Classification: Internal

NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT

COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT

COMPANY Contract No.: LTC/C/NFP/5129/20 CONTRACTOR Project No.: 033764

ASSET

: NFPS

Document Title

:

MATERIAL SELECTION PHILOSOPHY FOR COMP3 PROJECT

COMPANY Document No.

:

200-20-CE-DEC-00006

CONTRACTOR Document No.

:

033764-B-D00-18-SPM-MA-S-00001

Discipline

: CORROSION ENGINEERING

Document Type

: DESIGN CRITERIA

Document Category/Class

:

1

Document Classification

:

INTERNAL

00 29-APR-2025 Approved for Construction

B

A

26-MAR-2025

Issued for Approval

13-JAN-2025

Issued for Review

Arif Zainal Prin. M&C Engineer

Ajitpal Sekhon Lead M&C Engineer

Reetesh Kumar Eng. Manager

Arif Zainal

Ajitpal Sekhon

Reetesh Kumar

Prin. M&C Engineer

Lead M&C Engineer

Eng. Manager

Ajitpal Sekhon

Viswanathan V.

Reetesh Kumar

Lead M&C Engineer Sr. Prin. M&C Engineer

Eng. Manager

REV.

DATE

DESCRIPTION OF REVISION

PREPARED BY

REVIEWED 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.

200-20-CE-DEC-00006 _00

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MATERIAL SELECTION PHILOSOPHY FOR COMP3 PROJECT

REVISION HISTORY

Revision

Date

Revision Description

A1

10-DEC-2024

Issued for Inter Discipline Check

A

B

13-JAN-2025

Issued for Review

26-MAR-2025

Issued for Approval

00

29-APR-2025

Approved for Construction

HOLDS LIST

Hold No

Hold Description

nil

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MATERIAL SELECTION PHILOSOPHY 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

INTRODUCTION … 6

Project Objective … 6

Project Scope … 6

DEFINITIONS AND ABBREVIATIONS … 9

Definitions … 9

Abbreviations … 10

REGULATIONS, CODES AND STANDARDS … 12

Company Documents … 12

Project Documents … 13

Contractor Documents … 13

International Codes and Standards … 14

PURPOSE … 16

SCOPE … 16

Table 5-1: Field Platform List … 16

6

6.1

6.2

6.3

KEY DESIGN PARAMETERS … 16

Design Life … 16

Environmental Data … 17

Reservoir Fluid Contaminations … 17

6.3.1 CO2 & H2S Concentration … 17

Table 6-2: CO2 and H2S Concentration for RGE, RGA and QG2 … 17

6.3.2 Produced Water … 18

Table 6-3: Produced Water Properties … 18

6.3.3 Sand and Solid Particles … 19

6.3.4 Other Contaminants … 19

7

BASIS OF MATERIAL SELECTION … 19

7.1 Material Selection Process … 20

8

MATERIAL CONSIDERATION… 20

8.1

Carbon Steel … 20

8.1.1 Carbon Steel for Sour Service … 21

8.1.2 Corrosion Allowances … 21

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8.2

Corrosion Resistant Alloys … 22

8.2.1 Stainless Steels … 22

8.2.2 Nickel Alloys… 24

8.2.3 Copper Nickel Alloys … 24

8.2.4 Titanium Alloys … 25

8.3

Non-metallic Materials … 25

8.3.1 FRP/GRP … 25

8.3.2 Elastomers and Thermoplastics … 26

8.4

Fasteners … 26

Table 8-2: Recommended Fastener Materials … 26

8.5

8.6

8.7

9

Instrument Tubing and Fitting … 28

Grating and Ladders … 28

System Specific Material Requirements … 28

DEGRADATION THREATS … 30

9.1

Internal Corrosion … 31

9.1.1 CO2 Corrosion … 31

9.1.2 H2S & CO2 Corrosion … 31

9.1.3 H2S Related Corrosion Cracking … 32

9.1.4 Chloride Stress Corrosion Cracking (CSCC) … 34

9.1.5 Pitting and Crevice (Localized Corrosion) … 34

9.1.6 Microbiologically Influenced Corrosion … 35

9.1.7 Under Deposit Corrosion … 35

9.1.8 Erosion and Erosion Corrosion … 36

9.1.9 Galvanic Corrosion… 36

9.1.10 Oxygen Corrosion … 37

9.1.11 Preferential Weld Corrosion … 38

9.1.12 Liquid Metal Embrittlement … 38

9.2

External Corrosion … 39

9.2.1 Atmospheric Corrosion … 39

9.2.2 External Chloride Stress Corrosion Cracking … 40

9.2.3 Corrosion Under Insulation … 41

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9.2.4 Corrosion Under Pipe Support (CUPS) … 42

9.3 Mechanical Degradation … 42

9.3.1 Low-temperature Embrittlement … 42

9.4

10

Degradation of Non-Metallic Materials … 43

Appendices … 45

10.1 Appendix 1 ECE 5.8 Corrosion Prediction Modelling Basis … 46

10.1.1 Applicability of ECE 5.8 Corrosion Modelling for NFPS … 46

10.1.2 Assumptions for ECE 5.8 Corrosion Rate Calculation … 48

10.2 Appendix 2 The Effect of H2S in ECE 5.8 Modelling … 49

10.3 Appendix 3 Service Limitation for Elastomers and Thermoplastics … 50

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MATERIAL SELECTION PHILOSOPHY 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:

1. Investment #1: Drilling and Associated Facilities [WHP12S/ WHP13S/ WHP14S/

WHP12N/ WHP13N]

2. Investment #2: Trunk line Looping and Intra-field pipeline looping [32” PL1LN, 32”

PL1LS, 38”PL610LS]

3. 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 this 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.

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

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MATERIAL SELECTION PHILOSOPHY FOR COMP3 PROJECT

• 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 PL5S 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” CS PL9 to WYE on existing 38” trunkline PL48 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 Power & Control modifications, LQ6S/LFP (East)/BVS (East)- FO Tie-in 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 • Hook-up and brownfield modification at WHP12S/ RP9S/ RP4S Composite cable tie-in,

Spurline riser installation at RP4S RGA Power & Control modifications.

Facilities – 4B

• 2 subsea composite Cables from CP8S to RP11S & from RP8S to RP11S (with J-tube),

FO Cable from RT2 to Barzan WHP1.

• New Fuel Gas 8” CRA Spur-lines and flanged risers from Subsea skid to RT2.

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MATERIAL SELECTION PHILOSOPHY FOR COMP3 PROJECT

• 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) • New Fuel Gas 8” CRA Spur-lines and flanged risers 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.

• Decommissioning at topside existing and In-situ abandonment of existing Topside/subsea

Composite Cables RT-WHP2S, RT-WHP3S, Topside/Subsea FO cable RT-BRXWHP1.

Figure 1.2.1: NFPS Compression Project COMP3 Scope

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MATERIAL SELECTION PHILOSOPHY FOR COMP3 PROJECT

2 DEFINITIONS AND ABBREVIATIONS

2.1 Definitions

Definition

Description

COMPANY

Qatargas Operating Company Limited.

CONTRACTOR

Saipem S.p.A.

DELIVERABLES

FACILITIES

MILESTONE

PROJECT

SITE

All products (drawings, equipment, services) which must be submitted by CONTRACTOR to COMPANY at times specified in the contract. All machinery, apparatus, materials, articles, components, systems and items of all kinds to be designed, engineered, procured, manufactured, constructed, supplied, tested and permanently installed by CONTRACTOR at SITE in connection with the NFPS Project as further described in Exhibit 6.

fabricated,

A reference event splitting a PROJECT activity for progress measurement purpose.

COMP3 - NFPS Offshore Riser/Wellhead Platform & Intrafield Pipelines Project

(i) any area where Engineering, Procurement, Fabrication of the FACILITIES are being carried out 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

The person, group, or organization responsible for the design, manufacture, testing, and load-out/shipping of the Equipment/ Material.

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2.2 Abbreviations

Code

Definition

American Petroleum Institute

American Society of Mechanical Engineers

American Society for Testing and Material

Bottom of Line

British Standard Institution

Bulk Water Corrosion

Corrosion Allowance

Carbon Equivalent

Corrosion Inhibition

Corrosion Resistant Alloy

Carbon Dioxide

Carbon Steel

Chloride Stress Corrosion Cracking

Corrosion Under Insulation

Copper Nickel Alloy

Corrosion Under Pipe Support

Duplex Stainless Steel

European Standard

Explosive Decompression

Front End Engineering Design

Fibre-Reinforced Plastic

Glass-Reinforced Plastic

Heat Affected Zone

API

ASME

ASTM

BOL

BSI

BWC

CA

CE

CI

CRA

CO2

CS

CSCC

CUI

CuNi

CUPS

DSS

EN

ED

FEED

FRP

GRP

HAZ

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MATERIAL SELECTION PHILOSOPHY FOR COMP3 PROJECT

Code

Definition

H2S

H&MB

HIC

ISO

LAS

LCCA

LME

LQ

MDMT

MIC

NACE

NFPS

PREN

PWC

QG-2

RGE

RGA

RLIC

SCC

SDSS

SLC

SRB

SOHIC

SS

Hydrogen Sulphide

Heat and Material Balance

Hydrogen Induced Cracking

International Organization for Standardization

Low Alloy Steel

Life Cycle Cost Analysis

Liquid Metal Embrittlement

Living Quarter

Minimum Design Metal Temperature

Microbiologically Influenced Corrosion

National Association of Corrosion Engineers

North Field Production Sustainability

Pitting Resistance Equivalent Number

Preferential Weldment Corrosion

Qatargas 2

RasGas Expansion

Ras Gas Alpha Complex

Ras Laffan Industrial City

Stress Corrosion Cracking

Super Duplex Stainless Steel

Service Life Corrosion

Sulfate Reducing Bacteria

Stress Oriented Hydrogen Induced Cracking

Stainless Steel

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MATERIAL SELECTION PHILOSOPHY FOR COMP3 PROJECT

Code

Definition

SSC

SWC

TOL

TSA

UV

WHP

Sulfide Stress Cracking

Stepwise Cracking

Top of Line

Thermally Sprayed Aluminium

Ultraviolet

Wellhead Platform

3 REGULATIONS, CODES AND STANDARDS

In general, all design activities shall confirm to legal and statutory regulations and recognized industry best practices. 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 Procedures, Policies and Standards (Exhibit 5 Appendix I)

c) Project Specifications.

d) Industry Codes and Standards

e) COMPANY and CONTRACTOR’s Lessons Learned

If CONTRACTOR/SUBCONTRACTOR 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/SUBCONTRACTOR shall not proceed with any deviation to the specifications without prior COMPANY approval. In general, all design activities shall conform to legal and statutory regulations, and recognized industry best practices.

