Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMPANY Contract No.: LTC/C/NFP/5129/20
CONTRACTOR Project No.: 033764
ASSET
: NFPS
Document Title
:
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
COMPANY Document No.
:
200-51-IN-SPC-00054
CONTRACTOR Document No.
:
033764-E-D-18-SPM-AS-S-00007
Discipline
:
INSTRUMENTATION
Document Type
: SPECIFICATION
Document Category/Class
:
1
Document Classification
:
INTERNAL
00
27-FEB-2025
Approved for Construction
Laijith Mohanlal
B
29-JAN-2025
Issued For Approval
Laijith Mohanlal
A
15-DEC-2024
Issued For Review
Laijith Mohanlal
Engineer
Saravanan Selvam Saravanan Selvam Saravanan Selvam GF Lead
Venkateswara Rao Moturi Venkateswara Rao Moturi Venkateswara Rao Moturi Overall PSL
REV.
DATE
DESCRIPTION OF REVISION
PREPARED BY
CHECKED BY
APPROVED BY
Saipem S.p.A
www.saipem.com
THIS DOCUMENT IS PROPERTY OF QatarEnergy LNG. THIS DRAWING OR MATERIAL DESCRIBED THEREON MAY NOT BE COPIED OR DISCLOSED IN ANY FORM OR MEDIUM TO THIRD PARTIES, OR USED FOR OTHER THAN THE PURPOSE FOR WHICH IT HAS BEEN PROVIDED, IN WHOLE OR IN
PART IN ANY MANNER EXCEPT AS EXPRESSLY PERMITTED BY QatarEnergy LNG.
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
REVISION HISTORY
Revision
Date of Revision
Revision Description
A1
A
B
00
24-OCT-2024
Issued For Inter Discipline Check
15-DEC-2024
29-JAN-2025
27-FEB-2025
Issued For Review
Issued For Approval
Approved for Construction
HOLDS LIST
Hold No
Hold Description
200-51-IN-SPC-00054_00
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
TABLE OF CONTENTS
1
1.1
1.2
2
2.1
2.2
3
3.1
3.2
3.3
3.4
4
5
6
6.1
6.2
INTRODUCTION … 7
Project Objective … 7
Project Scope … 7
DEFINITIONS AND ACRONYMS … 10
Definitions … 10
Abbreviations … 10
REFERENCE, RULES, CODES AND STANDARDS … 14
Order Of Precedence … 14
Company Documents … 14
Project Documents … 15
International Codes and Standards … 16
PURPOSE … 17
SCOPE … 18
GENERAL TECHNICAL DESIGN CRITERIA … 18
Design Life … 18
Environmental Conditions and Weather Protection … 18
6.2.1 Offshore Environmental Condition … 18
6.2.2 Onshore Environmental Condition … 19
6.3
6.4
6.5
6.6
Instrumentation Standardization … 20
Electrical Hazardous Area Protection … 20
Obsolescence Management … 21
Electromagnetic Compatibility … 21
6.7 Mechanical Shock and Vibration Compatibility … 21
6.8
6.9
Lightning Protection and Electrical Surge Protection … 21
Instrument Signal Definition … 21
6.10 Material Requirement … 22
6.11 Utilities and Power Supplies … 23
6.11.1 Greenfield RPs and WHPs … 23
6.11.2 Brownfield Tie-in & Modification … 23
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
6.12 Engineering Units … 23
6.13 Painting and Coating … 25
6.14 Material Traceability and Certification… 25
6.15
Instrument QR Code … 25
6.16 Nameplate and Identification … 25
6.17
Instrument Identification and Numbering … 26
6.18
Instrument Engineering Database … 26
7
7.1
7.2
7.3
8
9
9.1
9.2
9.3
10
FIELD INSTRUMENT GENERAL REQUIREMENTS … 26
General Requirements … 26
Instrument Connections … 27
Performance … 29
ELECTRONIC TRANSMITTERS … 29
PRESSURE INSTRUMENTS … 30
General Requirements … 30
Pressure Gauge … 31
Pressure and Differential Pressure Transmitters … 32
FLOW INSTRUMENTS … 33
10.1 General Requirements … 33
10.2 Flow Meter Selection … 34
10.3 Ultrasonic Flowmeters (UFM) … 35
10.4 Vortex Flowmeters … 36
10.5 Coriolis Flowmeters … 37
10.6 Orifice Plates … 38
10.7
Integral Orifice … 39
10.8 Conditioning Orifice Plate … 39
10.9 Pitot Tube / Averaging Pitot Tube … 39
10.10 Venturi Tubes … 40
10.11 Variable Area Flowmeters … 40
10.12 Flow Nozzle … 41
10.13 V-Cone Flowmeters … 42
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
10.14 Magnetic Flowmeters … 42
10.15 Turbine Flowmeters … 43
11
LEVEL INSTRUMENTS … 43
11.1 General Requirements … 43
11.2 Magnetic Level Gauges … 44
11.3 Continuous Level Instruments … 45
11.3.1 Guided Wave Radar (GWR) … 45
11.3.2 Differential Pressure Type Instrument … 46
11.3.3 Displacer Level Transmitter. … 46
12
TEMPERATURE INSTRUMENTS … 47
12.1 General Requirements … 47
12.2 Thermowell … 47
12.3 Resistance-Type Detector … 49
12.4 Thermocouple … 49
12.5 Temperature Transmitter… 49
12.6 Temperature Gauge … 49
13
FIRE AND GAS DETECTORS… 50
13.1 General Requirements … 50
13.2 Fire Detection … 51
13.2.1 Smoke Detector … 51
13.2.2 Heat Detector … 52
13.2.3 High Sensitivity Smoke Detector (HSSD) … 52
13.2.4 Flame Detector … 52
13.2.5 Manual Alarm Call Point (MAC) & Manual ESD Push Button … 53
13.3 Gas Detection … 54
13.3.1 Flammable Gas Detector (Point Type) … 54
13.3.2 Hydrogen Gas Detector (Point Type) … 54
13.3.3 Toxic Gas Detector (Point Type) … 54
13.4 Visual and Audible Alarm … 55
13.4.1 Beacon … 55
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
13.4.2 Sounder … 55
14
MISCELLANEOUS INSTRUMENTS… 56
14.1 Corrosion Probes & Fittings … 56
14.1.1 General … 56
14.1.2 Electrical Resistance Probes (ERP) … 56
14.1.3 Data Logger … 56
14.2 Acoustic Solic Particle Detector (Sand Monitoring)… 57
15
16
17
18
INSTRUMENT INSPECTION AND TESTING … 57
DOCUMENTATION … 58
PACKING, SHIPMENT AND PRESERVATION … 58
SPARE PARTS AND SPECIAL TOOLS … 58
18.1 Spare parts … 58
18.2 Special tools… 59
19
TABLE SUMMARY … 59
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
1
INTRODUCTION
The North Field is the world’s largest natural gas field and accounts for nearly all the State of Qatar’s gas production. The principal objective of the NFPS projects is to sustain plateau from existing QatarEnergy LNG Operation – S1, S2, S3, N1 and N2 , production areas by implementing an integrated and optimum investment program consisting of subsurface development, pressure drop reduction steps and compression.
NFPS projects comprise 3 main investment programs:
- Investment #1: Drilling and Associated Facilities [WHP12S/ WHP13S/ WHP14S/
WHP12N/ WHP13N]
- Investment #2: Trunk line Looping and Intra-field pipeline looping [32” PL1LN, 32”
PL1LS, 38”PL610LS]
- Investment #3: Compression Complexes and associated facilities [Phase 1 CP6S & CP7S; Phase 2: CP8S & CP4N; Phase 3: CP4S & CP6N Phase 4: CP1S & CP1N]
Drilling and Looping, Investments #1 and #2, projects are in execution phase and are being executed as I1P1, EPCOL Projects except for WHP13N, which will be part of NFPS Compression Projects execution which compromises total up to 9 COMPs.
1.1 Project Objective
The objective of the COMP3 project includes:
• Achieve standards of global excellence in Safety, Health, Environment, Security and
Quality performance.
• Sustain the Qatarenergy LNG North Field Production Plateau by installing new RPs and one WHPs to support new Compression Complex facilities CP6S & CP7S and pre-installed facilities for future Compression Complex facilities including but not limited to CP4N & CP8S tie-in with integration to the existing facilities under Investment #3 program.
• Facility development shall be safe, high quality, reliable, maintainable, accessible,
operable, and efficient throughout their required life.
1.2 Project Scope
The Project Scope includes detailed engineering, procurement, construction, brownfield modifications, transportation & installation, hook-up and commissioning, tie-in to EXISTING PROPERTY and provide support for start-up activities of the following facilities and provisions for future development. The WORK shall be following the specified regulations, codes, specifications and standards, achieves the specified performance, and is safe and fit‐for‐ purpose in all respects.
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
Facilities – 1A
• RP5S RP with 2 x 28” CRA clad pipelines to RP7S and 2 subsea composite Cables
and associated J tubes from RP7S to RP5S & from CP7S to WHP13S.
• New Fuel Gas 8” CRA Spur-lines and flanged risers from Subsea skid to RP7S
• Hook-up and brownfield modification at WHP5S/RP5S bridge connection & WHP13S/CP7S Composite cable tie-in and E&I integration including RGA Control modification
• Pipeline decommissioning of 28” CS PL5 including associated demolition work at
WHP5S
Facilities – 2A
• RP6N RP with 1x28” CRA clad pipeline to WHP13N, 2 Subsea composite cables and
associated J tubes from WHP12N to RP4N and RP6N to WHP13N. • New fuel gas spur-line and flanged riser from subsea skid to RP6N • WHP13N Topside • Hook-up and brownfield modification at WHP6N/RP6N, RP4N- HPU-Umbilical and tie- in, WHP12N-new J tube installation, E&I migration, WHP6N/RP4N/WHP4N-E&I migration (Pre-CP4N), WHP13N and RP6N interconnection to NFB.
Facilities – 3A
• RP9S RP with 1x28” CRA clad pipeline to RP4S, • Hook-up and brownfield modification at RP4S/WHP9S, Modifications to integrate
RP9S to the RGA control network.
• Pipeline decommissioning of 28” PL9 to WYE on existing 38” trunkline PL49 including
associated demolition work at WHP9S.
Facilities – 1B
• New fuel gas spur-line and flanged riser from subsea skid to RP4N • Fiber Optic Cable from RP6N to onshore LFP East, RP6N to RP4N and RP6N to LQ6S. • Hook-up and brownfield modification at RP6N Composite and FO Tie-ins NFB-PU (East)- FO Tie-in
(East)/BVS
Power & Control modifications, LQ6S/LFP Controls/Telecoms Integration
Facilities – 2B
• RP5N RP with 2 x 28” CRA clad pipelines to RP4N, 1 x 28” CRA clad pipeline to RP6N and 2 subsea composite Cables and associated J tubes from WHP12N to RP5N & from RP6N to RP5N.
• Hook-up and brownfield modification at WHP5N- RP5N Bridge connection, WHP12N Composite cable tie-in, RP4N Intrafield pipeline Hook up PL54 N/LN and E&I integration including NFB-PU Power & Control modifications
• Pipeline decommissioning of 2 x 16” PL56/PL54 Subsea Spur line from WHP5N to
reducing barred tee in subsea tie-in skid on PL6 / PL4.
Facilities – 3B
• 2 subsea composite Cables from RP4S to RP9S & from RP4S to WHP12S (with J-
tube)
• New Fuel Gas 8” CRA Spur-lines and flanged risers from Subsea skid to RP4S
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
• Hook-up and brownfield modification at WHP12S/ RP9S/ RP4S Composite cable tie-
in, Spurline riser installation at RP4S RGA Power & Control modifications.
Facilities – 4B
• 1 subsea composite Cable from CP8S to RP11S (or from RP8S to RP11S as
Option).
• New Fuel Gas 8” CRA Spur-lines and flanged risers from Subsea skid to RP8S. • Hook-up and brownfield modification at WHP8S/ WHP11S for Test separator Internal Upgrade and MEG system modification, Spur lines, Power & Control Tie-ins on RP8S, RP11S/WHP11S-Tie-in (Power and Control), RGA Power & Control modifications.
Facilities – 5B
• 2 subsea composite Cables from RT2 to WHP3S & from RT2 to WHP2S (with J-tube)
and FO Cable from RT2 to Barzan WHP1.
• New Fuel Gas 8” CRA Spur-lines and flanged riser from Subsea skid to RP8S • Hook-up and brownfield modification at BRZ-WHP1 – FO cable tie-in, WHP2S/ WHP3S/ RT&RT2 Composite cable tie-in and associated modification, RGA Power & Control modifications.
Facilities – 6B
• RP3S RP with 1x24” CRA clad pipeline to RT2 with Stalk on risers, • Hook-up and brownfield modification at RT2 for 24” Intrafield pipeline and Composite/FO cable Hook-up, WHP3S for Production diversion and Utilities, Power and ICSS Hook-up, WHP2S for Composite Cable Tie-ins and Power & Control Integration RGA Power & Control modifications. topside existing and
In-situ abandonment of existing Topside/subsea Composite Cables RT-WHP2S, RT-WHP3S, Topside/Subsea FO cable RT-BRXWHP1.
• Decommissioning at
Figure 1.2.1: NFPS Compression Project COMP3 Scope
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
2 DEFINITIONS AND ACRONYMS
2.1 Definitions
Definition
COMPANY
QatarEnergy LNG
CONTRACTOR
Saipem S.p.A.
Description
DELIVERABLES
All products (drawings, equipment, services) which must be submitted by CONTRACTOR to COMPANY at times specified in the contract.
FACILITIES
MILESTONE
All machinery, apparatus, materials, articles, components, systems and items of all kinds to be designed, engineered, procured, manufactured, constructed, supplied, fabricated, tested and permanently installed by CONTRACTOR at SITE in connection with the NFPS Project as further described in Exhibit 6. A measurement purpose
reference event splitting a PROJECT activity
for progress
PROJECT
NFPS Offshore Riser Platforms & Intrafield Pipelines Project - COMP3
SITE
(i) any area within Ras Laffan Industrial City leased or to be leased by COMPANY for the purpose of the realization of the FACILITIES and (ii) the area offshore required for installation of the FACILITIES in the State of Qatar.
SUBCONTRACT
Contract signed by SUBCONTRACTOR and CONTRACTOR for the performance of a certain portion of the WORK within the Project.
