No.3 M1985Test methods for electrical wires and cables

Shell DEPs

DEP 32.80.10.10 Classification and implementation of instrumented protective functions

European Standards

EN 10204 Metallic Products - Types of inspection documents

EN 54 Part 1 Components of Automatic Fire Detection Systems - Introduction

EN 54 Part 5 Heat Sensitive Detectors – Point Detectors Containing a Static Element

EN 54 Part 7 Point Type Smoke DetectorsEN 50054 (Superseded) by EN 61779-1) Instruments for the Detection of Combustible Gasses

EN 50057 (Superseded by EN 61779 –4) Performance Requirements for Apparatus for the Detection of Combustible Gasses

International Electro Technical Committee

IEC 60534-2-1 Flow-capacity – Sizing equations for fluid flow under installed conditions

IEC 60534-2-4 Flow capacity – Section Four – Inherent flow characteristics and rangeability

IEC 60534-4 Inspection and routine testing

IEC 60534-8-3 Noise considerations – Control valve aerodynamic noise prediction method

IEC 60534-8-4 Control valve hydrodynamic noise prediction method

IEC 60584 - 1 Thermocouples, Reference Tables

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STANDARDS AND CODES OF PRACTICE APPLICABLE TO INSTRUMENTS

Number Title

International Electro Technical Committee continued ….

IEC 60584 - 2 Thermocouples, Tolerances

IEC 60584 - 3 Thermocouples, Extension and Compensating Cables

IEC 60751 Industrial platinum resistance thermometer sensors

IEC 60793 Optical Fibres Product

IEC 60794 Optical Fibres General Specification

IEC 92-375 General Control and Communication Cables

IEC 60034 Rotating electrical machines

IEC 60079 Electrical apparatus for explosive gas atmospheres.

IEC 60079 Part 1 Construction and verification test of flameproof enclosures of electrical apparatus

IEC 60079 Part 2 Electrical apparatus, type of protection ‘p’

IEC 60079 Part 7 Increased safety ‘e’

IEC 60079 Part 10 Classification of hazardous areas

IEC 60079 Part 11 Intrinsic safety ‘i’

IEC 60079 Part 14 Electrical installations in hazardous areas

IEC 60079 Part 15 Electrical apparatus with type of protection ‘n’

IEC 60079 Part 18 Encapsulation ‘m’IEC 60092 Parts 301 thru 390 Cables (construction, testing and installations)

IEC 60331 Tests for electric cables under fire conditions – circuit integrity

IEC 60331 Part 11 Apparatus – Fire alone at a flame temperature of at least 750 o C

IEC 60331 Part 23 Procedures and requirements – Electric data cables

IEC 60332 Tests on electric cables under fire conditions

IEC 60332 Part 1 Test on a single vertical insulated wire or cable

IEC 60332 Part 2 Test on a single small vertical insulated copper wire or cable

IEC 60332 Part 3 Tests on bunched wires or cables

IEC 60529 Degrees of protection provided by enclosures (IP Code)

IEC 60617 Graphical symbols for diagrams.

IEC 60751 Industrial Platinum Resistance Thermometer Sensors

IEC 61000-6-2 Electromagnetic compatibility (EMC) – Part 6-2: Generic standards – Immunity for industrial environments

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STANDARDS AND CODES OF PRACTICE APPLICABLE TO INSTRUMENTSNumber Title

International Electro Technical Committee continued ….

IEC 61000-6-4 Electromagnetic compatibility (EMC) – Part 6: Generic standards – Section 4: Emission standard for industrial environments

IEC 61131-3 Programmable Controllers – Part 3: Programming Languages

IEC 61508 Functional safety of electrical/electronic/programmable electronic safety – related systems

IEEE Standards Local Area Networks

IEEE 802 Local Area Networks Series (Parts 1 –11)

Instrumentation System and Automation Society

ISA RP 16.1,2,3 Terminology, dimensions and Safety Practices 2, 3 for Indicating Variable Area Meters (Rotameters)

ISA RP 16.6 Methods and Equipment for Calibration of Variable Area Meters (Rotameters)

ISA RP 31.1 Specification, Installation and Calibration of Turbine Flowmeters.

ISA S 5.1 Instrumentation Symbols and Identification

ISA S 5.2 Binary Logic Diagrams for Process Operations

ISA S 5.3 Graphic Symbols for Distributed Control/Shared Display Instruments, Logic and Control systems

ISA S 5.5 Graphic Symbols for Process Displays

ISA S 18-1 Specification and Guides for the use of General Purpose Annunciators

ISA S 75 Control Valves

International Standards ISO

ISO /DIS 11064-1 Ergonomic design of control centres - Part 1: Principles for the design of control centres

ISO /DIS 11064-2 Ergonomic design of control centres - Part 2: Principles of control suite arrangement

ISO /DIS 11064-3 Ergonomic design of control centres - Part 3: Control room layout

ISO 2714 Displacement Meter Systems

ISO 2715 Turbine Meter Systems

ISO 5167 Specification for square-edged orifice plates, nozzles and venturi tubes

ISO 6385 Ergonomic principles in the design of work systems

ISO 6718 Specifications for bursting Disc devices

ISO 6817 Flow measurement using electromagnetic flow-meters

ISO 7731, Danger Signals for Work Places – Auditory Danger signals

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STANDARDS AND CODES OF PRACTICE APPLICABLE TO INSTRUMENTSNumber Title

National Association of Corrosion Engineers

NACE MR-0175: Sulphide Stress Cracking Resistant Metallic Materials for Oilfield Equipment (if required)

National Fire Prevention Association

NFPA 20 Standards for installation of stationary fire pumps for fire protection

NFPA 496 Standard for Purged and Pressurized Enclosures for Electrical Equipment 1998 Edition

Russian State Regulations

Safety Rules for Exploration and Development of USSR Offshore Oil and Gas Fields

Safety Rules for Oil and Gas Industry (RF Gosgortekhnadzor, RD 08-200-98)

GOST 12.1.003-83 Noise, General Safety requirements

GOST 12.1.010-76 Blast Protection. General Requirements

GOST P51330.9-99 Blast Proof Electrical Equipment, Part 10. Classification of Explosive Zones

Safety of Life at Sea (SOLAS)

International Convention of Safety of Life at Sea

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specification for instrumentation & control

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