The following is a list of relevant regulations, codes, standards, specification, Company documents that shall be considered for the Project in the order of precedence listed above.

3.1 Company Documents

S. No

Document Number

Title

1. 560-20-PR-DEC-00001

Process Design Basis-RGE Complex

2. 640-20-RP-DEC-00001

Process Design Basis-QG2 Complex

3. 200-20-CE-REP-00001

NFPS Compression Project FEED - Erosion Study Report

4. 200-20-PI-SPC-00013

NFPS Compression Project FEED Specification

• Piping Material

5. 200-20-CE-SPC-00001

NFPS Compression Project FEED - Painting Specification

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MATERIAL SELECTION PHILOSOPHY FOR COMP3 PROJECT

3.2 Project Documents

S. No

Document Number

Title

200-20-PR-DEC-00051

RGE Process Design Basis For Comp3 Project

200-20-PR-DEC-00052

QG2 Process Design Basis For Comp3 Project

200-20-PR-DEC-00053

RGA Process Design Basis For Comp3 Project

200-20-PR-DEC-00054

Process Design Criteria For Comp3 Project

200-20-CE-SPC-00025

200-20-CE-REP-00008

Specification For Topsides Material & Corrosion Requirements For Sour Service For Comp3 Project Material Selection Report For Fixed Facilities For Comp3 Project

200-20-PI-SPC-00044

Piping Material Specification For Comp3 Project

200-20-CE-SPC-00027

200-20-CE-SPC-00028

200-53-CE-SPC-00005

Specification For Fixed Facilities Protective Coating For Comp3 Project Specification For Thermally Sprayed Aluminium Coating For Comp3 Project Specification For Cathodic Protection For Greenfield Jacket Structure For Comp3 Project

200-20-CE-SPC-00029

Specification For Thermal Insulation For Comp3 Project

200-20-CE-SPC-00033

200-20-CE-SPC-00032

200-20-PI-SPC-00045

Specification For Weld Overlay For Piping Materials For Comp3 Project Specification For Welding Of Pressure Vessels For Comp3 Project Specification For GRE Pipes, Fittings And Flanges For Comp3 Project

200-20-PI-SPC-00046

Specification For Pipe Fasteners For Comp3 Project

200-20-CE-SPC-00026

Specification For Elastomer And Thermoplastic Selection For Comp3 Project

200-20-PI-SPC-00042

Piping Support Standard Specification For Comp3 Project

3.3 Contractor Documents

S. No

Document Number

Title

Not Applicable

Not Applicable

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3.4

International Codes and Standards

S. No

Document Number

Title

23. API RP 14E

NACE MR0175/ISO 15156 (All parts)

ISO 14692 2017 (All parts) NACE TM 0192

27. NACE TM 0169

28. NACE Paper No. 06122

29. NACE Paper No. 09564

30. NACE Paper No. 5718

31. NACE TM0284

Recommended Practice for Design and Installation of Offshore Product Platform Piping System, Year 2019, 5th Edition Petroleum and Natural Gas Industries- Materials for Use in H2S- Containing Environment in Oil and Gas Production (including the latest technical circular), Year 2020, 4th Edition Petroleum and natural gas industries - Glass -reinforced plastic (GRP) piping, 2017, 2nd Edition Evaluating Elastomeric Materials Decompression Environment, 2012 Chemical Resistance of Polymeric Materials by Periodic Evaluation, 2021 Weight Loss Corrosion with H2S: Using Past Operations for Design Future Facilities Weight Loss Corrosion with H2S: From Facts to Leading Parameters and Mechanisms H2S+CO2 Corrosion: Additional Learnings Experience Evaluation of Pipeline and Pressure Vessel Steels for Resistance to Hydrogen - Induced Cracking, Year 2016

in Carbon Dioxide

from Field

ASM Handbook Volume 13B

Corrosion: Materials

33. DNVGL-RP-O501

Managing Sand Production and Erosion, Year 2021

34. NACE TM0177

35. ASTM A193/A193M

36. ASTM A194/A194M

37. ASTM A276/A276M

38. ASTM A320/A320M

39. ASTM A479/A479M

40. ASTM B637

Laboratory Testing of Metals for Resistance to Sulfide Stress Cracking and Stress Corrosion Cracking in H2S Environments, Year 2016 Standard Specification for Alloy-Steel and Stainless Steel Bolting for High Temperature or High Pressure Service and Other Special Purpose Applications, Year 2022 Standard Specification for Carbon Steel, Alloy Steel and Stainless Steel Nuts for Bolts for High Pressure or High Temperature Service, or Both, Year 2020 Standard Specification for Stainless Steel Bars and Shapes, Year 2017 Standard Specification for Alloy-Steel and Stainless Steel Bolting for Low-Temperature Service, Year 2022 Standard Specification for Stainless Steels Bars and Shapes for Use in Boilers and Other Pressure Vessels, Year 2021 Standard Specification for Precipitation-Hardening and Cold Worked Nickel Alloy Bars, Forgings, and Forging Stock for Moderate or High Temperature Service, Year 2018

41. ASTM F467

Nonferrous Nuts for General Use, Year 2018

42. ASTM F468

Standard Specification for Nonferrous Bolts, Hex Cap Screws, Socket Head Cap Screws, and Studs for General Use, Year 2016

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S. No

Document Number

Title

43. API STANDARD 6ACRA

44. BS EN 10269

45. NACE Paper No. 128

46. NACE Paper No. 577

47. NACE Paper No. 05648

48. CAP 437

49. NACE TM0316

Age-hardened Nickel-based Alloys for Oil and Gas Drilling and Production Equipment, Year 2022 Steels and Nickel Alloys for Fasteners with Specified Elevated and/or Low Temperature Properties, 2013 Influence of Liquid Flow Velocity on CO2 Corrosion: A Semi- Empirical Model Predictive Model for CO2 Corrosion Engineering in Wet Natural Gas Pipelines Corrosion Prediction and Materials Selection for Oil and Gas Producing Environments Standards for Offshore Helicopter Landing Areas, Year 2018, 8th Edition Four-Point Bend Testing of Materials for Oil and Gas Applications, Year 2016

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4 PURPOSE

The purpose of this document is to define the material selection philosophy to be adopted for North Field Production Sustainability (NFPS) Compression Project.

5 SCOPE

This document is applicable to all the process and utilities facilities (piping system and equipment) installed at RGE, RGA and QG2 complex for NFPS Compression Project COMP3.

The following table provides the details of the applicable assets for each field.

Table 5-1: Field Platform List

Field

Green Field RP5S RP9S

RGE

RGA

QG2

RP3S

WHP13N RP6N RP5N

Brown Field WHP5S RP7S WHP9S RP4S WHP8S WHP11S RP8S WHP3S RT-2 WHP4N RP4N WHP5N WHP6N

All brownfield related modifications as part of the Project shall meet or exceed the requirements of this Specification after due consideration of the asset integrity of existing components and systems unless with approval from COMPANY.

Material Selection Philosophy for Fuel Gas Spurlines and Intrafield pipelines are discussed in Corrosion Assessment And Material Selection Report For Intrafield Pipelines And Spurlines For Comp3 Project (200-20-PL-REP-00007).

6 KEY DESIGN PARAMETERS

This section outlines the key design parameters that shall be considered in corrosion assessment and material selection.

6.1 Design Life

The new facilities shall be designed for an operational life of 30 years [1,2,6,7,8].

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6.2 Environmental Data

The following offshore environmental data in Table 6-1 shall be considered [1,2,6,7,8].

Table 6-1: Offshore Environment Parameters

PARAMETER

Yearly ambient temperature (°C)

Black bulb temperature (°C)

Relative humidity (%)

MIN MEAN MAX

8.3

—

37

—

—

71

45.6

85

100

6.3 Reservoir Fluid Contaminations

The NFPS offshore facilities are to be designed to cope with the range of expected well fluid compositions for the following investment phases:

• Pre-compression in Near term

• Post-compression in Near and Long term

Corrosion assessments shall consider pre-compression and post-compression phases including fluid compositions.

6.3.1 CO2 & H2S Concentration

The reservoir fluid contains CO2 and H2S. For material selection purpose, the design CO2 and H2S concentration shall be considered for RGE, RGA and QG2 Complex as provided in Table 6-2 [1,2,6,7,8].

Table 6-2: CO2 and H2S Concentration for RGE, RGA and QG2

FACILITIES

Compression Platform (Topside)

Notes

ACID GAS CONCENTRATION

RGE

RGA

QG2 (3)

CO2

H2S

5.4 mol %

2.5 mol %

5.4 mol %

4.1 mol %

1.0 mol %

3.5 mol %

(1) The design CO2 and H2S concentration include some margins to account for reservoir

uncertainties, higher than process simulation values from the H&MB cases. This shall be the basis for the new facilities material selection, sour service classification, and corrosion calculation.

(2) H2S / CO2 concentration is only valid for new facilities associated with compression and is

not applicable for existing platforms/facilities and onshore facilities assessment work.

(3) The specified H2S are based on sensitivity concentration.

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6.3.2 Produced Water

Composition of produced water for compression facilities design consideration is shown in Table 6-3

[1,2,6,7,8].