SUBCONTRACTOR
Any organization selected and awarded by CONTRACTOR to supply a certain Project materials or equipment or whom a part of the WORK has been Subcontracted
WORK
Refer to article 2 of CONTRACT AGREEMENT
WORK PACKAGE
The lowest manageable and convenient level in each WBS subdivision
VENDOR
2.2
Abbreviations
The person, group, or organization responsible manufacture, testing, and load-out/shipping of the Equipment/ Material.
the design,
for
Code
AC
ADAS
AFDS
ALMS
Definition
Alternating Current
Analyzer Data Acquisition System
Addressable Fire Detection System
Alarm Management System
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
Code
ANSI
API
ASME
ASTM
CCC
CRA
CCR
CMMS
DBB
DC
DCS
DD
DFT
DIFFS
DPDT
DTM
EN
EOL
ESD
Ex d
Ex e
Ex i
EPCC
FAT
F&G
FEED
FGS
Definition
American National Standards Institute
American Petroleum Institute
American Society of Mechanical Engineers
American Society For Testing and Materials
Centralized Control Centre
Corrosion Resistant Alloy
Central Control Room
Computerized Maintenance Management System
Double Block and Bleed
Direct Current
Distributed Control System
Device Description
Dry Film Thickness
Deck Integrated Firefighting System
Double Pole Double Throw
Device Type Manager (DTM)
European Norms
End of Line
Emergency Shutdown System
Hazardous Area Protection Technique – Flameproof
Hazardous Area Protection Technique – Increased Safety
Hazardous Area Protection Technique – Intrinsically Safe
Engineering, Procurement, Construction, Commissioning
Factory Acceptance Test
Fire and Gas
Front End Engineering Design
Fire and Gas System
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NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
Code
H2
H2S
HART
HSSD
HVAC
IAMS
ICSS
IEC
IECEx
IO
IP
IR
IS
ISA
ISO
ITP
LER
LCD
LCP
LED
LEL
LELm
LFL
LQ
MAC
MICC
MOS
Definition
Hydrogen
Hydrogen Sulfide
Highway Addressable Remote Transducer
High Sensitivity Smoke Detector
Heating, Ventilation and Air Conditioning
Integrated Asset Management System
Integrated Control and Safety System
International Electrotechnical Commission
International Electrotechnical Commission System for Certification to Standards Relating to Equipment for Use in Explosive Atmospheres
Input Output
Ingress Protection
Infra-Red
Intrinsically Safe
International Society of Automation
International Organisation for Standardisation
Inspection and Test Plan
Local Equipment Room
Liquid Crystal Display
Local Control Panel
Light Emitting Diode
Lower Explosive Limit
Lower Explosive Limit metre
Low Flammable Limit
Living Quarters
Manual Alarm Call Point
Main Instrumentation and Control Contractor
Maintenance Override Switch
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
Code
NACE
NFA
NFB
NFPS
NPT
OD
PAGA
PCB
Definition
National Association of Corrosion Engineers
North Fields Alpha
North Fields Bravo
North Field Production Sustainability
National Pipe Thread
Outside Diameter
Public Address & General Alarm
Printed Circuit Board
Pre-FEED
Preliminary Front End Engineering Design
QA
QG
QG1
QG2
QG-N
QG-S
Re
RGA
RGE
RL
RP
RTD
SCC
SIF
SIL
SPI
SS
TC
Quality Assurance
Qatargas
Qatargas Block 1
Qatargas Block 2
Qatargas North
Qatargas South
Reynold’s number
RasGas Alpha
RasGas Expansion (LNG Train 3,4,5,6,7 and AKG-1,2) - Wet Gas System
Ras Laffan
Riser Platform
Resistance Temperature Detector
Satellite Control Centre
Safety Instrumented Function
Safety Integrity Level
Smart Plant Instrumentation
Stainless Steel
Thermocouple
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
Code
TCP/IP
UCP
UPS
URL
WHP
Definition
Transmission Control Protocol/Internet Protocol
Unit Control Panel
Uninterruptable Power Supply
Upper Range Limit
Wellhead Platform
3 REFERENCE, RULES, CODES AND STANDARDS
3.1 Order Of Precedence
The following codes, standards and specification are referenced within the document and shall be considered as part of this specification. Conflict among applicable specification and / or codes shall be brought to the attention of the COMPANY for resolution. COMPANY decision shall be final and shall be implemented. The latest editions of codes and specification effective as on date of contract shall be followed.
In general, the order of precedence shall be followed:
a) Qatari Governmental and Regulatory Requirements b) COMPANY Policies and Procedures c) d) e) COMPANY and CONTRACTOR’S lessons learned
Project Specifications Industry Codes and Standards
If Contractor / VENDOR deems any deviations from the specifications will result in significant project cost and schedule saving, proposal to such deviations shall be submitted to COMPANY for review and approval. Contractor / VENDOR shall not proceed with any deviation to the Specifications without prior COMPANY APPROVAL.
3.2 Company Documents
Document Number
Title
EXHIBIT 5
Project Instructions
PRJ-PJL-PRC-005_21
Facilities, System and Unit Number Codes and Descriptions Procedure
PRJ-PJL-PRC-006_01
Project Information Handover Procedure
PRJ-PJL-PRC-007_01
PRJ-PJL-PRC-048_11
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QG SmartPlant Eng Applications & Drafting (CAD) Standard
Facilities Documentation Metadata Requirements Procedure
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SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
PRJ-PJL-PRC-049_01
Project Information Handover, Verification and Acceptance Procedure
INF-ISG-POL-001_03
Information Classification Policy
PRJ-PJL-PRC-080
AIMS: Tag Management System (TMS)
COMP-QG-PR-REP-00003
NFPS-COMP-PE-DB-0004
NFPS-COMP-PE-DB-0005
PRJ-PJLPRC-008
GDL-UF-06
PRJ-PJL-PRC-007
3.3 Project Documents
NFPS QG-S RGE Compression Basis of Design (BoD) for FEED
NFPS QG-S RL Compression Basis of Design (BoD) for FEED
NFPS QG-N QG2 Compression Basis of Design (BoD) for FEED
Qatargas Equipment Numbering Philosophy
Qatar Petroleum Guidelines for the Measurement of Hydrocarbon Fluids
SmartPlant Engineering Applications & Drafting (CAD) Standard Procedure
Document Number
Title
200-51-IN-DEC-00011
Instrument And Control Systems Design Basis
200-20-PI-SPC-00044
Piping Material Specification for COMP3 Project
200-20-CE-SPC-00027
Specification for Fixed Facilities Protective Coating for COMP3 Project
200-20-PR-DEC-00005
Isolation Philosophy (Green Facilities)
200-83-IN-SPC-00005
Specification for High Sensitivity Smoke Detection (HSSD)
200-51-IN-SPC-00051
Instrument Database Specification
200-50-IN-SPC-00004
Specification for Panels and Control Consoles
200-51-IN-SPC-00059
Specification for Instrument Installation
200-51-IN-SPC-00060
Specification for Instrument Junction Boxes
200-51-IN-SPC-00057
200-20-CE-DEC-00006
Specification for Instrument Cables & Cable Glands for COMP3 Project
Material Selection Philosophy for Comp3 Project for COMP3 Project
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NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
3.4
International Codes and Standards
Document Number
Title
ASME B1.20.1
ASME B16.5
ASME B16.20
ASME B16.36
ASME B16.47
ASME B31.3
ASME B40.100
ASME B46.1
ASME MFC-5.1
Pipe Threads, General Purpose (Inch)
Pipe Flanges and Flanged Fittings NPS 1/2 Through NPS 24 Metric/Inch Standard
Metallic Gaskets for Pipe Flanges
Orifice Flanges
Large Diameter Steel Flanges
Process Piping
Pressure Gauges and Gauge Attachments
Surface Texture (Surface Roughness, Waviness, and Lay)
Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters
ASME PTC 19.3 TW
Thermowell - Performance Test Codes
ASME Section IX
ASME VIII
Qualification Standard For Welding, Brazing, And Fuzing Procedures; Welders; Brazers; And Welding, Brazing, And Fusing Operators - Welding, Brazing And Fusing Qualifications
Boiler and Pressure Vessel Code - Rules for Construction of Pressure Vessels
AGA Report No. 9
Measurement of Gas by Multipath Ultrasonic Meters
API MPMS 5.3
API MPMS 14.10
API RP 551
EN 10204
IEC 60079 series
IEC 60068-2-27
Manual of Petroleum Measurement Standards Chapter 5- Metering Section 3-Measurement of Liquid Hydrocarbons by Turbine Meters
Manual of Petroleum Measurement Standards - Chapter 14: Natural Gas Fluids Measurement - Section 10: Measurement of Flow to Flares
Process Measurement
Metallic Products – Types of Inspection Documents
Explosive Atmospheres (all relevant parts)
Environmental Testing – Part 2-27: Tests – Test Ea and Guidance: Shock
IEC 60529
Degrees of Protection Provided by Enclosures (IP Code)
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SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
IEC 60584-1
IEC 60751
IEC 60770-1
Thermocouples – Part 1: EMF specifications and tolerances
Industrial Platinum Resistance Thermometers and Platinum Temperature Sensors
Transmitters for Use in Industrial-Process Control Systems – Part 1: Methods for Performance Evaluation
IEC 61000 part 1 to 6
Electromagnetic Compatibility (EMC)
IEC 61131-2
IEC 61140
IEC 62305
IEC 62402
Industrial-Process Measurement and Control – Programmable Controllers – Part 2: Equipment Requirements and Tests
Protection Against Electric Shock – Common Aspects for Installations and Equipment
Protection Against Lightning
Obsolescence Management
IEC 62443 Series
Security for Industrial Automation and Control Systems
IEC 62828-1
ISA 18.1
ANSI/ISA 18.2
ANSI/ISA-71.04
MR0175/ISO 15156
NFPA 72
NE 043
ASTM E 1137/E 1137M
4 PURPOSE
Reference Conditions and Procedures Industrial and Process Measurement Transmitters - Part 1: General procedures for all types of transmitters
for Testing
Annunciator Sequences and Specifications
Management of Alarm Systems for the Process Industries
Environmental Conditions for Process Measurement and Control Systems: Airborne Contaminants
Petroleum and Natural Gas Industries – Materials for use in H2S - Containing Environments in Oil and Gas Production
National Fire Alarm and Signaling Code
Standardization of the Signal Level for the Failure Information of Digital Transmitters
Standard Specification for Industrial Platinum Resistance Thermometers
The purpose of this document is to define the minimum technical requirements for design, engineering, procurement, inspection, testing, supply and installation of Field Instruments as defined in this specification and in accordance with the referenced design codes, standards and specification.
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SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
API RP 551 shall be referred for recommendations about the selection and design of process measurement systems.
Compliance with this specification does not relieve the EPC Contractor / VENDOR from the responsibility to handover fit for purpose equipment in accordance with codes and standards, project specifications, COMPANY specifications and good engineering practice.
This Specification for Field Instruments and referred specifications and standards shall be applicable, in general for the brownfield scope on PU platforms also.
This document should be read in conjunction with other design philosophies, specifications and referenced document.
5 SCOPE
This design basis along with all the specifications and standards referenced in this document, defines the minimum technical requirements for the selection, engineering, design, manufacture, inspection, testing and installation of all instrumentation, control and safety systems for the PROJECT scope mentioned in the section 1.2.
6 GENERAL TECHNICAL DESIGN CRITERIA
6.1 Design Life
In general, the design life of the new facilities shall be for an operational life of 30 years. Any specific deviation shall be subject to COMPANY approval.
To minimise the disruption of the plant operations, equipment shall have full replacement or spare parts/component replacement in case of malfunction. All equipment must have at least two (2) years proven field experience. Prototype equipment and components shall not be used.
VENDOR shall provide technical support and provision of all supplied components throughout it’s design life (30 years). For any components becoming obsolete, VENDOR shall suggest and provide alternative component fit for the intended purpose.
6.2 Environmental Conditions and Weather Protection
All field mounted instruments, junction boxes, local control panel/unit control panel and instrument accessories installed outdoor shall be suitable for installation in saliferous, marine and corrosive environment for offshore locations and at onshore locations
The offshore and onshore environmental conditions based on the respective offshore/onshore environmental data.
6.2.1 Offshore Environmental Condition
• Ambient Temperature
o Expected maximum daily average o Expected maximum daily o Expected minimum daily o Expected yearly maximum temperature o Expected yearly minimum temperature
: 36°C : 41.1°C : 12.7°C : 45.6°C : 8.3°C
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o Air cooler design o Gas Turbine design o Black bulb temperature o Design temperature for equipment operating
at ambient conditions
• Relative Humidity o Minimum o Average o Maximum
• Atmospheric Pressure
o Minimum o Maximum
•
Rainfall o Once in 2 years minimum o Once in 10 years minimum o Once in 50 years minimum
• Sea Water Temperatures (°C):
: 45.6°C : 42°C : 84°C : 49°C
: 37 % : 71 % : 100 %
: 998 mbar : 1020 mbar
: 12 mm/h : 27 mm/h : 41 mm/h
Table 5-1: Sea Water Temperature
Water Depth (m)
Min. Temperature
Max. Temperature
Mean Temperature
0
15
30
45
60
75
15.8
15.8
15.6
15.2
16.3
17.1
34.7
34.5
33.4
33
31.8
27.5
24.1
22.9
23.2
22.7
22.1
21.6
6.2.2 Onshore Environmental Condition
• Barometric Pressure
o Design Barometric Pressure o Maximum Barometric Pressure o Minimum Barometric Pressure o Maximum Instantaneous Barometric Charge
: 1013 mbar : 1020 mbar : 995 mbar : 25 mbar
(for LNG tank pressure/vacuum protection design)
• Ambient Temperature
o Annual Average Air Temperature (Dry Bulb) o Annual Average Air Temperature (Wet Bulb) o Yearly Maximum (Dry Bulb) o Yearly Minimum (Dry Bulb) o Extreme Dry Bulb Temperature
: 29°C : 21°C : 49°C : 5°C : 49°C
• Relative Humidity
o Mean Daily o Mean Daily Maximum o Mean Daily Minimum
: 59% : 80%(@4°C Dry Bulb) : 35%(@4°C Dry Bulb)
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SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
• Solar Radiation
o Yearly Maximum Daily Measured o Design
: 8.03 kW/m2
: 0.90 kW/m2
Equipment exposed to sunlight shall be designed for black bulb temperature.
For equipment installed indoor in environment-controlled location with HVAC, the design rating for the electrical/electronic equipment shall be minimum +49°C.
As minimum, all equipment installed outdoor shall be with IP66 ingress protection as per IEC 60529. For instrument which are installed at splash zone area (impacted due to green water wave impact), ingress protection rating shall be IP67 or higher. In general, tubing shall not be routed in the vicinity of such areas to avoid impact/impingement due to waves. Consideration to be given for usage of instrument protective enclosures, where practical/available for the intended instrument, which act as a protective shield to the instruments which could be potentially exposed to the waves/splash. For cable routing in such exposed areas, consideration to be given for covered trays to protect cables from direct impact due to waves.
All indoor control panels and other instrument enclosures installed indoors in unclassified areas inside enclosed building shall be rated minimum IP42, except for IT cabinets (server and network) which shall be minimum IP20. Server cabinet doors are preferred to be mesh type (perforated) for maximum air flow.
All electronics shall be tropicalized, with measures such as anti-corrosion coatings on printed circuit boards and hermetical sealing of electronic circuitry, shall be incorporated within the instrument design to withstand the outdoor ambient conditions and function properly in the outdoor environment. Conformal coatings for PCBs, electronic modules, etc for control system equipment in indoor installation shall be provided to meet severity levels of ISA -71.04 Class G3.
Where equipment contained in enclosures may be subjected to temperatures exceeding 85°C due to solar, radiant or self-heating, the enclosure shall be provided with either a canopy type covering or a cooling system to maintain internal temperature below this value.
Canopy shall be provided for all electronic Instrumentation and Field Pushbuttons/manual alarm call points (FGS devices in general) that are exposed to direct sunlight, as well as junction boxes/local control panel when required. Canopy shall be UV resistant electrostatic free FRP / GRP material.
For environmental conditions which is to be met during equipment storage, it shall follow the storage temperature and conditions recommended by manufacturer of the equipment during storage of equipment during the execution phase.
6.3
Instrumentation Standardization
Instrumentation (field instrumentation, valves, ICSS, package control system and instrument bulk e.g. tube and fittings) standardization shall be considered for the PROJECT, including packaged units, to maximise the use of instrument with same technology, manufacturer and model for the same use.
6.4 Electrical Hazardous Area Protection
All instrument installed in outdoors shall be suitable for installation in Zone 1, Gas Group IIB and Temperature Class T3 as minimum. For instruments installed within battery rooms, it
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SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
shall be certified for installation in a Zone1, Gas Group IIC, and Temperature class T3 as minimum. Equipment certification shall comply to IECEx standard.
Field instrument shall be Ex ‘d’ flameproof certified, unless otherwise specified. Intrinsically Safe Ex ‘i’ protection is acceptable (as per VENDOR recommendation) for some of the machine monitoring signals, anti-surge control signals, etc.
6.5 Obsolescence Management
VENDOR shall submit an obsolescence plan for technologies used as part of the Services.
The obsolescence shall be managed as per IEC 62402.
All technologies shall be supported by the VENDOR for a minimum of 15 years from the placement of order or 10 years from end of warranty, whichever period ends last. These technologies include system hardware, firmware, and software with spare parts and services. This support shall not be contingent on the customer upgrading to later releases of software or hardware unless this upgrade is supplied at no additional cost.
System software upgrades to the latest revisions shall be provided for a period of up to 5- years from date of commissioning, at no additional cost. As EPC contracts will be awarded in stages, the obsolescence for backward compatibility to hardware and software shall be at least 10 years. Bid proposal shall cover this requirement explicitly.
6.6 Electromagnetic Compatibility
The equipment supplied shall function without introducing intolerable electromagnetic disturbances to other items of equipment, or being susceptible to electromagnetic influences from other sources. The equipment shall include electromagnetic compatibility and electrostatic discharge protection in accordance with the requirements of the IEC 61000-4 standards.
6.7 Mechanical Shock and Vibration Compatibility
Mechanical shock and Vibration compatibility shall be in accordance with IEC 60068-2-27, IEC 62828-1, and IEC 61131-2. Where no product specific standards exist, a continuous or repetitive vibration of 2.5 G, 5 -500 Hz shall not cause any damage or malfunction.
6.8 Lightning Protection and Electrical Surge Protection
For lightning protection, field transmitters selected shall be equipped with inbuilt transient surge protection within the circuitry. Similarly, the surge protection for the ICSS I/O cards and package control system I/O cards shall be integrated in the I/O card design for each channel.
Surge protection device/module shall be installed at the incoming power supply inside the ICSS power distribution panel. Surge protection device/module to be installed in package control panels installed in the field at the incoming power supply. Surge protection device shall be designed and tested in accordance to IEEE requirement.
6.9
Instrument Signal Definition
All electronic analogue transmitter signals connected to ICSS and package equipment control and safety systems shall be smart 4-20mA output superimposed with HART protocol (revision 7 or latest), 2 wire, 24VDC loop powered. Transmitters shall be supplied with integrated local digital indicators to display the measurement with associated engineering units. Separate remote local indicator shall be provided for transmitter installed on inaccessible location.
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SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
Transmitters with 4-20 mA output shall comply with NAMUR NE043 enabling process under range and over range detection and sensor failure detection with upscale or downscale burnout selector switch. The fault detection configuration in ICSS shall match to the field equipment fault generation settings.
Smart transmitters shall have output analog signal operational between 3.8 mA to 20.5 mA, unless specified otherwise by COMPANY.
For ESD signal, normally energised (fail-safe) design shall be followed. For FGS, normally de- energized (non fail-safe) design shall be followed.
For F&G input signal to FGS, all discrete input signal from F&G detectors shall be dry contact (volt-free) and shall be supervised to detect faults (open or short circuit) in the field wiring. For ESD, discrete input signals part of SIF shall be supervised to detect faults (open or short) in the field wiring.
Thermocouple signals for flare tip applications shall be wired to the flare package and 4 – 20 mA signal (loop powered) shall be transmitted to DCS for monitoring / alarm.
6.10 Material Requirement
For well fluid process/hydrocarbon services, wetted part material and pressure retaining parts shall be Inconel 625/Hastelloy C276 as minimum.
Material of Remote Diaphragm seals of Instruments, including lower and Upper housings and components, shall be of Inconel 625/Hastelloy C276 as a minimum.
Tubing and fittings material shall be minimum Inconel 625 for all services. Sea water service shall utilise Monel as minimum.
For sour service application, material shall be fully in compliance with the ISO 15156/ NACE MR 01-75 requirements.
In general, wetted parts materials for all instruments shall follow the associated piping class and shall as minimum have SS316 for non-hydrocarbon and non-sour services.
All Instruments shall be rated for continuous operation at 8.3 ˚C to 45.6 ˚C ambient and 84 ˚C black body temperature. SS316 instruments installed in exposed areas (under direct sunlight) where the ambient temperature / process temperature exceeds 60°C suitable alternate material shall be considered to avoid Chloride induced stress cracking. Stainless steel grade other than 316 are not allowed.
Instrument enclosures which are subject to temperatures exceeding 84°C due to solar or radiant heat, the enclosure shall be provided with canopy/sunshade to maintain the internal temperature below 84°C or the equipment’s operating limit, to protect the instrument from failure due to black body radiation.
Instrument enclosure / housing shall be of SS316 as a minimum.
For seawater services, instrument wetted parts material shall be Monel 400 or equal.
Transmitter wetted parts, Instrument manifold, mounting bolts and nuts, tubing and fittings shall be of same material to avoid bi-metallic corrosion.
The materials ASTM A193-B8M & ASTM A194-8M & ASTM A453-660 are not permitted for offshore bolt/nut materials. Bolt and Nuts shall follow the Material Selection Philosophy for COMP3 Project, 200-20-CE-DEC-00006.
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SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
All materials including gaskets shall be free from hazardous substances such as Asbestos, mercury, halogen, ceramic fibre, radioactive materials etc.
6.11 Utilities and Power Supplies
6.11.1 Greenfield RPs and WHPs
The ICSS and all package UCPs shall be supplied with 230VAC, 50 Hz from dual redundant UPS. UPS and Non-UPS supply shall be 230V, 1Phase + N + Earth .
Power distribution panels shall be used to distribute UPS power for the ICSS cabinets/panels and other cabinets/panels inside. The use of non-UPS power supply is not envisaged for the ICSS cabinets/panels and other cabinets/panels. For field instruments and packaged equipment instrumentation in field that need external 230 VAC UPS power supply, it shall be powered from the Instrument UPS power distribution panel.
All the instruments shall be generally 24VDC loop powered from ICSS and package UCPs, as applicable.
If 24VDC external power supply is needed for the 4 wire Instrumentation, it shall be derived from the instrument marshalling cabinets.
6.11.2 Brownfield Tie-in & Modification
For brownfield tie-in and modification at existing WHPs and RPs, the utilities and power supply requirement for the instrument shall be in accordance with existing facilities design conditions.
The utilities in the existing WHP to be utilized for the new instrumentation.
6.12 Engineering Units
Engineering units of this project shall follow the engineering units as per PROJECT Basis of Design.
Table 5-2: Unit of Measurement
Parameter
Unit
Abbreviation
Absolute Viscosity
Centipoise
Area
square meter
Cathodic Current Density
Amp per square meter
Conductivity
Micro Siemens per centimeter
Current
Elevation
Flow (mass)
Flow (molar)
Amp
meter
Kilogram per hour
СР
m²
A/m²
μS/cm
A
m
kg/h
kilogram mole per hour
kgmol/h
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SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
Flow (volume)
Barrel per day. Cubic meter per hour
BPD, m3/h
Force
kilo Newton
Heat / Energy
Kilocalorie. Kilojoule
kN
kcal, kJ
Heat Transfer Coefficient
watts per square meter per degree C W/m²°C
Heating Value
megajoule per cubic meter megajoule per kilogram
Heat Radiation
watts per square centimeter
Kinematic Viscosity
Centistokes
MJ/m3 MJ/kg
W/cm²
cSt
Millimeter or Meter or Kilometer
mm or m or km
Length
Level
Meter or millimeter Percentage
Liquid Density
Kilogram per cubic meter
Mass Enthalpy
kilojoule per kilogram
Mass
Kilogram or metric tons
Pipe diameter
Potential
Power
Pressure
Pressure (close to atmosphere)
Pressure Differential
Resistance
Inch
Volt
Kilowatt
Bar gauge, Bar absolute
millimeter water column
Bar
Ohm
Sound Pressure
Decibel
m or mm %
kg/ m3
kJ/kg
kg or t
in
V
kW
barg, bara
mmH2O
bar
Ω
dBA
Specific Heat
kilojoule per kilogram per degree C
W/m°C
Stress
Newton per square meter (Pascal)
N/m²
Temperature
Degree Celsius
Thermal Conductivity
watt per meter per deg C
°C
W/m°C
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SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
Throughput of gas at standard conditions
Standard cubic feet per minute Million standard cubic feet per day
SCFM MMSCFD
Time
Vacuum
Velocity
Viscosity
Volume
Second / minute/ hour / day
millimeter water column
Meter per second
centipoise
Cubic meter
Wind Velocity
meter per second
6.13 Painting and Coating
s/min/h/d
mmH2O
m/s
cP
m3
m/s
All Instrument electronic housing with SS316 material of construction shall be painted with manufacturer standard 3 coat system epoxy coating with minimum total DFT of 250 microns.
Field instruments (including instrument stand and other than the electronic enclosure) painting, shall be suitable for offshore corrosive environment and in accordance with PROJECT’s Painting Specification.
For indoor panels, the painting shall conform to VENDOR’s standard specification.
6.14 Material Traceability and Certification
Material certificates shall be provided for all pressure retaining and non-retaining parts. Pressure retaining parts shall be provided with EN 10204 3.1 material certificates while EN 10204 2.2 material certificate for non-pressure retaining parts and in accordance with PROJECT’s Specification for Material Traceability and Documentation Requirements. For sour service, material certificate to EN 10204 3.2 shall be provided.
6.15 Instrument QR Code
Field Instrument shall be provided with QR code supplied by QR code vendor. The QR code shall be affixed on the Instrument at most visible to individuals standing in front of the Instrument. If required, a permanent mounting bracket (or equivalent) shall be provided on the Instrument if there is no surface available to affix the QR code. Size and material of the QR code will be determined during detail design but it shall not exceed 10x5 cm.
6.16 Nameplate and Identification
Instruments shall have the following information on a permanently fastened 316 stainless steel nameplate in accordance with the project tagging philosophy :
a)
b)
Equipment identification number, which shall be supplied by Purchaser.
Manufacturer’s name, model, and serial number.
As applicable, nameplates shall also state service, pressure rating of pressure holding parts, operating range, certifications, voltage, frequency, and materials of construction for parts exposed to process fluids.
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SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
In addition to any VENDOR supplied nameplate, each installed instrument shall be provided with an identification nameplate containing the tag number and the process service description. These nameplates shall be fabricated from a corrosion resistant material (16 U.S. gauge stainless steel or equivalent is preferred) and shall be permanently and securely fastened to the instrument by rivets or drive screws. The identification nameplate shall be readable from grade or the associated maintenance platform. If any process connection is not viewable from its associated instrument, then a separate tag nameplate is required at each such process connection.
Instrument nameplate shall have tag number with service description.
6.17 Instrument Identification and Numbering
Instrument identification and numbering, including package instruments shall be in accordance with COMPANY’s Equipment Numbering Philosophy, Doc No: PRJ-PJLPRC-008 Qatargas Equipment Numbering Philosophy.
6.18 Instrument Engineering Database
SmartPlant Instrumentation (SPI) version 2018 (12.00.002913 HF 19) shall be used as instrument engineering database during FEED for this PROJECT. It shall be in accordance with Project’s Instrument Database Specification and COMPANY’s SmartPlant Engineering Applications & Drafting Procedure.
For brownfield scope where existing instrument SPI database may not be available, Microsoft® Excel spreadsheet will be used for instrument deliverables (e.g. Instrument Index, I/O list, datasheets and etc).
7 FIELD INSTRUMENT GENERAL REQUIREMENTS
7.1 General Requirements
In general, only transmitters shall be used for measurement. The use of switches is acceptable only when transmitters are not available for the same intended function and service.
Instrument range shall be selected to cover both Minimum, Maximum operating parameters. When choosing a range, the alarm set points shall fall between 10% and 90% of the instrument’s range.
Separate instruments along with tapping points shall be provided for control and safety functions in order to avoid common mode failures.
Instrument terminal blocks shall be non-hygroscopic. The terminal block shall be screw type or snap-in pressure clamp type. Proper terminals enclosed in the transmitter housings shall be supplied for all devices. Flying lead connections for field devices are not allowed.
The preferred instrument installation is close coupled (line mounted). If inline or direct mounted field instruments cannot be used, then the impulse line system shall be adopted where tubing shall be kept as short as possible.
Diaphragm seal (direct mounted) Pressure gauges shall be used for well fluid hydrocarbon application which are classified as toxic and hazardous service. Flushing ring shall be provided with the diaphragm seal. Remote diaphragm seal with capillary shall be avoided for possible delay in response.