Table 6-3: Produced Water Properties

WATER COMPOSITION

PARAMETER

Total Dissolved solid

Chloride

Formate

Acetate

Propionate

pH

Sodium

Potassium

Calcium

Magnesium

Dissolved iron

Strontium

Sulfate

Dissolved H2S/Sulfides

Dissolved CO2

Note:

UNITS

mg/L

mg/L

mg/L

mg/L

mg/L

mg/L

mg/L

mg/L

mg/L

mg/L

mg/L

mg/L

mg/L

mg/L

VALUE

54,000

30,000

<100

500

20

Note (1)

5,187

339

11,676

1,848

100

348

72

Note (1)

Note (1)

(1) Water pH, dissolved H2S/sulphides/CO2 vary depending on pressure, temperature, and fluid composition. Sensibility range shall be provided for the considered factors for variations in temperature and pressure.

A total of 30,000 mg/L chloride content in produced water shall be considered for compression facilities to cater for potential future increase of chloride at platform level [1,2,6,7,8]. In addition, 500 mg/L of organic acid (acetate) reported in the produced water analysis shall be considered as well in the corrosion assessment for compression facilities.

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6.3.3 Sand and Solid Particles

It is not anticipated that sand will be in the produced fluid with arrival at compression facilities since the reservoir is of carbonate formation and the offshore wells are not designed for sand production. Thus, the CONTRACTOR’s scope facilities design will not cater for sand production.

No indication of solid production based on historical data. The observed suspended solids (ppm level) in the produced water is attributed to the flow back of scale traces and acid stimulation by products which as light particles non-abrasive type.

However, due to pressure reduction in the reservoirs and possible pore collapse, fine migration could be mobilized by the gas phase and could lead to solid production in the surface production system but it is not possible to quantify the future solid production details (rates/size/etc.).

Due to lack of future solid production details (quantity/size/etc.), the CONTRACTOR’s scope will only consider the following future provisions in the design [1,2,6,7,8]:

• Replacement/upsizing of existing WHP topside piping (flowlines /header/etc) to be reviewed in future when sufficient details is available regarding solid production and if any erosion issued are encountered in future,

• No addition equipment envisaged for managing solid production/ removal without interruption to

production.

Refer to Section 9.1.8 for Erosion and Erosion Corrosion.

6.3.4 Other Contaminants

Following contaminants could be present and shall be considered for NFPS Compression Facility design [1,2,6,7,8]:

• Mercury in separator gas up to 1 micrograms/m3

• Radon in separator gas up to 500 Bq/m3

• Arsenic in separator gas: < 2 micro grams/m3

• Other contaminants such as Mercaptans, Sulphur etc. could be present in trace

amounts.

7 BASIS OF MATERIAL SELECTION

Material selection is part of the corrosion management framework, which involves shortlisting technically acceptable material of construction for an application and then selecting the most cost-effective option for the operational life, consistent with the health, safety and environmental aspect, technical integrity and operational constraints. The following factors and requirements shall be taken into consideration during the material selection process:

•

Integrity factor - resistance to external and internal threats/degradation over the design life.

• Reliability and operational integrity - consequences of failure and impact to facilities.

• Fabrication requirements and limitations – cost effective fabrication methods and in-line with

PROJECT fabrication specifications.

• Total life cycle cost – where the material is fit-for purpose with lower maintenance and fabrication

cost will be favoured.

•

Inspection and maintenance factor - minimum maintenance and inspection strategy.

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• Weight factor - weight saving.

• Availability and delivery time – in-line with PROJECT requirements.

• Local and international regulations - comply with relevant national and international codes and

regulations.

7.1 Material Selection Process

The material selection process shall consider the steps illustrated in Figure 7-1.

Figure 7-1: Material Selection Process

design life external environment condition design temperature & pressure operating temperature & pressure production fluid properties water chemistry upset or other non-steady state condition chemical injection

define internal & external corrosion threats corrosion estimation using COMPANY- approved corrosion modelling software calculate the service life corrosion for each system assess sour service requirements as per NACE MR0175/ISO 15156

evaluate the suitability of carbon steel as base case identify other material options (CRAs, nickel alloys, non-metallic)

material selection in line with the PROJECT requirements and philosophy

Develop corrosion management plan • define internal & external corrosion management strategies • identify inspection plan • define corrosion monitoring plan

8 MATERIAL CONSIDERATION

The following sections describe the range of prospective material of construction that will be considered for the NFPS compression facilities. Specific material considerations and limitations of the NFPS compression facilities also provided.

8.1 Carbon Steel

Carbon steel is considered as a basis construction material for most of applications in oil and gas industries due to its price and availability.

Carbon steel is susceptible to CO2 and H2S corrosion in the oil and gas production environment, with the corresponding damage modes of general and localized metal loss. These mechanisms of internal

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corrosion of carbon steel are well studied and understood. Refer to Section 9.1.1, 9.1.2, 9.1.3 for more detail.

Carbon steel shall be recommended with a nominal corrosion allowance to accommodate the predicted metal loss due to corrosion. Additional corrosion mitigation measures, such as corrosion inhibition, internal coating, cathodic protection, etc., can be added to mitigate corrosion rate. Nevertheless, carbon steel in combination with corrosion inhibition may be considered if the use is justified by a detailed life cycle cost analysis (LCCA) – a type of economic analysis.

The selection of carbon steel lines shall conform to the flow velocity limitations in API RP 14E [23] and line sizing criteria (Process Design Criteria For Comp3 Project) [9] to prevent erosion in the absence of solid particles. API RP 14E shall not be used for solid containing system. For pure erosion and erosion-corrosion caused by solids and corrosive environments, erosion and/or erosion corrosion allowance determination shall be submitted for COMPANY approval.

Carbon and low alloy steel shall not be used upstream of deluge and/or fire suppression.

In addition, galvanized carbon or low alloy steel shall only be used for selected utility system (Clean Agent Fire Suppression System piping). External painting requirements to be as per PROJECT Specification For Fixed Facilities Protective Coating For Comp3 Project [13].

8.1.1 Carbon Steel for Sour Service

For carbon and low alloy steels, sour service requirements apply when H2S partial pressure ≥ 0.05psia (3 mbar) in the vapor phase as per NACE MR0175 / ISO15156-2 [24]. Materials to be used in sour service shall comply with PROJECT Specification For Topsides Material & Corrosion Requirements For Sour Service For Comp3 Project [10], and NACE MR0175/ISO 15156-2 [24].

Further discussion for carbon steel use in sour service is discussed in Section 9.1.3.

8.1.2 Corrosion Allowances

Corrosion allowances (CA) are used for carbon steel and low alloy piping or equipment piping to compensate for:

• Service life corrosion (SLC) over 30 years of design life,

• A temporary lack of efficiency of the specified mitigation actions (chemical inhibition or other

corrosion control methodologies),

• Residual corrosion, particularly when no mitigation actions is used,

• Erosion corrosion / erosion (erosion allowance is required on top of corrosion allowance if

susceptible)

Use of carbon and low alloy steel for process piping and pressure vessels shall be limited to services requiring 3 mm of corrosion allowance or less. For process piping and pressure vessels with predicted SLC of 3 mm or higher, suitable CRAs shall be specified.

• Maximum corrosion allowance (CA), wet hydrocarbon and/or corrosive service: 3 mm

Carbon and low alloy steel piping in non-corrosive utility services (e.g., inert gas, clean diesel, breathing air and instrument & utility air) shall have at least a 3.0 mm corrosion allowance.

• Maximum corrosion allowance (CA), dry and non-corrosive services: 3 mm

There is no tube heat exchanger scope in Comp3 project. Flare Knock Out Drum Heater material selection to be as per Material Selection Report For Fixed Facilities For Comp3 Project [11].

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For water saturated (wet) acidic gas streams, CRA material is required. Carbon and low alloy steel shall only be considered if the bottom-of-line water accumulation is not significant and that water condensation rates are manageable throughout the operational life of the facilities.

In situations where the erosion and/or wear is anticipated, an erosion allowance shall be considered and evaluated, with the total allowance considering all wall loss mechanisms (e.g. corrosion and erosion). The recommended corrosion allowance shall be documented in PROJECT Material Selection Report [11].

8.2 Corrosion Resistant Alloys

When a system corrosivity requires corrosion allowance (CA) for carbon steel piping and equipment exceeding 3 mm CA, and other internal corrosion control measures (e.g. CI injection, internal coating) cannot be applied, suitable corrosion resistant alloy shall be selected instead of carbon steel. No corrosion allowance shall be provided for corrosion resistant alloy for corrosion or erosion-corrosion purpose.

Due to the risk of internal stress corrosion cracking in H2S containing environment, use of CRAs shall be limited to the environmental and material limits, fabrication requirements in accordance with PROJECT Specification For Topsides Material & Corrosion Requirements For Sour Service For Comp3 Project [10], and NACE MR0175 / ISO15156-3 [24].

Application of CRAs beyond the environmental limits specified by NACE MR0175/ISO 15156-3 is not acceptable [24].

The selection of CRA grades shall consider the corrosivity of the handling fluids (internal) and the environmental conditions (external). Consideration shall be given to the composition of the process fluid including all stipulated design contaminants even if they only present in traces amount. Consideration shall also be given to a complete spectrum of the operating and process conditions including COMPANY’s experience. Cost and market availability of the material shall be taken into account in CRA material selection.

The following CRA options shall be considered:

8.2.1 Stainless Steels

8.2.1.1 Austenitic Stainless Steels

The common austenitic stainless steels are SS304 & SS316. However, SS304 has been ruled out in this project due to risk of external threats in offshore/marine condition. Hence, the minimum acceptable austenitic stainless-steel grade shall be SS316/316L with external TSA coating to mitigate against external chloride stress corrosion cracking under marine environment. Application of TSA shall be as per Thermal Sprayed Metallic Coating Specification for COMP3 Project [14].

If the application of TSA coating is not practical or possible due to technical constraints, such as application on small and complex geometry and in areas with limited accessibility, then austenitic SS shall be painted with coating systems complying with the Specification For Fixed Facilities Protective Coating For Comp3 Project [13] based on the service criticality. Refer to Section 9.2.2 for more information pertaining to this threat and the acceptable mitigation.

SS316L with lower carbon content shall be specified for welded components. Dual certified grade SS316/316L offers the benefits of both grades SS316 & SS316L. It minimizes the risk of sensitization during welding by controlling carbon content to ≤0.03% with improved mechanical properties. Hence, the use of SS 316L or dual certified grade SS316/316L is acceptable in this project. SS316 can be selected/ used instead of SS316L or dual certified grade SS316/316L, when there is no welding involved.