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SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
In differential pressure level measurement, diaphragm seal capillary length shall be limited to maximum of 3 meters to avoid slow response on the measurement. If capillary length more than 3 meters is required, Company’s approval shall be required. In applications where high process temperature or accessibility requirements preclude the usage of direct mounted diaphragm seal, remote seal may be used without any delay in response time or performance for the intended application. If differential pressure type transmitters with remote seals are specified, their capillaries shall be as short as possible and equal in length. Requirement of any insulation or heat tracing to counteract the effects of ambient temperature changes as recommended by Vendor.
All vents (including solenoid valve vents) shall be provided with bug screens for protection from insects. Bug screens provided shall not impede the functionality of the valve due to backpressure and shall be of suitable material to avoid bi-metallic corrosion.
All parts exposed to atmosphere shall be resistant to environmental wear. Cadmium plating is not acceptable.
Instruments in flammable or toxic service shall minimize leakage when exposed to fire. Low melting point metallic materials such as aluminium and brass shall not be used for the construction of pressure bearing, instrument body or retaining parts.
For “large” instruments containing toxic materials (i.e., those containing more than 100 cc of material at operating pressure) the drain shall be routed to a closed system. The vent, if any, for instruments containing toxic materials (i.e. more than 100cc of gas at operating pressure) should be directed to a closed system or to a safe location as determined by dispersion calculations.
Threaded process connection for transmitters and gauges shall be of NPT thread, tapered in accordance with ASME B1.20.1 and shall have 1/2” NPT as minimum. Pneumatic connections shall be 1/2” NPT or 3/8” NPT depending on the selected actuator size and type.
Electrical entries to instruments shall be M20 x 1.5 ISO internally threaded. Cable glands shall be Electro-less Nickel-Plated Brass material. To prevent water ingress, the cable entry point into a field mounted instrument or thermocouple head shall be from the bottom (or side) wherever practicable.
Field sensors, enclosures, elements and junction boxes connected to ESD shall be specially painted and/or tagged for easy identification that they are part of the SIF / ESD. Red colour is preferred for safety instruments and valve actuators. Valves and actuators paint colour shall be as per COMPANY’s painting specification, (Refer Sec 3.3).
Instrument manifold and fasteners (studs and nuts) used shall be same material of construction in order to avoid bi-metallic corrosion.
Refer to section 6.10 for material requirements.
7.2
Instrument Connections
Instrument isolation shall be as per Project Isolation Philosophy, Doc No: 200-20-PR-DEC- 00005 Isolation Philosophy (Green Facilities).
Material selected for all instrument fittings and or threaded connection accessories shall be similar or superior to the material of construction of the instrument.
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SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
All threaded connections shall be tapered in accordance with ASME B1.20.1. Process connections that are threaded shall have minimum 1/2 in. NPT internal threads, unless specified otherwise in datasheet.
Process-connected instrument enclosures that contain a single process seal shall be provided with additional means to prevent a single seal failure from allowing process fluids to propagate into the external electrical system.
The size of terminal blocks and screws shall be consistent with the wire size used with them. Spring-type terminals are unacceptable as they may weaken over time and result in a poor connection . Terminations shall be one of the types described below:
a) Captive screw terminal strips used with spade type wire ends, b) Modular (or stacked) snap-in terminal block assemblies of the screwed, pressure
clamp type,
In general, the following Table 6-1 below indicates the connection for different types of instruments:
Table 6-1 : Instrument Connection Summary
Instrument Type
Process
Instrument
Remarks
Isolation
Process
Valve Size
Connection
D/P flow transmitter
Size: 3/4”
1/2” NPT (F)
Magnetic Level Gauge
(on stand pipe/ vessel)
Level Displacer
(on stand pipe/Vessel)
D/P level transmitter
(remote seal)
Guided Wave Radar level
transmitter
(on stand pipe/ vessel)
Level transmitter
(on vessel, top mounted)
Size: 2”
2” Flanged
3/4” Flanged Drain/Vent.
.
Size: 2”
2” Flanged
3/4” Flanged Drain/Vent.
Size: 2”
2” Flanged
Size: 2”
2” Flanged
3/4” Flanged Drain/Vent.
4” Flanged
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
Pressure gauge
(on pipe and vessel)
Pressure Instrument
(with diaphragm seal)
Pressure transmitter/
D/P transmitter
(on pipe and vessel)
Size: 3/4”
1/2” NPT (M)
(On pipe)
Size: 2” (On
Vessel)
Size: 2”
2” Flanged
Size: 3/4”
1/2” NPT (F)
(On pipe)
Size: 2” (On
Vessel)
Thermowell
N/A
2” Flanged
(On pipe and
vessel)
7.3 Performance
All electronic transmitter / positioner shall meet the following performance requirements:
a) Maximum measurement error shall not exceed ±0.075 percent of span. Accuracy
shall include terminal-based linearity, hysteresis, and repeatability.
b) Long-term stability or drift performance shall not exceed ±0.20 percent of Upper
Range Limit (URL) per 10 years.
c) Output change caused by 50°F (28°C) ambient shift shall not exceed ±0.1125
percent of span.
d) A means for calibration of transmitters, indicators, and transducers shall be
provided to permit adjustment of the zero and the span of the output.
e) Electro-pneumatic transducers shall meet the following performance requirements.
•
•
Maximum measurement error shall not exceed ±0.25 percent of span.
Hysteresis and dead band shall not exceed ±0.06 percent of span.
8 ELECTRONIC TRANSMITTERS
Field transmitters shall be microprocessor based, smart, analogue electronic, 4-20mA HART protocol, 2 wire, 24VDC loop powered, with integrated LCD display or remote digital indicator, when the location of the transmitter precludes the view of the local display by the operator.
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
Only where HART protocol is not available, conventional 4-20mA DC instrument shall be used. Local indicators, except for Level instrument, shall have the scale in engineering units.
Transmitter shall be suitable and protected for use in offshore saline environment. All electronic printed circuits shall be protected against humidity and corrosion with appropriate anti-corrosion coating.
Transmitters installed indoor shall be designed to withstand Outdoor relative humidity, in order to accommodate the absence of HVAC during Construction / Pre-commissioning phase and any HVAC shutdown / failure after start-up with relative humidity.
Transmitter shall be capable of driving a load of 600 ohm maximum at 20 mA to overcome the loop resistance and any current limiting circuitry.
All transmitters shall be enabled for in situ or remote calibration/tuning, range changes etc. with a hand-held HART communicator. Quantity of HART Communicator shall be as per the Material requisitions of respective instruments.
Transmitters with 4-20mA output shall comply with NAMUR Recommendation NE043 enabling process under range and over range detection and sensor failure detection with upscale or downscale burnout selector switch. The fault detection configuration in ICSS shall match to the field equipment fault generation settings.
Smart transmitters shall have output analog signal operational between 3.8 mA to 20.5 mA, unless specified otherwise by COMPANY.
Transmitters shall have minimum SS316 housing.
All electronic transmitters which are exposed to direct sunlight shall be provided with UV resistant electrostatic free material Sunshades. Sunshade material shall be FRP / GRP.
Electrical cable entry shall be ISO M20 X 1.5. All unused openings on the field instrument shall be plugged with SS316 certified plugs.
Minimum SIL 2 rated transmitters shall be used for process measurements in ESD applications. All transmitters in safety applications shall have provision to turn off remote change of configuration parameters (e.g. from IAMS) using hard configurable switch settings in the transmitter. By default, remote configuration option for the safety transmitters shall be disabled physically in the field transmitter through appropriate switch setting.
Field transmitters shall be capable of interfacing with IAMS (Instrument Asset Management System) through HART pass-through IO installed in ICSS Cabinets or UCP/LCP. For package equipment IO which HART pass through Is not available shall be using IO multiplexers. VENDOR shall provide required configuration files such as DD, DTM etc. compatible with system.
2” pipe mounting brackets and mounting accessories for all remote mounted transmitters shall be provided. Material of construction for the mounting accessories shall be SS316.
9 PRESSURE INSTRUMENTS
9.1 General Requirements
API RP 551 shall be the basis for the selection & Installation of the pressure instruments. Where an API document describes a practice as “advisable” or “most common,” it shall be considered a COMPANY requirement.
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
A pressure instrument shall withstand the maximum pressure of the system to which it is connected; however, over-range protection, at least 1.3 times the maximum instrument range, shall be furnished for all instruments. Protection against full vacuum shall be required, if specified in data sheet. Scales and displays (local or remote) shall read in engineering units.
Ranges for pressure instruments shall be selected so that the normal operating point correlates to the middle third of the instruments full scale range. For readability, accuracy and control, a reading between 50 and 75 percent of scale is desirable
For suppressed-range applications, a full-range indication shall be installed in order to provide measurement while the pressure is below or above the suppressed range.
Proper materials or diaphragm seals shall be used to protect instruments from corrosive service or plugging.
9.2 Pressure Gauge
Indicating pressure gauges shall be liquid-filled, and in accordance with ASME B40.100. If liquid filled pressure gauges are unavailable for a certain range, gauges shall be dampened by other means.
Accuracy shall be Grade 2A. Liquid-filled gauges shall have a small vapor space for thermal expansion of the liquid fill. Vapor space shall be adequate to allow gauge to satisfactorily operate without leakage under the full range of ambient and process conditions specified. And where process temperature is higher than 65 ⁰C liquid filled gauges shall be mounted remotely.
Gauges shall be capable of passing the vibration test (A2.5) and the fatigue test (A2.8) specified in ASME B40.100, Nonmandatory Appendix A, “Some Definitions and Suggested Test Procedures Used to Measure New Gauge Performance.” A statistically meaningful percentage of all gauges sold shall be sampled to give a confidence factor of at least 90 percent.
The minimum dial size shall be 4” (100 mm). 6” (150mm) dial size shall be used for pressure gauges installed on vessel. Dial shall be white, non-rusting metal. Inscriptions shall be black figures and letters.
Process connection shall be 1/2 in. NPTM unless otherwise approved by COMPANY.
Pressure gauge measuring elements shall be the C-type seamless Bourdon tube-type.
Digital pressure gauges shall be used on installations that are susceptible to vibration.
All pressure gauges installed in hydrocarbon service shall be diaphragm seal welded type with flanged process connection. Diaphragm seal weld shall be full weld, tack welding is not acceptable. Bolted type Diaphragm seals shall not be used.
For Flanged diaphragm seals, DBB with mating flange shall be provided by Piping.
The measuring element shall be minimum hardened Type 316 stainless steel for used in utility service and for service using diaphragm seal. A Monel element is typically required in sea water service.
All accessories like gauge saver, snubber, gauge adapter etc. shall be same material of the gauge wetted part or as specified in respective data sheets.
The measuring element shall withstand over-ranging to a pressure 1.3 times the maximum scale reading without a permanent set that affects gauge calibration.
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
The pressure range of the Bourdon tube and the tube material shall be stamped on the socket.
The case shall be solid-front, weather-proof, and furnished with a blow-out back or blow-out disk. All cases shall be made of SS316. Other case materials require approval by COMPANY.
A visible stop pin shall be used to restrict the upper limit of the pointer travel. The stop pin shall be located at the 6 o’clock position on the gauge front.
Gauge window shall be double-strength shatter-resistant safety glass. The window shall be gasketed on the bezel side by means of a resilient gasket and held in place from the case side by means of a threaded retaining ring.
Fill fluids used in liquid-filled gauges shall be selected carefully, and account for both process and ambient temperature limits. Glycerine or silicone fill fluids shall not be used in applications involving strong oxidizing agents, such as chlorine, nitric acid, or hydrogen peroxide, because of spontaneous chemical reaction, ignition, or explosion. Instead, Fluorolube shall be specified in these cases. Fill fluid shall be reviewed and approved by COMPANY.
Gauge ranges shall be selected from the following series as defined in EN 837-1 so that the normal operating pressure is between 50 to 75% of scale.
For pressure above atmospheric:
0 – 1 barg
0 – 1.6 barg
0 – 2.5 barg
0 – 4 barg
0 – 6 barg
0 – 10 barg
0 – 16 barg
0 – 25 barg
0 – 40 barg
0 – 60 barg
0 – 100 barg
0 – 160 barg
0 – 250 barg
0 – 400 barg
0 – 600 barg
0 – 1000 barg
0 – 1600 barg
For vacuum services:
-1 – 0 barg
For combined pressure / vacumm services:
-1 – (+0.6) barg
-1 – (+1.5) barg
-1 – (+3) barg
-1 – (+5) barg
-1 – (+9) barg
Pressure gauges for severe pulsating services, such as reciprocating pumps and compressors, shall be dampened by means of snubbers.
Close-coupled siphons shall be used for hot condensable vapour service.
Set pointers shall be provided in all pressure gauges for operator care program.
Siphons shall be of 316 stainless steel as a minimum. Other exotic materials shall be used for critical fluid services
9.3 Pressure and Differential Pressure Transmitters
All pressure and differential pressure transmitters shall meet the following criteria:
a) Transmitters shall have negligible internal volumetric displacement.
b) Absolute, differential, and gauge pressure transmitters shall have two-way, three-way, four-way, or five-way manifold assembly as specified in datasheet.
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NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
All valve manifolds shall be provided with anti-tampered key.
Differential pressure instruments shall meet the following requirements:
a) Differential pressure instruments shall withstand direct or reverse over range that is equal to full static design pressure rating, without affecting calibration or having any zero shift.
b) Any output change caused by a change in static pressure equal to 100 percent
of pressure element rating shall not exceed 1 percent of span.
c) The means for transmission of forces or motion through the pressure holding parts shall be of the positive seal type, such as torque tube, bellows, diaphragm, or magnetic coupling. Magnetic coupling shall not, however, be used with differential pressure instruments.
d) Square root extraction for differential pressure flow meter shall be done at flow
computation device (e.g. ICSS, PLC, flow computer).
e) The length of diaphragm seal capillary shall be limited to 5 meters length without any degradation in performance. Usage of capillary with length more than 5 meters shall be approved by COMPANY.
10 FLOW INSTRUMENTS
10.1 General Requirements
API RP 551 shall be the basis for the selection & Installation of the flow instruments. All flowmeters shall be installed upstream of control valves.
Pressure-retaining parts of in-line flow instruments shall be fabricated with full penetration welds. These shall be in accordance with the requirements of ASME B16.5 and ASME B31.3.
For orifice flanges ANSI B16.36 shall follow.
Material requirements are as per stated in Section 6.10
Elements (e.g., Venturis and metering tubes) shall be designed in accordance with the Piping Material Specifications for the line in which the element will be installed.
All in-line flow elements shall have flanged ends suitable for the piping service. Flangeless devices are not acceptable.
Straight length requirement upstream and downstream of pipe shall be in accordance with relevant international code and standard (e.g. ISO 5167) and based on selected manufacturer recommendation
Where the pressure drop associated with a flow element needs to be minimized, the use of high-pressure recovery devices (e.g., Dall tube or a low-loss Venturi tube) may be considered.
Some devices, such as a Coriolis meter, cause a significant pressure drop and may cause cavitation or flashing in the meter and the downstream piping. If this is a concern, then back- pressure control or relocation of the meter to another part of the line shall be evaluated.
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COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
Any device that relies on a single diaphragm or bellows assembly to serve as the sole seal between the process fluid and atmosphere shall not be used in hydrocarbon and toxic services.
When a primary element is not covered by a consensus standard (API, ANSI, ISO, etc.), the manufacturer’s installation instructions shall be used, subject to COMPANY approval.
10.2 Flow Meter Selection
Due to high content of H2S, in line flowmeter shall be used for hydrocarbon service because they have lesser risk of leak compared with online meter which use impulse tubing. Ultrasonic flowmeter shall be the first-choice hydrocarbon gas service especially on the service when the pressure drop is to be kept minimal. Vortex meter may be used for hydrocarbon gas service for smaller size piping and accuracy of better than 2% are not required. Coriolis meter to be considered as first choice for liquid hydrocarbon service followed by ultrasonic and vortex meter.
Orifice or any other differential pressure type flow meter may be considered for utility service.
In general, flowmeter selection shall be as per Table 9-1 below.
e t a l P e c i f i r O g n i n o i t i d n o C
e n i b r u T
l a n o i t n e v n o C
r e t e
M
t n e m e c a l p s i D
e n i b r u T
l a c i l e H
e c i f i r O
l a r g e t n I
c i t e n g a M
e b u T
t o t i P
e c i f i r O
Custody Transfer
B B
B
B A1
Non-Custody Transfer
) n O
p m a l C
(
r a n o S
s s a M
l a m r e h T
c i n o s a r t l
U
A1
B
n o
p m a l C c i n o s a r t l
U
a e r A e l b a i r a V
e l z z o N
/ i r u t n e V
e n o C
r e t e
M g n i d d e h S x e t r o V
e g d e W
B
B
B
s i l o i r o C
B
A2
A1
B
A2
B A2
A1 B
A2 A2 B
A1
B
A2
B
A1
A1
B
A2
A1 B
A2
A1
A1
A1
A1
A1
A1
B
B
A2 B
B
B
B
B
B
B B
B
A2
B
B
B
B
B
A2
A2
B
B B
B B
A1 B
B
A2
B
A1
A2
B
B
B
A1 B
Application vs. Meter Type
Gas
Crude and Condensate
Chemicals
Fuel Gas
Flare Gas
Fouling Services
Gas Lift/Injection
High Pressure Water (exceeding 900# ANSI) Light Hydrocarbons (LPG, condensate, etc.)
Liquids, Re < 10,000
Oil (Re >10,000, gas free)
Other Dry Gas Applications
Produced Gas (Saturated)
Produced Gas (Wet)
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
e t a l P e c i f i r O g n i n o i t i d n o C
e n i b r u T
l a n o i t n e v n o C
r e t e
M
t n e m e c a l p s i D
e n i b r u T
l a c i l e H
e c i f i r O
l a r g e t n I
c i t e n g a M
e b u T
t o t i P
e c i f i r O
r e t e
M g n i d d e h S x e t r o V
e g d e W
a e r A e l b a i r a V
e l z z o N
/ i r u t n e V
e n o C
n o
p m a l C c i n o s a r t l
U
) n O
p m a l C
(
r a n o S
s s a M
l a m r e h T
c i n o s a r t l
U
A1
B
B
B
B A2
B
B B B A1
A2 B
A2 A1
B
A2 B
A2
s i l o i r o C
A1
A1
B
B
Application vs. Meter Type
Crude (e.g., leak det.)
Produced Oil and Two-Phase, < 10% GVF (e.g., Test and Production Separators Liquid outlets) Utility Gas (N2, Air, Blanket, Purge, Instrument, Starter, etc.)
Water
Legend:
Blank =
A1
A2
B
Not Recommended Preferred Choice Secondary Choice Third Choice
10.3 Ultrasonic Flowmeters (UFM)
The flow meter reliability and criticality shall be considered, along with the following, when selecting a UFM design and Manufacturer:
a) Transit time meters are preferred to Doppler type in accordance with ASME
MFC-5.1.
b) Meter bodies with transducers that may be replaced with the meter in service
shall be considered.
c) Multipath UFMs shall be used for custody transfer and flare applications.
The use of clamp-on UFMs is not allowed unless otherwise approved by COMPANY.
The UFM working velocity range shall be between 10 ft/s (3 m/s) and 70 ft/s (21 m/s), where the maximum velocity is at minimum pressure.
The meter accuracy shall be ± 1% of full scale.
Upstream/Downstream straight length requirements shall be based on the selected manufacturer recommendation.
UFMs in services above ANSI 600# shall be ordered without a pressure tap on the meter body, or if so supplied, with the pressure tap plugged but not seal-welded. For this service, a pressure transmitter shall be located on the meter run within five diameters downstream of the meter.
Liquid UFMs should not be installed where entrained gas exists or two-phase oil/water flow exists, where emulsions may interfere with transmission of the signal paths and on liquid streams at or near the bubble point (e.g., on production separators where the liquid outflow
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
from the separator is at the bubble point and foaming may occur). UFM should be installed upstream of the valve and as far apart as possible.
Flare UFMs shall be designed in compliance with API MPMS 14.10. Maximum wake frequency calculations shall be performed on insertion probes with the probes meeting the same criteria as for thermowells.
Transducer of the flare meter shall be retractable on-line (with the flare line in service).
Flare UFM shall be capable of sustained operation under the following conditions:
a) Over a wide dynamic measurement range (e.g. flow velocities ranging from 0.1 m/s during normal operation to 100 m/s during emergency blowdowns are commonly encountered).
b) At relatively low line pressures (e.g. the flare line is generally open to
atmosphere).
c)
In the presence of liquids within the flare line (e.g. as the result of liquid carry‐ over at high flow rates, liquid drop‐out under falling pressure or vapour emissions from sources that feed into the flare line).
d) In the presence of solid particulates within the flare line (e.g. under blowdown
conditions).
e) When installed on relatively large‐bore pipes (which are typically required to
accommodate occasional extreme flowrates).
Flare UFMs shall have total system uncertainty of 7.5%.
10.4 Vortex Flowmeters
The use of vortex flowmeters for high turndown or the possibility of low flow rates shall be avoided. The Reynold’s number should be greater than 20,000 at minimum flow rate. Signal cut-out or significant flow rate errors may occur for Re below 20,000, with cut-out or erratic signals probable for Re below 4,000. Manufacturer’s guide for low flow cut-off should be followed.
Sizing of the flow meter shall be by the VENDOR. Estimation of back pressure to avoid cavitation/flashing, shall be as per ISO 12764. The standard measurement practice shall be followed as per ASME MFC 6.
Vortex meters shall not be used for control or for low flow trips where loss of signal at low flow conditions is a probability. This includes process start-up and shutdown scenarios.
Vortex meters shall not be installed where pulsating flow or mechanical vibrations is possible.
The performance of the vortex flowmeter shall be as follows:
• Accuracy: ±2% of full scale or better
• Repeatability: ±0.25%
VENDOR shall ensure that the minimum cut-off flow of the flowmeter is less than the specified process minimum flow.
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
Upstream/Downstream straight length requirements shall be based on the selected manufacturer recommendation.
10.5 Coriolis Flowmeters
Coriolis flowmeters are available in two-wire and four-wire configurations. For ease of installation, a two-wire system is preferred.
Coriolis flowmeters design shall be in accordance with API MPMS 5.6 and AGA Report No.11, sizing shall be by VENDOR and submitted for COMPANY approval.
The accuracy of the coriolis flowmeter shall be ± 0.5% of full scale as minimum.
Coriolis flowmeters shall be calibrated at a recognized meter calibration facility or at Manufacturer’s facility prior to installation. If Manufacturer’s own meter calibration facilities are not used, then COMPANY approval of the selected facility is required.
The gauge pressure rating of the meter flow element (flow tube and flow splitters) shall be selected to be greater than or equal to the design pressure of the accompanying pipe system. However, in no case shall the minimum pressure rating be lower than 175 psig (12 bar). Manufacturer shall indicate the actual pressure rating of the flow meter on the tag plate.
The wetted meter flow element shall be hydrostatically or pneumatically tested per ASME B31.3. The duration of the pressure test shall take into account the possibility of small leaks between the pressure-containing portion and the outer enclosure.
The rupture disc of Coriolis flow meter shall be of same material of sensor wetted part material.
All Coriolis flow meters shall have flow direction marked on the sensor body. Coriolis flowmeters shall be installed in installed in upward or downward with respect to the direction of flow as per Vendor guidelines.
Meters shall be installed in a stable supported pipeline section. Coriolis meter needs to be installed where vibration is not envisaged or have less vibration as vibration might interfere with sensor tube excitations.
The Coriolis meter should be placed at least 5m away from industrial electromagnetic interference sources, such as large power motors, compressors etc.
If the Transmitter is remote mounted, Cable between the sensor and the transmitter shall be armored and shall meet the requirements of Specification for Instrument Cables and Cable Glands for COMP3 Project , Doc No: 200-51-IN-SPC-00057
For most applications, the outer enclosure of a Coriolis meter provides physical protection for the vibrating tubes and keeps moisture from affecting the operation of the drive mechanism and associated sensors. Meter shall be dual tube type with secondary containment tube.
The following requirements apply to the outer enclosure:
a) The integrity of the outer enclosure shall be proven via a hydrostatic or pneumatic
test per ASME B31.3.
b) If the maximum operating pressure (i.e., as limited by a pressure safety device) of the process fluid side of the meters is greater than the rated design pressure of the outer enclosure, then the outer enclosure shall be equipped with an relief device assembly.
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SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
10.6 Orifice Plates
Concentric orifice plates shall normally be used as primary elements as described in API RP 551, Section 6 or as required by applicable local regulations such ISO 5167.
The usage of orifice plates application shall be minimised for toxic hydrocarbon services to reduce possible leakage of fluid from the process connection/ fitting joints.
Orifice design, upstream and downstream straight length shall be as per latest ISO 5167 requirement.
Where the pipe Re is less than 10,000, a square-edge orifice plate shall not be used. In such services, the use of a quadrant-edge orifice, conical-entrance orifice, or wedge meter shall be considered. Eccentric orifice plates may be used on non-critical flow measurements when solids are present.
Minimum material shall be SS316L. Where the nature of the fluid may require a higher grade alloy or other material, that material shall be consistent with the applicable piping specifications and be subject to COMPANY approval.
For RTJ connection, orifice plate shall be female groove oval type. The plate thickness shall be as per ASME B16.36.
Orifice plates shall be sized to provide a reading between 60 and 80 percent of the scale when the flow is at its normal design rate. The beta ratio (orifice bore to pipe diameter) shall be between 0.20 to 0.60. However, beta ratio up to 0.70 are permitted with approval by COMPANY. The anticipated minimum and maximum flow rates shall be between 20% and 95% of the full-scale flow (maximum permissible turndown of 5:1). Rangeability higher than 8:1 is not recommended.
Orifice meter differential range shall be 50 mbar, 62.5 mbar, 125 mbar, 250 mbar or 500 mbar. Accuracy shall be better than ± 0.25% of span.
VENDOR shall provide sizing calculation sheets for the orifice plates. The sizing sheets shall also provide information of permanent pressure loss, plate thickness and noise calculation information.
Orifice plate thickness shall be the recommended value given in API MPMS 14.3.2, except that for NPS 6 and NPS 8 (DN 150 and DN 200) services above 750 ⁰F (400 ⁰C), the plate thickness shall be 1/4 in. (6 mm).
The minimum nominal pipe size for an orifice plate installation shall be 2 in. (50 mm). Where the process line size is less than 2 in. (50 mm), the line size shall be increased for the length of the metering run. If this is not possible, then an integral orifice or a prefabricated meter run shall be used.
Where a single orifice plate is used for flow measurement for both control and protective systems, a second set of taps on the orifice flange shall be used for the protective system.
Orifice plate fabrication shall include requirements of API RP 551. Drain or weep holes shall not be provided.
Pressure tapping for orifice plates shall be based on ISO 5167. For ring joint construction, the plate holder shall be a handle-type oval ring of pipe specification material. Unless prohibited by orifice fitting construction, all orifice plates shall have handles.
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SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
In orifice fittings that require seal rings, metal seal rings shall be used if possible. This bears special emphasis in high pressure applications where compression of rubber or teflon rings may result in orifice plate movement.
10.7 Integral Orifice
Integral orifices may be used for line sizes smaller than NPS 2 (DN 50) subject to COMPANY approval.
Integral orifices shall follow ASME MFC 14M. Sizing calculation shall be by manufacturer.
Integral orifices come in standard pipe sizes of 0.5 in. (12.7 mm), 1.0 in. (25.4 mm), and 1.5 in. (38.1 mm). For these meter sizes, the orifice bore may range from 0.010 in. (0.25 mm) to 1.184 in. (30.07 mm). Due to these very small clearances, the use of these devices in dirty services should be avoided and the use of strainers should be considered.
Accuracy of the Integral Orifice with the transmitter shall be ± 2 % of flow rate or better.
10.8 Conditioning Orifice Plate
Conditioning orifice plates are recommended in lieu of traditional orifice plates when insufficient upstream piping is available to meet the straight run requirements and will cause flow profile issues.
Conditioning orifice plates shall be used only in applications where the measurement accuracy is not critical.
The beta ratio (d/D) for a conditioning orifice is determined using the sum of the area of the four bores. This beta is equivalent to the area of a bore “d” in the standard equation “beta = d/D” for a standard orifice meter. Thus for a given beta, each bore diameter of a conditioning orifice is equal to half the bore diameter of a standard orifice.
Beta ratios between 0.4 and 0.65 are recommended.
A conditioning orifice shall be centered in the pipe (the same as a traditional orifice plate). A conditioning orifice shall be installed such that its orientation has the taps located perpendicular between two of the four holes (bottom taps shall be avoided).
10.9 Pitot Tube / Averaging Pitot Tube
Pitot tubes or averaging Pitot tubes may be used in applications that require minimum 10 in. (250 mm) or larger pipe sizes where conventional flow elements would be very expensive to fabricate, and may not be cost justified, subject to COMPANY approval.