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Due to the risk of internal stress corrosion cracking in H2S containing environment (sour service), use of austenitic stainless steel shall be limited to the environmental, material and fabrication limits in PROJECT Specification For Topsides Material & Corrosion Requirements For Sour Service For Comp3 Project [10] and NACE MR0175/ISO 15156-3 [24].

All austenitic stainless steel base material for piping and equipment (excluding bolting) shall be free from any cold work intended to enhance their mechanical properties. The austenitic stainless steel shall be in a solution-annealed or solution-annealed and thermally stabilized condition in compliance with NACE MR0175/ISO 15156-3 [24].

It is understood that COMPANY assets have historically suffered from external CSCC failures of austenitic stainless steel when exposed to offshore/marine environment. Therefore, following are the additional limitations pertaining the use of austenitic stainless steel:

o SS304 shall not be used for any components / applications.

o SS316 and SS317 pressure retaining fasteners shall not be used. SS316 and SS317 can be used for structural, non-primary application (eg. Cable trays, Junction box, non- pressure retaining fasteners etc).

o TSA is required for pressure retaining SS 316 components. However, COMPANY approved alternative coating system can be applied for components where TSA is not practically possible e.g. on small and complex geometry component and low criticality utility services as defined above as per Specification For Fixed Facilities Protective Coating For Comp3 Project [13] based on the service criticality. Refer to Section 9.2.2 for more information pertaining to this threat and the acceptable mitigation.

o Austenitic stainless steel shall not be used for tubing material due to external pitting and

crevice corrosion in offshore/marine environment

o Austenitic stainless steel shall not be used for offshore application in sour gas or sour

condensate systems.

o Where SS316/316L is specified for pressure retaining components, crevices exposed

to marine atmosphere shall be avoided unless crevice corrosion is mitigated otherwise. Refer section 9.1.5.

8.2.1.2 Super Austenitic Stainless Steels

Super austenitic stainless steels (> 6% Mo) differ from conventional grade austenitic stainless steels regarding corrosion, mechanical and physical properties, due to the higher contents of chromium, nickel, molybdenum and nitrogen. They demonstrate greater chloride stress corrosion cracking (CSCC) and localized corrosion resistance compared to SS 316L. Super austenitic stainless steels (e.g., Type 6Mo UNS 31254/254SMO) are resistant to CSCC in marine atmosphere up to 100 °C as per literature. However, due to COMPANY’s previous experience, super austenitic SS should not be used for instrument tubing, pressure gauges, and other piping / equipment in process services fittings considering they are not fully immune to external chloride induced stress corrosion cracking under marine environment and application of external painting is not practical as a mitigation.

8.2.1.3 Martensitic Stainless Steels

Martensitic stainless steels (e.g., Type 410, 420, 431) are normally used in rotating equipment and valve components. The use of martensitic stainless steels in Sour service application shall

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comply with the environmental limits given in NACE MR0175 / ISO 15156, meeting the metallurgical requirement and mechanical condition.

However, precipitation hardened martensitic stainless steels (aged hardening) are limited to service with relatively low H2S partial pressure, thus they shall not be specified for the process system valve and other items (including fasteners) in sour service. Due to the risk of crevice and pitting corrosions, precipitation hardened martensitic stainless steels also not acceptable for pressure retaining fasteners exposed to offshore/marine environment.

Note: For welded components, this material shall not be used in COMP3 Project without COMPANY approval.

8.2.1.4 Duplex Stainless Steels

Duplex stainless steel (Type 22Cr) and super duplex stainless steel (Type 25Cr) also have improved chloride stress corrosion cracking (CSCC), localized pitting and crevice corrosion resistance as compared to SS 316L. Duplex stainless steels have approximately twice the strength of austenitic stainless steels and therefore advantages in high pressure systems, in term of weight and cost saving. In H2S containing environments, they offer relative resistance depending on the alloy grade.

Due to the risk of external CSCC, 22Cr DSS and 25Cr SDSS shall be used with operating temperature not exceeding 70 °C and 80 °C respectively.

For aerated seawater application, 25Cr SDSS is acceptable up to 30 °C. However, the temperature limit can be extended up to 45 °C, if crevices are weld overlaid with alloy C-276 or COMPANY approved equivalent. 25Cr SDSS used in seawater shall have PREN>40.

Use in H2S containing environments shall be based on the limitations of NACE MR0175 / ISO 15156-3 [24], and PROJECT Specification For Topsides Material & Corrosion Requirements For Sour Service For Comp3 Project [10].

8.2.2 Nickel Alloys

Nickel alloys with Ni content > 42% may be considered immune to CSCC in oil and gas environment. This includes the commonly used high nickel-chromium-molybdenum alloys for offshore applications such as alloy 625, alloy 825 and alloy C-276. Hence, the application of external corrosion protective coating concerning external CSCC is not required. However, if these components are insulated, external painting shall be applied to mitigate corrosion under insulation.

Cladding of nickel-based alloys such as Alloy 625 and Alloy 825 can be proposed as a compromise between suitability for service and cost reduction for process piping and pressure vessel depending on feasibility and size. Fabrication, welding and inspection requirements for Alloy 625 overlay / cladding shall comply with PROJECT Specification For Weld Overlay For Piping Materials For Comp3 Project [17] for piping and Specification For Welding Of Pressure Vessels For Comp3 Project [18] for pressure vessels respectively.

Nickel-chromium-molybdenum alloys with PREN>40 offer excellent resistance to localized corrosion (pitting and crevice) in marine environments and seawater application. Alloy C276 and C22 can be used in aerated seawater application exceeding 30 °C.

Nickel alloys also show greater resistance in H2S environment compared to stainless steels materials. However, the suitability of use under H2S environment shall be assessed, documented as part of the material selection assessment and shall be limited to the environmental, material and fabrication limits in NACE MR0175/ISO 15156-3 [24], and PROJECT Specification For Topsides Material & Corrosion Requirements For Sour Service For Comp3 Project [10].

8.2.3 Copper Nickel Alloys

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Copper alloys shall not be used in in sour service. Copper-based alloys are normally used in water service.

Common material grade for seawater application is CuNi 90/10 and 70/30. Cast components are specified as nickel aluminium bronze (UNS C95800). The maximum flow velocity in heat exchangers shall be 2.5 m/s for 90/10 CuNi systems and 3.0 m/s for 70/30 CuNi systems. The maximum flow velocity in pipes shall be 3.5 m/s for 90/10 CuNi systems and 4.0 m/s for 70/30 CuNi systems with pipe diameters ≥ 100 mm. For intermittent service (e.g., in a fire water system), the maximum flow velocity shall be limited to 10 m/s.

8.2.4 Titanium Alloys

Titanium is considered the most versatile material in seawater service at maximum temperature up to 85 °C. Due to its high cost, titanium is mainly used in area which other metallic materials are limited. On the other hand, titanium is also known to be excellent in concentrated sodium hypochlorite service. Titanium is usually limited to metal temperature of 71 °C in acidic solution and 76 °C in alkaline solution to avoid formation of internal hydrides which can cause embrittlement.

Titanium commercial grades 1 & 2 are commonly used. Other commercially pure titanium grades (such as grade 4 having higher strength) can also be selected, if found suitable.

8.3 Non-metallic Materials

8.3.1 FRP/GRP

The term of Fiber-Reinforced Plastic (FRP) and Glass-Reinforced Plastic (GRP) may be used interchangeably. They refer to composite materials with polymer matrix and can be collectively referred as composites. GRP has been widely used for aerated seawater application.

Piping system in GRP requires technical expertise as well as careful monitoring and oversight during the design, manufacturing, handling, installation and testing activities. Composite piping shall comply with the fabrication and testing requirements in accordance with ISO 14692 [25] and PROJECT Specification For GRE Pipes, Fittings And Flanges For Comp3 Project [19].

Composite piping shall only be used in services where the probability of failure is low or the consequence of failure is low. Selection of GRP piping and equipment shall consider assessment under sour in-leak scenarios and full vacuum services.

In addition, material selection of composites shall consider the requirement of fire resistance, effect of UV degradation and electrical conductivity for dissipating the potential generation of electrostatic charges. The dry composite piping shall be fireproofed. The selection of composite depends on the temperature limitation of resin type and curing agent. Table 8-1 should be used as guidance.

Table 8-1: Temperature Limitation of Common Resin Materials

RESIN TYPE MAXIMUM TEMPERATURE °C (1)

Epoxy (2)

Phenolic (4)

Polyester (3)

Vinyl Ester (5)

110

150

70

100

Notes:

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(1) The maximum temperature listed should be used as general guideline only. Resin or pipe manufacturer shall be

consulted for evaluation of resin performance in specific service conditions.

(2) Epoxy resin has the best strength, modulus and toughness of common resins and is acceptable for hydrocarbon and

water-handling applications.

(3) Polyester resin shall be used only for water handling applications operation near ambient temperature as such resin

has low thermal and chemical resistance.

(4) Phenolic resin has the best thermal and chemical resistance of all commercially available resins. However, due to the higher expense and higher likelihood of manufacturing defects, such resin should only be used for special application where other resins are inadequate.

(5) Vinyl ester resin has excellent chemical resistance to most chemicals used in oilfield applications.

8.3.2 Elastomers and Thermoplastics

Non-metallic seal material selection, including elastomers and thermoplastics, shall be based on the limitation in term of chemical compatibility and design requirements. Suitability and service limitation of some elastomers and thermoplastics are given in Appendix 3. Further requirements are provided in the Specification For Elastomer And Thermoplastic Selection For Comp3 Project [21].

All sealing elastomeric components (valves, compressors, pumps, etc.) shall:

• Comply with NACE TM0192 and NACE TM0196, for sour service and CO2, including proof of

rapid gas decompression highest resistance.

• Be compatible with service and added chemicals, confirmed by ASTM immersion tests at design

condition.

• Be purchased from well-known suppliers having appropriate testing witnessing/certificates.

8.4 Fasteners

Pressure retaining bolting material requirements and external corrosion protection shall be in accordance with Specification For Pipe Fasteners For Comp3 Project [20].