A Pitot tube or averaging Pitot tube shall not be used in an application where dirty streams or streams containing solids are found.
Opposite-end support shall be provided.
An on-line retraction assembly should be considered to allow for on-line maintenance. Retraction assembly shall be provided with isolation valve, safety chain and extension fittings.
Accuracy of the pitot tube with the transmitter shall be ± 1.6 % of flow rate.
Upstream/Downstream straight length requirements shall be based on the selected manufacturer recommendation.
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10.10 Venturi Tubes
Venturi tubes shall be used where high pressure recovery is necessary or where only low inlet pressure is available. Venturi tubes shall be preferred to measure suction flow of compressors.
Venturi Tube shall be used in applications were available permanent pressure loss is very low.
Venturi tubes shall be constructed in accordance with the requirements of ISO 5167-4 latest edition, except that unless otherwise specified, only one pressure tapping shall be provided for upstream and one for downstream measurement.
Venturi tubes shall be Classical Venturi (or Herschel) with machined convergent section and with a maximum divergent angle of 14° and provided with single taps each for upstream and downstream, unless otherwise specified.
Bore / Throat diameter shall be in “mm” only and shall be rounded off to the nearest 0.1 mm for values up to 25 mm and to nearest 1 mm above 25 mm
“Beta” ratio (β) shall be chosen to be within 0.4 and 0.7 for gas, vapour or steam and within 0.3 and 0.7 for liquids, to minimise uncertainties.
Meter maximum flow shall be selected so that the normal design flow is about 70 % of scale, while at the same time the maximum design flow shall be at about 90 % of scale.
Accuracy of the Venturi along with the transmitter shall be ± 1 % of full scale.
Where minimizing pressure drop is important, the use of high-pressure recovery devices (e.g., Dall tube or a low-loss Venturi tube) may be considered.
Venturi tube applications require Re of 75,000 or more, as this is the region where their discharge coefficient (C) is relatively constant.
Upstream/Downstream straight length requirements shall be as per ISO 5167.
10.11 Variable Area Flowmeters
The use of variable area flowmeters shall be restricted to applications such as low flow conditions, measurement of purge, cooling, chemical injection or sealing fluids.
In some circumstances it may be necessary, when all other types of measurement have been considered and found unsuitable, to consider variable area meters for applications other than those mentioned above.
The meters shall have a metal metering tube, with a pressure rating which is compatible with the maximum process conditions.
Variable area flowmeters shall be made of metal. When flow rates are lower than cannot be measured with a metal tube, a glass tube with a heavy-duty flat glass protective enclosure may be used.
Connections NPS 1/2 and larger shall be flanged as per ASME B 16.5. Connections smaller than NPS 1/2 (15 mm) shall have an internal taper thread.
The Manufacturer’s standard tube and float shall be used wherever possible. Normal flow shall be between 60 and 80% of capacity, provided that anticipated minimum and maximum flow rates will be between 10 and 90% of capacity.
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Flow measurement accuracy shall be better than 2% of full-scale flow over a rangeability of 10% to 100%.
The meter coefficient and design conditions shall be engraved permanently on the nameplate and/or tube.
Variable area flowmeters shall be hydrostatically tested to 1.5 times the meter pressure rating at 38 °C.
Variable area flowmeters with integral needle valves shall not be used in hydrocarbon and toxic services.
Variable area flowmeters shall be magnetically coupled local indication with 0-100% scale in flow units. The scale shall have black numerals in white background.
When required, the variable area flowmeter shall has transmitter option where it could provide 4 to 20mA output as indicated in the datasheet.
The pressure drop across the meter is essentially constant over the full rangeability 10:1 operating range. Pressure drop shall be within range of allowable pressure drop as specified in datasheet.
Metal tubes and wetted parts shall be SS316L as minimum. Wetted parts shall be compatible with the process fluid and shall be suitable for the design conditions.
Variable area flowmeters shall be installed vertically, unless otherwise specified in the associated Instrument datasheet.
Variable area flowmeters shall have flanged bottom and top connections. The flange size and rating shall be as indicated in the datasheets.
10.12 Flow Nozzle
Flow nozzles are used for high pressure application, so it has more pressure loss than the venturi tube.
Construction materials of nozzle elements shall be in accordance with Piping Service Classes and Materials Specification and throat shall be coated with better material to protect from corrosion & erosion of process fluids.
Pressure taps shall be at the inlet & outlet of nozzle for measuring the differential pressure through DP transmitter.
Flow nozzle shall be constructed in accordance with the requirements of ISO 5167-3 latest edition.
Flow nozzle element type shall be as per ISA 1932. And beta ratio 0.3 to 0.8 shall be used.
The upstream and downstream tappings shall be corner tappings.
Preferred differential pressure range is 2500 mmWC. However, 5000 mmWC up to 10000 mmWC shall also be considered if unavoidable.
Accuracy shall be ± 2 % of span.
For 3:1 rangeability of Flow Nozzle shall be used.
Upstream/Downstream straight length requirements shall be as per ISO 5167.
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10.13 V-Cone Flowmeters
V-Cone flowmeters will be used for measurement of high pressure liquid, wet gas and high pressure gas flow streams.
V-Cone meter shall be based on principle of differential pressure measurement.
V-Cone meter shall be sized for a differential pressure range of 250 mbar corresponding to meter maximum flow, and other differential ranges to be followed 500 mbar subject to COMPANY approval.
Accuracy of V-Cone meters shall be ± 0.5% of full-scale flow as minimum.
For 10:1 rangeability V-Cone meters shall be used. Two sets of pressure tapping shall be provided for flow rangeability exceeding 10:1.
The d/D (Beta) Ratio shall be between 0.3 and 0.7 and Reynolds number shall be ≥200,000.
V-Cone flowmeter and its accessories shall be suitable for design pressure and design temperature specified in the datasheet.
Upstream and downstream straight length requirements for V-Cone shall be in accordance with manufacturer recommendation.
The design of the cone shall not allow any areas of stagnation where debris, condensation, or particles from the fluid could accumulate. V-Cones meter have no moving parts, which results in very little maintenance requirements.
10.14 Magnetic Flowmeters
Magnetic flowmeters shall be used in applications where the fluid has minimum 5 µS/cm of conductivity and a minimum fluid velocity of 0.5 m/sec.
As the flow tubes of most magnetic flow meters are lined, appropriate liner material shall be selected for compatibility with the process fluid to be measured. Polytetrafluoroethylene (PTFE) and polyurethane shall be used for liner materials.
Electrode material shall be Hastelloy suitable for seawater application and rated pressure and temperature conditions as specified in datasheet.
To avoid interference with measurement, flow meter shall not be installed near high process noise or vibration environment.
Flow meters shall be factory wet-calibrated prior to installation and assigned a factory set calibration factor.
The pipe should be filled with liquid at all times, and piping layout shall be designed to avoid an empty or partially filled pipe condition.
Grounding rings or connections shall be provided for meters to ensure proper grounding to the plant electrical ground. The grounding ring material shall be compatible with the process fluid (same as the electrode material).
Flowmeter accuracy shall be ±0.50% of span.
A low-flow cut-off shall be provided and configurable. The cut-off shall be factory configured to the lowest flow rate measurable at the desired accuracy.
Electromagnetic flow meters shall be integral type with transmitter, unless otherwise specified as remote type in datasheet. Remote signal Converter/ transmitter shall be suitable for remote
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mounting and separately mounted from the meter with interconnecting coaxial cable from sensor electronics.
Upstream/Downstream straight length requirements shall be based on the selected manufacturer recommendation.
10.15 Turbine Flowmeters
Turbine flowmeters shall not be used for custody transfer of gas.
Design, construction, installation, and calibration of turbine meters shall be in accordance with API MPMS 5.3. Turbine flow elements should be provided with back-pressure controls, or other means should be provided to prevent damage by over-speed during start-up.
All turbine meter applications shall be calibrated for an ReD range equal to that of the application wherever possible. Where this is not possible, COMPANY shall approve the use of an alternative, such as a composite calibration curve.
Calibration curves shall be provided for each turbine flowmeter. Flows shall range from the maximum meter design flow downward to the point at which required accuracy is no longer attainable.
Flowmeter accuracy shall be better than 2%.
Turbine flowmeters shall be equipped with two pickup coil hubs.
For service at or below 600# ANSI, the flow conditioner and meter run shall be the same nominal pipe diameter as the meter and have a welding neck, raised-face flange at either end, sized and rated as defined in the data sheet. The meter-to-meter run flange shall provide a smooth internal diameter transition and shall be internally aligned and doweled in a minimum of three places to ensure this alignment.
When specified by COMPANY for high-accuracy applications, the flow-conditioning element shall comply with API MPMS 5.3. The element type selected shall be installed per Manufacturer’s recommendations.
Turbine flowmeters shall have strainers installed upstream of the meter.
11 LEVEL INSTRUMENTS
11.1 General Requirements
API RP 551 shall be the basis for the selection and installation of level devices.
Instruments shall be
Level CONTRACTOR/COMPANY
in accordance with
the Level Sketches provided by
In general, pressure/temperature rating of level instruments and gauges shall be equal to or greater than the pressure/temperature rating of the vessel to which they are connected.
Pressure retaining welds on all instruments shall be full penetration welds and shall be in compliance with the requirements of ASME B31.3.
Devices containing mercury shall not be used in any level application.
Variation in fluid properties during start-up, shutdown, and special operations shall be considered and fully addressed during instrument selection. If the shift in properties is too
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great to be covered by a single technology, diversity shall be employed to cover the full range of operation.
Perforated stilling-well shall be provided for internal top mounted type level instruments like displacer, guided wave radar, radar etc. The well shall be open-ended, drilled, or slotted along its entire length; and shall have a smooth interior finish.
The use of a bridle (standpipe) assembly to reduce the number of vessel connections is acceptable for other than ESD level transmitters.
Shut-down devices shall be mounted on nozzles dedicated for their use only. Where separate level measurement exists for control and shutdown, level transmitters measuring the same process variable shall have identical centre to centre length and range. Bridle (standpipe) shall not be less than NPS 2 (50 mm), Schedule 80 pipe for carbon steel or NPS 2 (50 mm), Schedule 40 pipe for stainless steel.
For interface applications additional nozzle shall be provided.
Level Instrument external chamber connection shall be flanged type and side mounted. External chamber shall be designed and constructed to ASME B31.3 as applicable.
Dedicated isolation valves shall be provided for each level Instrument. Top mounted level Instrument do not require isolation valve.
Material of construction for level chamber shall be minimum SS316 for utility service and Inconel 625 or Hastelloy C for hydrocarbon service. Stilling well shall be minimum SS316.
Remote digital indicators shall be supplied where instruments are located at height or not easily visible by operators to assist field personnel.
Two independent level measuring instruments based on different operating principles shall be provided for each pressure storage vessel.
11.2 Magnetic Level Gauges
Magnetic type level gauges are preferred for most services but in particular for the services listed below, glass gauges shall not be used.
a) All clean services
b) Cryogenic services
c) Fluids that attack glass (e.g., strong acids, alkalis, boiler feed water)
d) Light ends services
e) Toxic services
f) Pressures above 500 psig (3,450 kPa)
g) Temperatures above the auto-ignition point
Technologies other than magnetic type level gauges shall be considered for fluids with significant entrained solid particulate matter.
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Level gauges shall be of sufficient length to provide complete coverage of the range of the associated level instrument, including all control, alarm, and protective level functions.
Level gauges shall be hydrotested to 1.5 times the process design pressure by the Manufacturer prior to shipment. The Manufacturer shall include the hydrotest documentation with shipment.
For magnetic type gauges, the float shall be selected so as to withstand the highest expected process and mechanical damage due to rapid level fluctuations.
11.3 Continuous Level Instruments
For measurement ranges up to 48 in. (1200 mm), the following devices are preferred:
a) Guided Wave Radar (GWR).
b) Differential pressure type instruments.
For measurement ranges greater than 48 in. (1200 mm), the following devices are preferred:
a) Guided Wave Radar (GWR).
b) Differential pressure type instruments.
c) Ultrasonic devices may be used with approval by the COMPANY.
For interface level measurement, the following devices are preferred:
a) Guided Wave Radar (GWR).
b) Vertically installed capacitance or RF Level Probe may be used with approval by the
COMPANY.
Ultrasonic level transmitters shall not be used in foamy applications.
Vertically installed capacitance or RF level probes shall have a coating suitable for the application. Capacitance probes for single point level indication shall be mounted horizontally.
11.3.1 Guided Wave Radar (GWR)
Guided wave radar is based on Time Domain Reflectometry (TDR) technology.
GWR are independent of the liquid density and hence may be used on fluids with varying density but will require accurate specification of the dielectric constant. Use of GWR on viscous coating waxy media shall be avoided.
The GWR shall be fitted with NPS 2 (50 mm) flanges and the flange type and joint shall be in accordance with Piping Material Specifications.
Dielectric values of the fluids shall be greater than 1.4. In interface level applications, low dielectric fluid must be on top and the two liquids must have a dielectric difference of 10 or greater to avoid measurement errors.
General design preference is for single, rigid, co-axial probes. Probe length greater than 3 ft (1 m) and less than 10 ft (3 m) will need a centering disk. Selection of other probe designs or length greater than 10 ft (3 m) must be approved by the COMPANY.
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The large diameter co-axial probe shall be considered first whenever the application and dimensions of the chamber allow for it. Large diameter coaxial probes offer the strongest return signal and have no upper dead zone and a very small lower dead zone.
The GWR probe shall be installed directly on top of vessel in a stilling well or in external chambers similar to displacer level instruments and must not touch the wall of the chamber or the bottom of the chamber.
11.3.2 Differential Pressure Type Instrument
Differential pressure transmitters are preferred for the following services, External displacer types are not considered acceptable alternatives:
a) Services below −58⁰F (−50⁰C).
b) Slurry services or viscous or waxy fluids: these services require remote seal units with flush or extended diaphragm seals. Flange mounted differential pressure transmitters are preferred.
c) Services where liquids boil at ambient temperature conditions: the transmitter shall normally be located above the vessel taps. Some applications may require that the transmitter be mounted below the vessel taps and the legs to the transmitter be sealed with a liquid heavier than the liquid in the vessel.
d) Special installations that require purged or flushed taps: these installations require
approval by the COMPANY.
A suppression or elevation adjustment shall be supplied for differential type instruments in level service. Suppression or elevation shall be adjustable when the instrument is in service and under pressure. Adjustment of the elevated-zero and suppressed-zero range shall be at least 100 percent of the maximum transmitter upper range value.