Electroplated bolts (with Cadmium) shall not be allowed based on COMPANY previous experience of repetitive failures due to hydrogen embrittlement.

Table 8-2 provide the recommended acceptable fastener materials.

Table 8-2: Recommended Fastener Materials

DESIGN METAL TEMPERATURE

MINIMUM STUD YIELD STRENGTH (2)

COATING REQUIRED (1)

STUDS

NUTS

ºC

ºF

KSI (MPA)

STANDARD

GRADE

STANDARD

GRADE

−29 to 93

−20 to 200

95 (654)

Yes

−48 to 93

−55 to 200

105 (723)

Yes

−48 to 93

−55 to 200

105 (723)

Yes

-60 to 93

– 76 to 200

110 (758)

-100 to 100 −420 to 200

65 (450)

No

No

ASTM A 193/A 193M

ASTM A 320/A 320M

ASTM A 320/A 320M

API STD 6ACRA

B7

L7

L43

Alloy 925

ASTM A 194/A 194M

ASTM A 194/A 194M

ASTM A 194/A 194M

API STD 6ACRA

2H

7L

7L

Alloy 925

ASTM F 468

Alloy 625

ASTM F 467

Alloy 625

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Notes:

1. Corrosion protection requirements shall be in accordance with PROJECT Specification for Bolts, Nuts and Gaskets [24].

2. Replace “yield strength” with “proof strength” if using ISO or EN standards.

3. Bolting that can be exposed directly to a sour environment, or that is buried, insulated, equipped with flange

protectors, or otherwise denied direct atmospheric exposure or direct open seawater exposure, shall conform to the requirements of Specification For Topsides Material & Corrosion Requirements For Sour Service For Comp3 Project [10] and NACE MR0175 / ISO 15156.

4. For fasteners that are exposed to sour service, the hardness is the controlling parameter over yield strength for

carbon and low-alloy steels.

Compatibility of the fastener material with the component bodies should be assessed to confirm the risk of galvanic corrosion and ensure acceptable.

Consideration shall be given to the accidental leakage or exposure of the handling fluids. Fasteners (internal or external) for sour service application shall comply with requirement as defined in NACE MR0175 / ISO 15156 [24] and PROJECT Specification For Topsides Material & Corrosion Requirements For Sour Service For Comp3 Project [10].

All carbon and low alloy steel fasteners shall be protected with corrosion resistant coating to mitigate atmospheric corrosion (marine) following requirement in Specification For Fixed Facilities Protective Coating For Comp3 Project [13].

The CRA grade selected for fasteners shall be resistant to the environmental conditions (external).

Fasteners should be avoided in splash zone. When bolting cannot be avoided, minimum requirement is to have CS bolting with Aluminium Cermet and PTFE Coating as per Specification For Fixed Facilities Protective Coating For Comp3 Project [13].

Fasteners under submerged condition if protected by cathodic protection, no additional corrosion coating is required. Fasteners protected by cathodic current shall be resistant to hydrogen embrittlement. If cathodic protection is not applied or cannot be ensured, fasteners shall be made of seawater resistant material e.g. Alloy 25Cr SDSS/Alloy 625/C-276.

General material selection guidelines for fasteners:

• SS304, SS316, SS317 and 17-4PH stainless steel pressure retaining fasteners shall not be

used due to the risk of external CSCC in offshore/marine environment.

• The use of carbon and low alloy steel fasteners with external painting is acceptable to fasten with CRA body components that are not defined within the scope of PROJECT Piping Material Specification For Comp3 Project [12].

•

•

•

If CRA fastener is required, the use of 22Cr DSS fastener is acceptable for operating temperature ≤ 70°C. However, this is not applicable to components defined within the scope of PROJECT Piping Material Specification For Comp3 Project [12].

If CRA fastener is required, the use of 25Cr SDSS fastener is acceptable for operating temperature ≤ 80°C. However, this is not applicable to components defined within the scope of PROJECT Piping Material Specification For Comp3 Project [12].

If CRA fastener is required, the use of 6Mo SASS fastener is acceptable for operating temperature ≤ 100°C. However, this is not applicable to components defined within the scope of PROJECT Piping Material Specification For Comp3 Project [12].

• Alloy 625 shall be the minimum CRA pressure retaining fasteners for all CRA component defined

within the scope of PROJECT Piping Material Specification For Comp3 Project [12].

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8.5

Instrument Tubing and Fitting

External corrosion protective painting is not practical for the small-bore instrument tubing and fitting. Hence, the selection of CRA grades for instrument tubing and fitting shall be resistant to marine operating condition on top of the required internal corrosion resistance for the handling fluids under all the anticipated operating conditions in design.

Instrument tubing and fitting used in marine environment shall be as a minimum made from Alloy 625 due to high risk of crevice and pitting corrosion for all services (hydrocarbon or utilities). Higher CRA grades shall be used if assessed as required by the internal corrosion evaluation during the material selection process. Monel 400 is acceptable as the minimum material of construction for tubing and fitting components used in seawater handling services, and resistant to marine operating environment.

Hypochlorite instrument tubing and fitting shall be titanium grade 2 as a minimum.

In addition, there shall be no galvanic coupling capable of promoting corrosion in instrumentation tubing systems and/or between the tubing and the instrument themselves.

8.6 Grating and Ladders

Atmospheric corrosion is a major threat to galvanized carbon steel structural items (e.g., grating, handrails and ladder). COMPANY’s lesson learnt indicated that galvanized steel is susceptible to external corrosion and has a limited-service life in offshore marine environment despite of the highly intensive painting maintenance activities. To mitigate the accelerated rate of corrosion with galvanized grating and ladders, the following material selection shall be considered:

• To use FRP/GRP as preference, for all areas where it can be allowed. GRP grating is not allowed in emergency escape routes. GRP shall be certified and its composition shall include fire retardant, strength, UV protection and finishing as per COMPANY colour code.

• For area where galvanized steel is required, an extra corrosion protection coating shall be applied in order to prolong the service life of the grating. Finishing topcoat of the galvanized grating shall comply with COMPANY colour code.

8.7 System Specific Material Requirements

The basic piping material for different process and utility systems are summarised in Table 8-. The material listed shall be used as general basis and guideline only. The final material selection shall be based on corrosion assessment results in the PROJECT Material Selection Report For Fixed Facilities For Comp3 Project [11].

Table 8-4: General Material Selection Basis for Piping and Equipment

SYSTEM

BASIC MATERIAL

REMARKS

Production system

Fuel gas system

Nickel alloys (clad2 / solid)

CS, SS316L (clad2 / solid), 25Cr SDSS, Alloy 625

TSA coating shall be considered for external protection of SS316L to mitigate CSCC3

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SYSTEM

BASIC MATERIAL

REMARKS

Helifuel

SS316L (solid / clad2), 25Cr SDSS

TSA coating shall be considered for external protection of SS316L to mitigate CSCC3

Flare system

Nickel alloys (clad2 / solid)

Minimum design temperature shall be considered in material selection. Flare pipework shall be designed for free-draining.

Seawater system

GRP, CuNi, 25Cr SDSS with PREN

40, Nickel alloys, Titanium

Firewater

GRP, CuNi

Open drain

CS, GRP, 25Cr SDSS

Closed drain

Nickel alloys (clad / solid)

Cooling medium (closed loop)

CS

Chemical Injection

SS 316L or higher alloy

Sodium hypochlorite CPVC, Titanium

25Cr SDSS is limited to 30 °C.

Clean Agent Fire Suppression System (NOVEC1230 (FK-5-1-12)) piping to utilise CS+Galvanized

CS is acceptable provided the drain lines are free draining, no pocket and normally non-flowing condition.

With chemical treatment

• Depend on the chemical compatibility requirements.
• TSA coating shall be considered for external protection of SS316L to mitigate CSCC3.

Fresh / Potable / Demineralized Water

SS316L, 25Cr SDSS, Non-metallic materials

TSA coating shall be considered for external protection of SS316L to mitigate CSCC3.

Diesel

CS

Instrument air

SS 316L, 25Cr SDSS

TSA coating shall be considered for external protection of SS316L to mitigate CSCC3.

Utility air

CS

Dry air, tapped from downstream of the air dryer package.

Nitrogen / inert gas

CS, SS 316L1, 25Cr SDSS1

TSA coating shall be considered for external protection of SS316L to mitigate CSCC3.

Breathing air

SS 316L, 25Cr SDSS

Lube Oil

SS 316L, 25Cr SDSS

Sewage / Wash Water

Instrument Tubing and Fitting

Non-metallic materials (GRP), 90/10 Cu-Ni, SS 316L

Hydrocarbon and General Services: Alloy 625

TSA coating shall be considered for external protection of SS316L to mitigate CSCC3.

TSA coating shall be considered for external protection of SS316L to mitigate CSCC3

90/10 Cu-Ni for 2” and below piping. Carbon steel tanks in fresh water service shall be internally coated.

Refer to Section 8.5

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SYSTEM

BASIC MATERIAL

REMARKS

Hypochlorite: Titanium Grade 2 Seawater: Monel 400

Notes:

1. Due to cleanliness requirement or to prevent fluid contamination.

2. Cladding in form of weld overlay shall meet requirements specified in the Specification For Weld Overlay For Piping Materials For Comp3 Project [17] for piping and Specification For Welding Of Pressure Vessels For Comp3 Project [18] for pressure vessels.

3. TSA coating shall be applied in accordance with Specification For Thermally Sprayed Aluminium Coating For Comp3 Project [14]. However, for small component or component with complex geometry (e.g. piping and valves of all sizes and the associated pipe support) where application of TSA is not practically nor technically possible, alternative coating as Per Specification For Fixed Facilities Protective Coating For Comp3 Project [13] shall be applied based on the service criticality.

9 DEGRADATION THREATS

This section outlines the potential degradation threats that shall be considered in the corrosion assessment and material selection for the NFPS Compression facilities.