If differential pressure type transmitters with remote seals are specified, their capillaries shall be as short as possible (limited to 3 metres) and equal in length. The capillaries shall be provided with insulation or insulation and heat tracing to counteract the effects of ambient temperature changes. Remote seals shall be provided with flushing ring to flush the diaphragm to avoid fouling the seal diaphragm chamber and connecting piping.
11.3.3 Displacer Level Transmitter.
Use of displacer level transmitter shall be avoided as far as possible.
The minimum range and connection spacing for an external displacer type instrument shall be 14 in. (350 mm).
Connections for external displacer type instruments shall be NPS 2 (50 mm) minimum size, flanged and the flange type, and joint shall be in accordance with Piping Material Specifications.
Preferred connection configurations are either top-side/bottom-side or top-side/bottom. When top-side and bottom-side connections are specified, the mating pressure vessel level instrument connections shall be constructed by use of a “Jig Fit” (a fabrication template used to attach nozzles to vessels and prevent warping during welding).
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External displacer instrument chambers shall be provided with tapped NPS 3/4 (20 mm) vent and/or drain connections in the same centreline as the chamber as appropriate and shall be gate or ball type valve. However, for top connected displacers, a NPS 3/4 (20 mm) valve vent connection shall be made in the top connecting line, adjacent to the chamber. This vent connection must also be suitable to be used as a fill connection to allow on line testing of float switches when they are in protective system service.
Rotatable head construction is required for external displacers.
Standard displacer lengths shall be used.
For displacers or floats subjected to turbulence, provisions shall be made for shielding the connections or guiding the fluid to eliminate the effect of turbulence on the torque tube or float shaft assembly.
12 TEMPERATURE INSTRUMENTS
12.1 General Requirements
For general temperature measurement and control, RTD shall be the preferred choice for primary sensing elements. For the flare stack, dual thermocouples shall be used. All sensors shall be wired to field mounted transmitters. The choice of element selection would be based on temperature range and/or accuracy.
Temperature measurement systems shall be compensated for ambient temperature variations and shall be protected for a maximum temperature over-range.
Critical temperature elements such as in process heater, flare tip temperature measurement service, bearing temperature and winding temperature measurement as well as in application where online temperature element replacement is not possible, shall be provided with dual sensing elements.
Tip-sensitive elements shall be provided with a mechanical means of ensuring a solid thermal connection with the thermowell tip (spring loaded, compression fitting, etc.).
In general, temperature transmitter shall be supplied as a complete unit compromising, thermowell, measuring device (RTD/thermocouple), union coupling and connection head etc.
12.2 Thermowell
The design of each thermowell shall be checked using the calculation methods for thermowell frequency, fatigue stress, and pressure, described in ASME PTC 19.3 TW latest revision, to ensure that wake-frequency-induced vibration will not result in thermowell failure. Wake frequency calculation shall be provided as part of hand over material to COMPANY.
The fluid velocity used in these calculations shall be the maximum velocity possible that could occur in the pipe based on both normal and abnormal operation of the facility. Calculations shall include consideration of abnormal operation such as startup and shutdown or a control valve failing wide open. If a thermowell is used for a check temperature measurement and is routinely left empty, then the thermowell calculations shall be performed with the sensor included and excluded to ensure that the frequency shift does not cause the thermowell to operate in a resonance condition.
For pipe-mounted thermowells, immersion length (measured from inside wall of pipe) shall be selected such that the tip is located around one-fourth of the pipe diameter and does not
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exceed 10 in. (25 cm) insertion length unless the maximum velocity rating of the thermowell requires a shorter length.
For process vessels, thermowell immersion length shall not exceed 10 in. (25 cm) unless otherwise specified in datasheet. Longer lengths used for tanks with negligible fluid velocities are permitted with COMPANY approval.
VENDOR standard lengths shall be used to the maximum extent possible. The use of velocity collars as a means to reduce fluid-velocity-induced vibration is prohibited.
Thermowells shall use 2” flange-mounted process connections as per ASME B16.5 for both installation on Piping and vessels / tanks. Screwed thermowells shall be avoided. Socket weld thermowells shall not be used, except for atmospheric storage tanks with approval by the COMPANY.
Selection of thermowells with features considered standard in the industry shall be the basis of specification. These features include the following:
a) NPTF ½” internal connection (for transmitter connection)
b) 6.6 mm (0.260 in) bore diameter
c) OD—straight taper from 11/16 in. (27 mm) OD at the base of thread (or point of
flange attachment) to a minimum of 5/8 in. (16 mm) at the tip.
d) Tip Thickness—1/4 in. (Nominally 6 mm) minimum.
e) The minimum pipe size for thermowell installation is NPS 4 (100 mm). For NPS 3 (75 mm) or smaller piping, 4” spool piece shall be provided for installation of the thermowell.
f) Thermowells in erosive service shall have heavier wall and tip thicknesses. Thermowells shall taper from 11/16 in. (27 mm) OD at base of the thread to 7/8 in. (22 mm) at the tip. Tip thickness shall be 5/8 in. (16 mm).
Material of Thermowells shall be in line with Piping Material Specifications, with minimum SS316L material. For recommended materials, Inconel 625 for hydrocarbon applications and Monel 400 for sea water applications. Also, Inconel 625 shall be used for CRA cladded steel pipe.
All Thermowells shall be machined from solid bar stock. Flanges shall be full penetration weld. Van stone style thermowells shall not be used. The flange shall be designed as per ASME B16.5.
Temperature transmitter shall be provided with sufficient length head extensions where applicable e.g. for insulated area, high temperature application. Extension lengths shall be sufficient to ensure electronic sensor or termination head is outside insulation and to ensure transmitter design temperature is not exceeded.
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12.3 Resistance-Type Detector
RTD elements shall be a metal-sheathed, mineral-insulated, nominal 100 OHM platinum with class A, ungrounded, three-wire configuration, unless otherwise specified. It shall conform to ASTM E 1137/E 1137M or IEC 60751.
4 wire RTD shall be used for application where high accuracy is required, such as custody transfer measurements and machine monitoring applications.
RTD should only be used for temperatures up to 650°C.
Dual platinum RTDs, if specified, shall be provided with one of the RTDs terminated locally and available as a spare.
12.4 Thermocouple
Thermocouple shall be Type T or Type K, Metal-sheathed, mineral-insulated, thermocouple assemblies with the measuring junction at the tip electrically isolated from the metal sheath, as per API RP 551, Section 5.3.2.2. The minimum diameter of the sheath shall be 6 mm (1/4 in). Minimum wire size shall be 20 AWG (0.5 mm2).
For the temperature range 0⁰F to +2,000⁰F (−20⁰C to +1,090⁰C), the preferred thermocouple material is chromel-alumel (Type K, per API RP 551), unless other types of material (such as Type J) are required to connect to existing equipment. Thermocouple extension wire connected to Type K thermocouples shall be Type KX. Use of any other type of thermocouple or extension wire material requires approval by the COMPANY.
Any Type K (chromel-alumel) thermocouples used for gas turbine exhaust temperature monitoring or actuation of exhaust temperature shutdowns shall be pre-aged. If pre-aged devices are not available, then VENDOR shall state in the proposal any re-calibration requirements after start-up to ensure accuracy of these thermocouples’ output signals so that maximum turbine output power may be attained.
For the temperature range −300⁰F to +200⁰F (−185⁰C to +95⁰C), the preferred thermocouple material is copper-constantan (Type T). Thermocouple extension wire connected to Type T thermocouples shall be Type TX.
The tolerances of the thermocouples shall be class 1 as per IEC 60584-1.
12.5 Temperature Transmitter
Head mounted temperature transmitters shall be used for all applications with thermocouples or RTDs. In special cases such as high temperature and/or vibration, transmitter shall be remote mounted type based on the ambient/surrounding temperature at tapping point location.
Remote transmitter shall be supplied with LCD display in engineering unit. Mounting brackets and accessories in stainless steel shall be provided by the transmitter VENDOR.
Transmitter shall have built-in cold junction compensation for thermocouple inputs.
12.6 Temperature Gauge
Temperature gauge type shall be Bimetallic, provided with thermowell and with 360-degree adjustable head.
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The case material shall be 316 stainless steel, hermetically sealed and external calibration adjustment (zero), with high impact resistance shatterproof glass. Ingress protection shall be IP66.
Stem material shall be stainless steel 316L.
Accuracy class shall be Class 1 as per EN 13190.
Overtemperature limit shall be 30% of full scale.
The diameter of the case must be 4” diameter, white background with black characters and graduate degrees Celsius (°C) scale.
The thermometer stem length shall exceed the thermowell length and the stem shall be secured in the thermowell with a compression fitting.
Dial thermometer ranges shall be selected from the following series so that the normal operating temperature is between 50 to 75% of scale:
-40 – (+60) °C 0 – 100 °C
0 – 160 °C
0 – 250 °C
0 – 400 °C
13 FIRE AND GAS DETECTORS
13.1 General Requirements
The design requirements for the fire and gas detectors shall be in accordance 200-20-SH- DEC-00013, Technical Safety Basis of Design (Offshore) For COMP3 Project.
Fire and gas detectors, except smoke and MAC shall be 24VDC, 0-20mA HART protocol, 3 wire loop powered from FGS cabinet. Only where HART protocol is not available, conventional 0-20mA DC instrument shall be used.
Detectors lens shall be able to prevent fogging of the lens. The detector shall also be capable of identifying fault, calibration modes and any other diagnostic status and generate the applicable status and alarms via the 0 – 4mA range and HART signals.
All indoor and outdoor F&G detectors shall be connected to platform FGS. All the F&G detectors shall be suitable for use in FGS system.
The enclosure material of the outdoor fire and gas detectors shall be SS316. Each unit shall be weatherproof to IP66 as minimum.
All electronic printed circuits shall be protected against humidity and corrosion with appropriate anti-corrosion coating, including for detectors installed Indoor.
All detectors installed Indoor shall be designed to withstand Outdoor relative humidity, in order to accommodate the absence of HVAC during Construction / Pre-commissioning phase and any HVAC shutdown / failure after start-up with relative humidity.
Fire and gas detectors shall be selected and calibrated to respond as fast as reasonably practicable.
During maintenance, fault repair on loops shall consist of replacing only the faulty detectors. It shall not affect other sensors in the loop.
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
All detectors shall be suitable for easy on-site calibration/ test. Permanent and easy access to all fire and gas detectors shall be provided for periodic testing, and where necessary provided with tubing to access floor level for gas detectors.
Equipment shall be installed to minimize interference from Electro Magnetic Interference (EMI) or Radio Frequency Interference (RFI) as per standard IEC 61000 part 1 to 6.
All detectors shall be listed for gas detection service by Underwriters Laboratories (UL), Factory Mutual (FM), European Committee for Electrotechnical Standardization (CENELEC), or Company-approved equivalent, unless otherwise agreed to by COMPANY.
All detectors shall be minimum SIL 2 certified.
VENDOR shall supply all appropriate devices, accessories and special tools required for proper operation, weather protection, mounting, installation, maintenance, calibration, and testing of each detector.
Detectors shall be provided with weather shield to protect from direct sunlight and rainwater droplet. Sunshade shall be provided for all F&G detectors that are exposed to direct sunlight.
All detectors shall be supplied with mounting accessories like mounting brackets, stainless- steel screws etc. in SS316.
The calibration and test accessories kits supplied for gas detectors shall include as a minimum, Pressure Gauges, gas cylinders containing the calibration gas for respective type of detection (i.e. flammable, hydrogen and toxic gas and flexible tubing and sensor adapter.
For Instruments installed at higher elevations and in non-easily accessible locations, Vendor shall supply remote testing and calibration tools like tubes and extension poles etc.
13.2 Fire Detection
13.2.1 Smoke Detector
Photoelectric (optical) smoke detectors shall be used for indoor fire detection. Smoke detector shall be UL/FM certified. Offshore platforms shall utilised non addressable type smoke detector.
Each smoke detector shall generate an alarm. When a smoke detection system is arranged to actuate shutdown or extinguishing system, it shall be set in a 2ooN voting array.
Non-addressable smoke detectors shall be 2-wire, normally open DPDT contact with a supply voltage of 24V DC loop powered from FGS. An EOL resistor shall be provided for line monitoring.
Detector shall be designed for continuous detection of smoke. VENDOR shall offer universal detectors for all types of smoke ranging from smouldering to open fire smoke as well as for solid and liquid combustibles; with visible and invisible smoke particles. Design shall be as per NFPA72 recommendations, however, electrical parts shall be compliant to IEC.
Smoke detectors shall have an integrated LED on each detector unit indicating an alarm condition. Remote LED indicator shall be provided and shall be installed at visible location for the smoke detectors installed in the false floor to indicate the status of smoke detection.
All single detectors shall generate an alarm. When smoke detection systems are installed to actuate shutdown or extinguishing systems, they shall be arranged with a cross-zoning or voting array.
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
Detectors shall be supplied with appropriate surface mounting and accessories with base. Required marking shall include item tag number, model, manufacturer, serial no., approval authority, type of protection, etc. Nameplate material shall be stainless steel.
Each indoor unit shall be weatherproof to IP42.
Smoke detector shall be Exd certified. Ex’i’ version can be provided if Ex’d’ certified is not available. For smoke detectors located within pressurized safe area rooms (LQ, LER, CCR, SWGR rooms, etc), it shall be of general purpose type, rated for Safe Area use (non- classified), in accordance with 200-20-SH-DEC-00013, Technical Safety Basis Of Design (Offshore) for COMP3 Project
Detectors shall be insensitive to steam from accommodation shower cubicles.
Local status indicator shall be provided and installed to the nearest wall for the hidden smoke detectors in false flooring/ceiling void.
13.2.2 Heat Detector
Heat detector shall be of rate compensated type detector. However fixed type heat detector can be used in LQ area e.g. galley.
Heat detector installed in hazardous area (e.g. battery room) shall be Ex’d with IP 66 and SS316 enclosure.
For heat detectors located within pressurized safe area rooms (LQ, LER, CCR, SWGR rooms, etc.), it shall be of general purpose type, rated for Safe Area use (non-classified), in accordance with 200-20-SH-DEC-00013, Technical Safety Basis Of Design (Offshore) for COMP3 Project .
13.2.3 High Sensitivity Smoke Detector (HSSD)
HSSD shall be aspirating type smoke detection to be considered for all electrical, switchgear, Instrument Room and Telecom Room. The HSSD system shall aspirate from within the control cabinets.
HSSD shall be interfaced with FGS for fire detection, alarms and fault signals.
Reset of the detector shall be from the front of HSSD panel.