1. Internal corrosion:

• CO2 corrosion

• H2S/CO2 corrosion

• H2S related corrosion cracking (i.e., SSC, HIC and SOHIC)

• Chloride stress corrosion cracking (CSCC)

• Pitting and crevice (localised) corrosion

• Microbiologically influenced corrosion (MIC)

• Under deposit corrosion

• Erosion and Erosion corrosion

• Galvanic corrosion

• Oxygen corrosion

• Preferential weldment corrosion (PWC)

• Liquid metal embrittlement (LME)

2. External corrosion:

• Atmospheric corrosion

• External chloride stress corrosion cracking (CSCC)

• Corrosion under insulation (CUI)

• Corrosion under pipe support (CUPS)

3. Mechanical Degradation:

• Low temperature embrittlement

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• Degradation of non-metallic material

9.1

Internal Corrosion

These corrosion mechanisms form on the internal surface when the steel is exposed to the water and contaminations or corrosive agents in the produced fluid.

9.1.1 CO2 Corrosion

CO2 corrosion is one of the most common corrosion mechanisms that occurs in carbon steels in oil and gas production and processing system. The risk of CO2 corrosion shall be considered when the presence of free water and CO2 is anticipated.

The reactions of CO2 and water will tend to form carbonic acid which can lead to a considerable increase in the corrosion of carbon steel. As the partial pressure of CO2 increase, more CO2 will dissolve in water leading to higher corrosion rates. The CO2 corrosion rate varies with CO2 content, pressure, temperature, flow regime, pH and condensation rate.

CO2 corrosion rate of carbon steel can be estimated using several industry accepted corrosion prediction models. For this project, ECE 5.8 corrosion model is proposed for use. Corrosion assessment results shall serve as basis for material and corrosion control selection. The guidelines for corrosion assessment are provided in the Appendix 1.

9.1.2 H2S & CO2 Corrosion

When CO2 and H2S are present in the production fluid simultaneously, either one of the three distinctive corrosion phenomena can occur, namely the H2S corrosion, the mixed CO2/H2S corrosion or the CO2 corrosion, depending on the ratio of CO2 and H2S. The three corrosion mechanisms are described in Table 9-1.

Table 9-1: Dominant Weight Loss Corrosion Mechanisms in CO2 & H2S Containing Environment

CO2/H2S RATIO

DOMINANT CORROSION MECHANISMS

REMARKS

CO2/H2S < 20

H2S Corrosion

20<CO2/H2S<500

Mixed CO2/H2S Corrosion

Ferrous sulphide as product

the main corrosion

A mixture of carbonate

ferrous sulphide and

iron

CO2/H2S>500

CO2 Corrosion

Iron carbonate as the main corrosion product

By taking the design H2S and CO2 concentration shown in Table 6-2, CO2 / H2S ratio of RGE, RGA and QG2 produced fluids are expected to be less than 20. Thus, the weight loss corrosion in the NFPS compression hydrocarbon containing facilities will be dominated by H2S corrosion in which the iron sulphide is the primary corrosion product.

In comparison with CO2, H2S rarely causes severe weight loss corrosion in production equipment because the corrosion product, iron sulphide, usually forms a protective film on the surface of the steel. Nevertheless, it must be emphasized that H2S may also form a non-protective layer and result in enhanced localized corrosion (pitting) of the steel. The exact conditions that produce a protective film

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and those that cause pitting are not well understood to accurately predict corrosion rates, when H2S corrosion is the dominant mechanisms.

However, it has been found that localized pitting corrosion mostly related to the sulphur deposition, oxygen entries in produced fluids, solid deposition, bacterial development and/or ineffective inhibition [28] [29] [30]. Flow regime and fluid velocity are considered as the important factors affecting pitting attacks in the H2S corrosion. Thus, dead-legs and area with stagnant flow are highly susceptible.

CO2/H2S corrosion assessment will be performed for process streams based on process data (operating temperature, operating pressure and production flowrates) taken from the H&MB using ECE 5.8 corrosion prediction model, supplemented by literature publications [29] [30] [31].

The capability of ECE 5.8 corrosion assessment is provided in the Appendix 1. Material selection shall be based on the corrosion assessment results in PROJECT Material Selection Report For Fixed Facilities For Comp3 Project [11].

The effect of H2S for ECE 5.8 Corrosion Modelling is further explained in Appendix 2.

9.1.3 H2S Related Corrosion Cracking

The presence of H2S may lead to sulfide stress cracking (SSC), stress corrosion cracking (SCC), and hydrogen-induced cracking (HIC). The risk of H2S cracking shall be considered for NFPS compression facilities with the designed H2S concentration in the produced fluids as per Table 6-2.

SSC is a credible cracking mechanism for all carbon and low alloy steel process and utility systems in contact with wet H2S and with H2S partial pressure ≥ 0.3 kPa.

In wet H2S corrosion, atomic hydrogen resulted from an electrochemical reaction between the metal and the H2S-containing medium, enters the steel at the corroding surface. The presence of hydrogen in steel may, depending on the type of steel, the microstructure and inclusion distribution, and the tensile stress distribution (residual and applied), cause embrittlement and possibly cracking.

The cracking mechanisms due to wet hydrogen sulphide (H2S) service fall into three main categories as follows:

9.1.3.1 Sulfide Stress Cracking (SSC)

SSC is a form of hydrogen embrittlement phenomenon, i.e. cracking is caused by the dissolution and diffusion of hydrogen atoms (produced by corrosion) into the steel which subjected to tensile stress. Cracking is affected by material strength / hardness, stress level, solution chemistry and type of material. The main method used to prevent such cracking is by controlling material yield strength / hardness and stress level by heat treatment (PWHT) following guidance in NACE MR0175 / ISO 15156 [24].

The susceptibility of this threat shall be assessed and documented in Material Selection Report For Fixed Facilities For Comp3 Project [11] as part of the material selection process. SSC is applicable to the carbon and low alloy steel piping and equipment when the absolute H2S partial pressure is ≥ 0.3 kPa (3 mbar) and defined as “sour” in project [10].

All carbon and low alloy steels when specified as sour, regardless the presence of internal CRA cladding, shall comply with all the applicable material and fabrication requirement in NACE MR0175 / ISO 15156 [24] and Specification For Topsides Material & Corrosion Requirements For Sour Service For Comp3 Project [10]. In addition, qualification testing to demonstrate SSC resistance shall be required for all bare (no CRA cladding) carbon steels and low alloy steels with direct exposure to sour service application, in accordance with NACE

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TM0177 [34] and NACE TM0316 [49]. The carbon and low alloy steels backing with CRA cladding is exempted from these laboratory qualification requirements.

The basis of selection of SSC-resistant corrosion resistant alloys (CRAs) shall be done through complying with the metallurgical requirements and environmental limits as stipulated in NACE MR0175 / ISO 15156-3 [24] and Specification For Topsides Material & Corrosion Requirements For Sour Service For Comp3 Project [10]. Application of CRAs beyond the environmental limits specified by NACE MR0175/ISO 15156-3 [24] is not acceptable. Hence, additional laboratory testing concerning SSC is not required following this basis of material selection.

9.1.3.2 Hydrogen Induced Cracking (HIC)

HIC occurs when atomic hydrogen diffuses into the steel and recombines to form molecular hydrogen at inclusions or other microstructural defects, causing internal pressurization. Damage can be seen in various forms depending on the type and location of the inclusions present and the stress pattern. Typical damages include blistering, stepwise cracking (SWC) and stress-oriented hydrogen induced cracking (SOHIC). The main method used to prevent this type of cracking is by selecting high quality clean material. For the case of SOHIC, reduction of internal stresses by heat treatment should be performed.

If sour service is specified, bare CS or LAS pressure vessel plate or piping components made of plate shall be made of HIC resistant steel as defined in NACE MR0175/ISO 15156 [24] and Specification For Topsides Material & Corrosion Requirements For Sour Service For Comp3 Project [10].

The HIC resistant material and qualification testing requirements in PROJECT Specification For Topsides Material & Corrosion Requirements For Sour Service For Comp3 Project [10] and NACE MR0175 / ISO 15156 [24] and NACE TM0284 [31] shall be complied.

9.1.3.3 Stress Corrosion Cracking (SCC)

SCC is the cracking of metal involving anodic processes of localized corrosion and tensile stress (residual and/or applied) in the presence of water and H2S. Chlorides and / or oxidants and elevated temperature can increase the susceptibility of SCC. The main method used to prevent such cracking is to select a material resistant to SCC under the service conditions and, in some cases, to reduce the service stresses.

The basis of selection of SCC-resistant corrosion resistant alloys (CRAs) shall be done through complying with the metallurgical requirements and environmental limits as stipulated in NACE MR0175 / ISO 15156-3 [24] and Specification For Topsides Material & Corrosion Requirements For Sour Service For Comp3 Project [10]. Application of CRAs beyond the environmental limits specified by NACE MR0175/ISO 15156-3 [24] is not acceptable. Hence, additional laboratory testing concerning SCC is not required following this basis of material selection.

9.1.3.4 Assessment of Sour Service Requirement

H2S cracking susceptibility of NFPS compression facilities shall be assessed based on NACE MR0175 / ISO15156-2 [24] for carbon and low alloy steels and NACE MR0175 / ISO15156-3 for CRAs [24] and documented in Material Selection Report For Fixed Facilities For Comp3 Project [11].

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For bare carbon and low alloy steels, sour service requirements apply when H2S partial pressure ≥ 0.05 psia (3 mbar) in the vapour phase as per NACE MR0175 / ISO15156-2. For CRA and other alloys, environmental and material limits, fabrication requirements in PROJECT Specification For Topsides Material & Corrosion Requirements For Sour Service For Comp3 Project [10] and NACE MR0175/ISO 15156 [24] shall be complied.

The use of dehydration, corrosion inhibitors or protection coating/lining shall not relax the requirement to use sour service resistant material should the sour service is specified in accordance with PROJECT Specification For Topsides Material & Corrosion Requirements For Sour Service For Comp3 Project [10] and NACE MR0175/ISO 15156 [3].

The use of H2S-cracking resistant CRA cladding / weld overlay is an acceptable means of mitigation if the applicable requirements in Section 9.1.3.1 and Section 9.1.3.3 are complied and the integrity of the CRA cladding / overlay can be assured e.g. no sand erosion concern.

Refer to Section 9.1.3.1 for sulfide stress cracking (SSC).

Refer to Section 9.1.3.2 for hydrogen induced cracking (HIC).

Refer to Section 9.1.3.3 for stress corrosion cracking (SCC).

Dissimilar weldment between carbon steel and CRA is not allowed in sour service. When unavoidable, weld design of cladded portions with extended CS ends or other mean shall be provided. The use of dissimilar weld joints in wet sour service requires comprehensive assessment and qualification similar to dissimilar weld joint in subsea pipeline.

9.1.4 Chloride Stress Corrosion Cracking (CSCC)

Stress corrosion cracking (SCC) of CRAs in contact with chloride containing environments is often referred as chloride stress corrosion cracking (CSCC), as the presence of chloride can affect the passive layer of the CRAs. It is detrimental for austenitic and duplex stainless steel. The resistance of CRAs on CSCC is primarily dependant on the chloride content and operating temperature. The breakdown of passive layer is affected by the presence of oxygen, and the in-situ pH.

9.1.5 Pitting and Crevice (Localized Corrosion)

Passive films of corrosion resistant alloy can be subjected to localized breakdown resulting in accelerated dissolution of the underlying metal under certain susceptible operating conditions. It is called pitting if the attack initiates at open surface and crevice if the attack initiates at occluded site.

To minimize the risk of pitting and crevice corrosion, selection of stainless steel shall take into account the environmental limitation given in Figure 9-1. Figure 9-1 shows the risk of pitting and crevice corrosion of various stainless steels in oxygen-saturated water with varying chloride content and temperature.

The severity of pitting and crevice corrosion tends to vary with the concentration of chloride. Chloride is aggressive since it is relatively small with high diffusivity, thus interfering passivation. The presence of oxidizing agents in chloride containing environment further enhance pitting and crevice corrosion. Since oxygen is a strong oxidant and depolarizing agent, it means even trace quantities of dissolved oxygen can be harmful.

Therefore, systems containing oxygen and chloride such as seawater system and open drain are particularly susceptible to pitting and crevice corrosion. Corrosion mitigation is through adequate material selection. The CRA with pitting resistant equivalent number (PREN) > 40 and non-metallic material shall be considered in mitigating pitting and crevice corrosion.

In deaerated condition, the risk of pitting or crevice corrosion is low with the exception of highly concentrated chloride solution. The risk of pitting in hydrocarbon (with the absence of oxygen) service is often associated with other contaminants such as H2S.

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Figure 9-1: Critical Pitting and Crevice Corrosion Temperature as a Function of Chloride Concentration for Various Stainless Steels [32]

Notes:

Solid Line: Critical Pitting Temperature, Dotted Line: Critical Crevice Temperature

9.1.6 Microbiologically Influenced Corrosion

Microbiologically influenced corrosion (MIC) due to bacteria especially sulfate-reducing bacteria (SRB), can lead to highly localized corrosion. In addition, the bacteria reduce the sulphate ions present in the water to sulphide ions which can then cause corrosion problems associated with H2S. Risk of MIC to be evaluated based on sulphate content, operating temperature & liquid flow rates.

Production and processing system are inherently free of living organisms that could lead to MIC. This threat is typically related to the improper treatment of hydrotest water or injection water (not applicable to COMP3). The only threat for the commencement of MIC in hydrocarbon system of COMP3 is the cleanliness level of hydrotest water from bacteria contamination perspective. It shall be ensured to use clean and treated hydrotest water to commission COMP3 facility to prevent MIC. Pipe shall be drained and dried as soon as practicable after hydrotest.

Services such as seawater, cooling water and atmospheric exposed drain system are susceptible to this threat and requires attention. Low and stagnant flow area (dead leg) can promote the build-up of biofilm, thus are prone to MIC risk. It is recognized that corrosion management of dead legs is challenging as they are difficult to chemical treat and are prone to MIC and under deposit corrosion.

• The key corrosion control strategy should be through prevention of contamination. Hence, it is important that all pre-commissioning activities that allow ingress of water into the equipment and piping only use treated hydrotest water.

• Microbes require water to thrive, proper design to avoid dead legs and free-draining drain

pipework could mitigate the risk of MIC.

• Proper application of biocides.

• The use of non-metallic material is considered as resistant to this threat.

9.1.7 Under Deposit Corrosion

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The under-deposit corrosion is caused by a localized chemical concentration which results in pits at the metal surface under the solid deposit. Under deposit corrosion occurs in wet liquid hydrocarbon systems where solids, corrosion product and scale, settle out in low flow or stagnant areas (dead leg). The solids can prevent corrosion inhibitor reaching the steel beneath the deposit and provide a breeding ground for corrosive bacterial.

To minimize the potential for this form of corrosion, drains shall be installed at all points in the process flow where liquid can accumulate and/or stagnant. In addition, the flare and drain pipework shall be designed to be no pocket, sloped, free-flowing and avoiding low spots. CRA with PREN>40 shall be selected where dead legs are unavoidable and liquid accumulation is likely with risk of under deposit corrosion. Evaluation on the risk of dead-leg should be done on a case-by-case basis.

9.1.8 Erosion and Erosion Corrosion

Erosion corrosion can occur when the liquid flow itself contributes to a mechanical and / or enhanced chemical removal of a protective layer, with subsequent corrosion reactions. The presence of solid particles in produced fluid can exacerbate the risk of erosion corrosion by promoting the physical / mechanical removal of a protective corrosion layer.

No sand production is expected since the reservoir is carbonate formation. However, due to pressure reduction in the reservoirs and possible pore collapse, fine migration could be mobilised by the gas phase and could lead to solids production in the surface production system.

An increased C factor of 200 is only applicable for CRA piping or corrosion inhibited systems, under sand/solids free service, in determining the erosional velocity based on API RP 14E. With the presence of solids in production fluid, the material erosional behaviour changes completely.

An erosion study was performed at FEED Erosion Study Report [3] using DNVGL-RP-O501 methodology [33] to understand the erosion risk of existing production flowlines and manifolds.

The recommendation as follows was suggested:

• Due to the high velocities, it is recommended to have an erosion and particle monitoring system in place on the production flowlines, consisting of, for example, both erosion probes (or UT devices) and acoustic particle detectors. It is recommended to have the solid monitoring on the flowlines due to the higher velocities in these streams, which makes it easier for the equipment to detect sand and erosion. The effectiveness of acoustic detectors on calcite particles should however be evaluated by the supplier.

As per Process Design Basis documents for RGE, RGA and QG2 [6,7,8]:

• No sand production is expected since the reservoir is of carbonate formation and the offshore wells are not designed for sand production consequently, the CONTRACTOR’s scope facilities design will not cater for sand production.

• No indication of solid production based on historical data. The observed suspended solids (ppm level) in the produced water are attributed to the flow back of scale traces and acid stimulation by products which are light particles non abrasive type.

• However, due to pressure reduction in the reservoirs and possible pore collapse, fine migration could be mobilized by the gas phase and could lead to solid production in the surface production system, but it is not possible to quantify the future solid production details (rate/size/etc.).

The selection of carbon and low alloy steel lines shall conform to the flow velocity limitation in API RP 14E and line sizing criteria (Process Design Criteria For Comp3 Project) [9] to prevent erosion corrosion in the absence of solids.

9.1.9 Galvanic Corrosion

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Galvanic corrosion occurs when dissimilar metallic materials are connected together in a conductive corrosive fluid. The potential difference between the two metals can cause a significant increase in corrosion rate of the less noble material. However, the extent of the galvanic corrosion risk is influenced strongly by factors such as the area ratio of the two metals, the conductivity of the electrolyte, oxygen content and temperature.

It is assumed that the local corrosion rate near the interface between dissimilar metal is three (3) times higher than the average corrosion rate farther from the interface, decreasing with distance from the interface over a length of 10 pipe diameters.

Dissimilar metals connections shall be avoided or limited as much as possible. Nevertheless, following solutions can be used in case susceptible areas are encountered:

• Use of a thick-walled, carbon-steel-flanged section at the junction, designed for replacement at

scheduled intervals.

• Use of a spool piece of a non-conducting material (e.g., FRP pipe or rubber-lined CS) for a

minimum length of 10 pipe diameters.

If the above measures are not feasible particularly in process system, CRA cladding should be considered on the flange face of the CS side to prevent internal galvanic corrosion of CS-CRA flanged connection.

It should be noted that the above solutions are not required for piping conveying dry fluid without free water presence during normal operation and non-corrosive liquid. This includes connection with intermittent service (e.g., drain and flare lines) and connection with instruments.

Dissimilar Flanged Connection

Dissimilar flanged connection shall be avoided as much as possible. In cases when the dissimilar material joints are unavoidable, appropriate remediations shall be established on a case by-case basis.

Mitigation of galvanic corrosion on flanged connections in hydrocarbon process shall be, as a base case, through CRA cladding of flange faces at the points of material change. If flange face cladding proved impractical (e.g. brownfield piping), isolation gaskets and bolt sleeves shall be considered.

For utility systems and low risk piping systems, isolation gaskets and bolt sleeves shall be considered.

Fasteners used in dissimilar flanged connections, shall be galvanically compatible (based on anode / cathode area ratio of the mating components).

9.1.10 Oxygen Corrosion

Oxygen dissolves in produced brines and seawater and causes severe corrosion in carbon steel. If the dissolved oxygen is higher, the corrosion rate is greater. The presence of oxygen also drastically affects the localized corrosion and cracking resistant of stainless steel. Therefore, for aerated seawater service, the CRAs with pitting resistant equivalent number (PREN) > 40, nickel-based alloys, titanium and non- metallic material shall be considered in material selection.

In hydrocarbon service, oxygen is not normally present and shall be avoided at all times. All hydrocarbon systems, irrespective of material, should be designed to eliminate oxygen ingress into the system, either directly (from feed streams), or more importantly from secondary streams.

Potential oxygen contamination through open drain, pump seals and storage tank shall be prevented by other means. For storage tanks, ingress of oxygen should be prevented through proper inert gas

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blanketing. Integrity of sealing system of rotating equipment shall be designed and maintained to prevent air ingress.