HSSD shall be installed in wall mounted panel, to be supplied together with other panel’s accessories e.g. circuit breakers, terminal blocks and sampling tubings. Panel shall be min IP 42.
Cable entry to panel shall be M20 x 1.5.
Refer to Specification for High Sensitivity Smoke Detection System, Doc no ; 200-83-IN-SPC- 00005 for detail requirement.
13.2.4 Flame Detector
Triple IR flame detectors shall be used to detect fires from multiple fuels, including methane and methanol.
Flame detectors shall be selected according to the types of fuel that have been identified at the facility and nature of fires.
Flame detectors installed in gas turbine enclosures shall be arranged to avoid temperatures above the rated maximum for the detector.
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
Triple IR flame detectors shall be UL/FM certified. The detectors are to be installed in the production area.
Detector shall be automatic resetting type.
Flame detectors shall be sited according to VENDOR’s recommendation. Flame detectors shall be placed such that their view of the area they are covering is not obstructed.
Each unit shall be designed for continuous detection. Cone of vision shall be 90° as minimum. Sensitivity shall be adjustable between 18 m, 13 m, 9 m and 5 m to a 0.09 m2 (1 ft2) of gasoline fire. Response time shall be approximately 2-5 seconds to a 0.09 m2 (1 ft2) of gasoline fire at 18 m. Sensitivity charts shall be provided by the VENDOR.
Each unit shall include a self-testing feature. Flame detectors shall be highly immune to humidity, arc welding, lightening and vibration. Flame detector shall be provided with weather shield to protect from direct sunlight and rainwater droplet. Weather shield shall be installed in such that the detector’s vision is not affected.
Flame detectors shall be able to prevent fogging of the lens and subsequent faults. The detector shall also be capable of identifying the dirty window and to generate alarm via HART signals or through different current levels below 4 mA.
Detectors shall not create false alarms to solar interference, or plant lighting.
13.2.5 Manual Alarm Call Point (MAC) & Manual ESD Push Button
Manual alarm call points (MAC) shall be strategically located at or near building doorways and exits on escape routes. MAC shall be lift flap, push-and-stay pushbutton type with local key manual reset. MAC shall be suitable for wall / surface or 2” pipe mounted.
Outdoor MACs’ shall be PULL Lever type. SS Key type or Hammer / chain shall not be used, considering corrosive environment.
MAC break glass type shall be used only for Indoor areas.
Non-addressable type MAC shall be used for offshore platforms and they shall be connected to platform FGS.
Manual alarm call points shall be located throughout the platform so that they are unobstructed and readily accessible in the normal path of exit from the area.
MAC housing material shall be UV resistant glass reinforced polyester for indoor and SS316 for outdoor unit. MAC shall be “Red” in colour for fire alarm and “Blue” in colour for general alarm.
MAC shall be 2-wire, normally open DPDT contact with a supply voltage of 24V DC, contact rating 1A. An EOL resistor shall be provided for line monitoring.
MAC installed in hazardous area shall be Ex’d.
Similar specification of outdoor MAC shall be used for outdoor manual ESD push button. The ESD push button shall be “Yellow” in colour.
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
13.3 Gas Detection
13.3.1 Flammable Gas Detector (Point Type)
Infra-red type Flammable gas detectors shall be considered for use in process and utility areas, HVAC air intakes, combustion air inlet and outlet of Gas Turbine enclosure.
The response time of IR point type gas detectors shall be T50% < 5 secs and T90% < 10 secs. Zero drift shall be less than 2% over two years.
The sensor shall have a long-term stability (drift) of ±3% LFL every year a measurement range from 0-100% of LFL to minimize the required maintenance.
Detector shall be immune to solar interference, heat, moisture changes and general climatic changes.
Detector shall be 3-wire with a supply voltage of 24V DC. Detector signals for normal operation shall be 4-20mA with HART corresponding to a measuring range of 0 – 100% LFL. Detector shall be automatic resetting type.
For detectors that are mounted on duct, a duct mounting kit shall be provided. The kit shall comprise a sampling probe in the duct system, calibration nozzle, remote calibration terminal box, complete with duct mounting accessories. All material used for the duct mounting kit shall be SS316.
13.3.2 Hydrogen Gas Detector (Point Type)
Hydrogen gas detectors shall be UL/FM certified, suitable for installation inside Battery Rooms.
Hydrogen gas detectors shall be catalytic type. Response time of the hydrogen gas detector shall be T50% < 10secs (with 0% ~ 100% LEL).
Detector shall be automatic resetting type.
The Hydrogen gas detectors are required shall be installed in the battery room.
The calibration and test accessories kits supplied for the detectors shall include as a minimum, Pressure Gauges, gas cylinders containing the calibration gas (H2-Air Mixture), one with 20% LEL & 50% LEL concentrations respectively and Flexible tubing and sensor adapter.
13.3.3 Toxic Gas Detector (Point Type)
An automatic toxic gas detection system shall be installed to monitor those parts of the facilities where toxic gases (H2S) may inadvertently accumulate (creating incipient gas hazard conditions) and to alert personnel to the existence and location of the condition.
Toxic gas detectors shall incorporate Electrochemical Cell sensing technology. Sensor life shall be of 2 to 3 years.
The response time of toxic gas detectors shall be T90% < 30 secs. Zero drift shall be less than 5% per year.
Detector measuring range shall be of 0 – 50 ppm.
The following information shall be provided for COMPANY approval, prior to selection of toxic gas detectors:
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
- The guaranteed detector/indicator control unit response, i.e., Linearity,
Repeatability, Drift.
- Data plotted against time, so that the system behaviour during the first few
seconds after release of the sample is clearly distinguishable.
- Substantiated approval data available from a national approval or testing
authority.
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Information on the behaviour and recovery of the proposed system after exposure of the detector to twice the full range of the sensor for the specified gas.
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A minimum shelf life in excess of 24 months is required. VENDOR shall preferably meet a minimum warranty period of 36 months of satisfactory device operation without a mode failure which leads to cell replacement.
13.4 Visual and Audible Alarm
13.4.1 Beacon
Beacon shall be high intensity xenon type strobe light. Beacon shall be 24VDC and connected to PAGA. Upon detection of an alarm condition, visual alarm or flashing beacon shall be initiated from the FGS. It shall also be possible to manually initiate Flashing beacons, Toxic Gas Alarm, General Platform Alarm from the PAGA system.
Beacon shall be installed at noisy area and all corners of the platform walkways &, bridges.
Beacon enclosure material shall be SS316 and red epoxy painted. Lens material shall be toughened glass and lens colour shall be as follow:
• Red: for Fire Alarm (RP3S, RP5S, RP9S ); General Alarm and Abandon
Platform Alarm (WHP13N, RP5N, RP6N )
• Blue: for Toxic (H2S)/ Flammable Gas Alarm (RP3S, RP5S, RP9S )
• Amber: for abandon Platform Alarm (RP3S, RP5S, RP9S)
• Yellow: for Toxic (H2S)/ Flammable Gas Alarm (WHP13N, RP5N, RP6N)
Flashing rate shall be of 60 flashes per minute.
The beacons shall be supplied with all mounting accessories like mounting brackets, and stainless-steel screws etc.
13.4.2 Sounder
Upon detection of an alarm condition, sounder shall be initiated from the FGS through a PAGA. Alarm signal shall be sent to PAGA from Fire and Gas system upon detection of fire and/or gas.
Sounder shall have a sound pressure level of 118 dBA at 1m distance.
Housing material shall be SS316, painted in red with epoxy finish. Installation of the sounder shall be surface mounted and possible to be orientated.
The sounders shall be supplied with all mounting accessories like mounting brackets, and stainless steel screws etc.
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
14 MISCELLANEOUS INSTRUMENTS
14.1 Corrosion Probes & Fittings
14.1.1 General
Access fitting system design shall be in line with Corrosion Management and Monitoring Manual Doc. No. 200-20-CE-PRC-00001 and material selection shall be as per “Material and Corrosion Requirement in Sour System” Doc. No. 200-20-CE-SPC-00002. Mechanical design type is not acceptable.
Corrosion probe shall be installed on horizontal runs of pipe, in 6’o clock position. Consideration shall be given to the required length and weight of the extraction equipment.
Corrosion Probe shall be removable during line pressurized condition and shall include required accessories same shall be designed for the maximum anticipated pressure rating.
All corrosion probes shall utilize access fittings of a common size (usually DN 50 or NPS 2) and model to allow for interchange within the facility.
A specimen of test material to be used in a corrosion test, usually a metal strip or ring shaped to fit into a testing cell or between joints of drill pipe. Rings, or coupons, are weighed before and after exposure, and weight loss is measured. They are also examined for pits and cracks. Corrosion products are analyzed to define the type of corrosion reaction.
14.1.2 Electrical Resistance Probes (ERP)
Corrosion Probe shall be Electrical Resistance High Resolution Metal Loss Type.
Electrical resistance probes may be used to measure corrosivity of both conductive and non- conductive liquids and vapors. The recommended type is the flush high-pressure element type. The probe element seals shall be selected/designed in such a way as to avoid any preferential crevice attack at the steel element/potting compound interface.
ERP corrosion probe sensor shall be of high sensitivity design (250-micron sensor thickness). Resolution shall be of 0.1 % ranges 0-1%, 1-10%, 10-100% of full scale.
The probe installation shall be suitable for corrosion measurement at bottom of line. Corrosion probe shall be installed on pipeline with access fitting which will facilitate the removal of probe in online using retrieval tool when the pipeline in pressurized condition. Vendor shall supply all the required tools and accessories for the online retrieval of probes under pressure.
Wake frequency calculation to be performed by Vendor for all corrosion probes in flow lines.
Incase of Wake frequency failure, Vendor shall propose alternative solutions.
14.1.3 Data Logger
Data logger shall be supplied for all corrosion probes. Data logger shall be battery powered and suitable for the hazardous area mentioned in section 6.4. Data logger enclosure shall be SS316.
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
Vendor shall supply any special tools, Handheld communicators and software required for the configuration and data transfer from Data logger. Handheld communicators if any, shall be suitable for Hazardous area operation.
14.2 Acoustic Solic Particle Detector (Sand Monitoring)
Acoustic Solid particle detectors shall be of non-intrusive type and shall measure the solid particle production at the flow lines. The rate of solid particle production will be calculated in DCS based on the flow line flow rate and acoustic detector signal input to DCS.
Algorithm to be defined by Acoustic Solid Particle Detector Vendor and implemented in DCS. Vendor shall advise Laptop requirement for configuration of sand particle detectors.
Acoustic Solid particle detector signal will be connected to DCS and shall be smart 4-20mA output superimposed with HART protocol (revision 7 or latest), 2 wire, 24VDC loop powered. However, Vendor shall advice the requirement of external 24VDC if loop powered is not available.
Vendor to advise the Maintenance and calibration requirement for the Acoustic Solid Particle detector and
Acoustic solid particle detectors shall be Ex ‘d’ flameproof certified.
Mounting brackets and accessories in stainless steel shall be provided by the Acoustic solid particle detector VENDOR. Acoustic Solid Particle Detector Device should be painted. VENDOR shall provide all recommended mounting requirements and as a applicable markings applied to piping.
Acoustic solid particle detector shall be flexible to mount and shall be flexible to transfer or shift to other wells/lines. VENDOR to advise possibility to move Acoustic Solid Particle Detector with cable connection facility.
15 INSTRUMENT INSPECTION AND TESTING
Instrument inspection and testing requirements shall be as per approved ITP and FAT procedures wherein VENDOR shall provide resources and materials to facilitate COMPANY/ EPC Contractor
inspection services, factory acceptance testing and site testing of all systems. This shall include but not be limited to: engineering personnel, multi-meters, signal generators, simulation test panels and etc.
All Field instruments shall be subjected to test and inspection.
A comprehensive series of tests known as the Factory Acceptance Tests (FAT) shall be witnessed by COMPANY / EPC Contractor at the VENDOR staging area.
For packaged equipment with own unit control panel/package control system, integrated-FAT (IFAT) with ICSS shall be carried out prior to the shipment of the panels to site. Prior to the actual FAT, VENDOR shall carry out pre-FAT and pre-FAT report shall be provided to EPCC Contractor / COMPANY.
Inspection and test plan shall be submitted by VENDOR for EPC Contractor / COMPANY approval.
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
16 DOCUMENTATION
A complete documentation for Instrumentation and Controls shall be provided for the entire PROJECT. The documentation shall be consistent and provide accurate information.
All engineering and design documents produced shall clearly identify the Instrument and Control components and indicate the relevant interfacing discipline information e.g. process data (operating data, design data), piping data (size, rating, material), electrical data (UPS, power cable definition), etc.
Following deliverable related to COMPANY CMMS shall be provided in COMPANY’s template and format:
-
Equipment Database (EQDB)
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Bill of material (BOM)
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Spare Parts List (SPL)
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Special Tools
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Operating Supplies (Lubes and Chemicals)
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Maintenance manual
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Installation and Operating Manual
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Preservation procedure
17 PACKING, SHIPMENT AND PRESERVATION
The requirements for packing and preservation of field instruments, including loose shipped items, are detailed in the protection, packing and marking instructions provided as part of contract documentation.
FAT final approval and closure of all punch items will allow shipment of the equipment.
When the instruments arrive at site it may be possible that they will be kept in the stores for several days prior to installation. Hence care should be taken for protecting the necessary parts of the instruments from getting exposed to the adverse environmental conditions.
A preservation procedure and packing list shall be submitted to COMPANY for review before the shipment take place.
18 SPARE PARTS AND SPECIAL TOOLS
18.1 Spare parts
The VENDOR shall recommend the number, type and storage conditions required for initial and operation spare parts and shall supply insurance and commissioning spare parts, as per project requirements.
The spares shall be managed via Spare Parts and Interchangeability Record (SPIR) process.
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Classification: Internal
NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT
COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT
SPECIFICATION FOR FIELD INSTRUMENTATION (INCL. FLOW, LEVEL, PRESSURE AND TEMPERATURE INSTRUMENTATION & F&G DETECTORS) FOR COMP3 PROJECT
18.2 Special tools
As part of the scope, VENDOR shall provide any special tools, which are necessary for assembly, dismantling, testing of the instruments during erection, pre-commissioning, operation and maintenance.
In addition to the software provided to run the PLC and HMI, VENDOR shall provide all software and licences to be used to develop application and/or operator interface (if any), this also applies to simple field local operator interface.
19 TABLE SUMMARY
Table No
Description
Table 5-1
Sea Water Temperature
Table 5-1
Unit of Measurement
Table 6-2
Instrument Connection Summary
Table 9-3
Table for Flowmeter Selection
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Project: Q-32705 - Saipem COMP3 Folder: RFQ Files