9.1.11 Preferential Weld Corrosion

When carbon and low alloy steels are used for process piping system in CO2 & H2S containing environment, it is often found that the weldment are more severely affected than the parent material. This form of selective attack is known as preferential weld corrosion (PWC) where the weld metal (and/or heat affected zones) corrodes at a significantly faster rate than the adjacent parent metal. Typically, three reasons that cause PWC are:

• Differences in composition between the weld metal and the base metal led to a potential difference in certain environment, thus setting up a galvanic cell, and subsequently corrosion.

• Even if the weld metal is close in chemical composition to the base metal, differences in as welded microstructure could make the weld metal sufficiently different from and even less corrosion resistant than the base metal.

• Microstructural difference between the base metal and as welded heat affected zones can lead

to localised attack on the HAZ.

To minimize the PWC the following actions should be considered:

• The use of filler metal that is compatible / more noble with respect to the base/parent material in

order to minimize PWC.

•

Inhibitor qualification shall be carried out in such a way that protection of all section of the pipework system including weld metal, parent metal and HAZs is proven.

• Post weld heat treatment to reduce the residual stresses at the weld and composition gradient

across the weldment.

Success has been reported for use of filler metal to make weldment more cathodic with respect to the adjacent HAZ and parent metal in seawater application. However, overall performance is not consistent for hydrocarbon services. This may attribute to the complex interaction of other influencing parameters such as scale effect, flow condition and etc. Hence, prevention of PWC should not be only relying on consumable selection. Full consideration should be given to the welding process, filler metal, base metal composition and microstructures to ensure meeting the expected corrosion resistance and mechanical property of the weldment.

9.1.12 Liquid Metal Embrittlement

Liquid metal embrittlement is the loss of ductility in normally ductile metals when stressed under contact with liquid metal. Mercury is a natural components of certain hydrocarbon reservoirs and is known to embrittle certain materials (e.g., aluminium alloy, copper alloys, and titanium alloys).

A trace amount of mercury (up to 1 micrograms/m3) and zinc (13.9 mg/L) has been reported, hence the risk of LME is considered relatively low in the NFPS compression facilities. However, the following materials should be avoided when mercury is present:

• Aluminium-based alloys

• Copper-based alloys

• Titanium-based alloys (except the commercially pure grades are acceptable)

Another metal / embrittler couple is austenitic stainless steels / zinc.

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Precautions are only necessary for stainless steel equipment or piping exposed to temperature above 420 °C or where there is a risk of contact with molten zinc (e.g. during a fire) if it contains flammable toxic or fire-fighting fluid under pressure. In such service, precaution shall be taken to avoid contact between stainless steel and galvanized steel hangers, supports, backing flanges, bolts and similar components. In addition, zinc containing paints are prohibited on stainless steel.

9.2 External Corrosion

External corrosion occurs due to chemical interaction between the exterior surface of the steel items and the marine atmosphere surrounding them. Typically, the external corrosion is controlled by applying protective coating to prevent external environmental condition such as humidity and air-borne salt and chloride from contacting with the steel surface. This section outlines the external corrosion threats associated with a marine environment.

9.2.1 Atmospheric Corrosion

The marine environment contains water and chloride salts. Carbon steels will corrode under such conditions. The main protection is achieved through proper application of coating system. The use of external corrosion allowance for carbon and low alloy steel is impractical when considering the additional weight, it would require providing protection to bare metal surface. Figure 9-2 shows typical corrosion rates of mild steel in marine environment.

Figure 9-2: Typical Corrosion Rate of Mild Steel in Marine Environment

In submerged installation, seawater which contains about 3.5 % salt and dissolved oxygen, will cause corrosion to various metals, specifically carbon steel. The average corrosion rate of steel in seawater is about 0.1 to 0.15 mm/yr, normally showing fairly uniform corrosion. Corrosion protection is normally achieved through protective coating and sacrificial anodes. At splash zone, oxygen is freely available and mechanical action of waves removes any protective oxides that may form; therefore, the corrosion rate is highest. Thick and high-quality coating system (i.e., TSA coating and Glass Flake Epoxy for structural components) is used as splash zone protection to prevent corrosion attack. The detailed

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corrosion protection approach for the jackets and other immersed items will be defined in PROJECT Specification For Cathodic Protection For Greenfield Jacket Structure For Comp3 Project [15].

All pressure containing components regardless of the service are prone to this threat, the associated risk depends on the material and metal temperature. Carbon steel and stainless steel (e.g., austenitic and duplex stainless steel) shall always be externally coated in accordance with PROJECT Specification For Fixed Facilities Protective Coating For Comp3 Project [13].

Copper-based alloys and nickel-chromium-molybdenum alloys with PREN > 40 have high degree of resistance to atmospheric corrosion and pitting resistance under marine operating environment. Hence, application of external corrosion protective coating for these corrosion resistant alloys without insulation is not required unless top coat colour is required for safety reason.

9.2.2 External Chloride Stress Corrosion Cracking

Chloride stress corrosion cracking (CSCC) refers to cracking caused by simultaneous presence of tensile stress, specific corrosive medium and susceptible material. In wet chloride containing conditions, CRAs are susceptible to breakdown of the passive protection film, resulting in pitting corrosion and/or chloride induced stress corrosion cracking. It is particularly the case for uncoated austenitic stainless steel and duplex stainless steel.

In addition, stress corrosion cracking requires source of tensile stress, and this can be assumed in welded components where weld residual stresses typically exceed yield strength. Residual stress may also arise from cold working during manufacture. Given both conducive environment and source of stress are inevitably, the key controlling factor becomes the temperature.

Temperature is an important variable in determining the susceptibility of CRAs to CSCC. The temperature limit indicated in Table 9-2 (to be read in conjunction with Table 6-1) shall be used as default values for the basis of design where application of mitigation against external CSCC is technically challenging or not possible e.g. instrument tubing.

Table 9-2: Material Temperature Limit for External CSCC

MATERIAL TYPE

GRADE

Stainless Steel

Ni Alloys

SS 316 / SS 316L SS 317 / SS 317L Type 6Mo Type 22Cr DSS (PREN > 34) Type 25Cr SDSS (PREN > 40) Alloy 625 Alloy 825 Alloy 800 H Alloy C276

TEMPERATURE LIMIT WITH NEGLIGIBLE LIKELIHOOD OF CSCC <20 <20 <100

<70

<80

No restriction No restriction No restriction No restriction

300 series austenitic stainless steels are highly susceptible to CSCC. In order to mitigate this threat to an acceptable risk level, all SS316 / 316L pressurized components shall be painted with thermally

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sprayed aluminium (TSA) concerning external CSCC. The application of high integrity TSA coating is considered as an effective mitigation against external CSCC under the salt bearing offshore marine environment.

However, if the application of TSA coating is not practical or possible due to technical constraints, such as application on small and complex geometry (piping and valves of all sizes including the associated pipe support) and in areas with limited accessibility, then COMPANY approved alternative coating systems as specified in the PROJECT Specification For Fixed Facilities Protective Coating For Comp3 Project [13] is permitted based on the service criticality.

In addition, considering the use of austenitic stainless steel SS316L as a material of construction is limited to lower criticality utility systems in the project (A pressure rating of #300 and below can generally be regarded as low criticality for the purpose of external CLSCC mitigation when a suitable painting system is applied.)

Coating systems for such applications shall be selected as specified in the PROJECT Specification For Fixed Facilities Protective Coating For Comp3 Project [13].

Other stainless-steel groups such as DSS, SDSS, 6Mo are also susceptible to CSCC under offshore marine environment but at a lower degree than 300 series austenitic SS. Application of external coating on these components shall be provided following PROJECT Specification For Fixed Facilities Protective Coating For Comp3 Project [13] to mitigate CSCC regardless operating temperature or design temperature.

Nickel alloys with Ni content > 42% is considered immune to CSCC in oil and gas environment, application of external coating concerning CSCC is hence not required. Commonly used high nickel alloys for offshore applications include Alloy 625, Alloy 825 and Alloy C-276.

9.2.3 Corrosion Under Insulation

Corrosion under insulation (CUI) is caused by water ingress into the insulation, which gets trapped and in contact with the metal surface. Corrosion under insulation (CUI) is reported to occur in systems operating between -12 °C and 175 °C for CS and between 60 °C and 175 °C for SS. Some of the mitigation measures to prevent CUI are given in below:

• Only applying insulation if it is deemed absolutely necessary from operation / process point of

view

• Personnel protection shall be physical barriers such as wire mesh or metal cage instead of insulation if the surface process temperature is ≤ 260°C. Piping or equipment components shall not be insulated when not necessary.

• Selection of insulating materials which are less prone to initiating CUI

• Closed-cell, hydrophobic and water repellent insulation material is preferred e.g. cellular glass

and aerogel.

• Apply a high-quality protective coating

• Whenever insulation is needed, the corrosion protection design shall presume that it will become wet and secure protective measures shall be based upon this assumption. Consequently, carbon steels, stainless steels and nickel alloys under insulation shall always be adequately coated.

• Proper design and installation of the insulation system

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• A completely sealed jacketing system shall be provided for insulation design. Jacketing material and inspection ports shall be selected to reduce the risk of damage from mechanical abuse.

Appropriate external coating systems shall be specified, and the insulation/sealing shall be designed to limit water entry/retention. Detailed requirements for external coating and insulation systems are provided in Project Specification For Fixed Facilities Protective Coating For Comp3 Project [13] and Project Specification For Thermal Insulation For Comp3 Project [16].

9.2.4 Corrosion Under Pipe Support (CUPS)

Corrosion often occurs due to the abrasive movement between the pipe and support or when moisture is trapped between the pipe and its support. Both mechanisms cause disbondment of the pipe coating and lead to crevice and pitting corrosion. This condition gets aggravated by poorly designed pipe supports that prevent adequate inspection, trap water, and produce metal-to-metal contact between the pipe and the pipe supports.

Crevice corrosion can be prevented through good design details that exclude crevice such as avoiding the formation of pipe support crevice space where rainwater will be accumulated, and regular inspection are effective mean of controlling the crevice corrosion.

Proper pipe support design shall be implemented per PROJECT Piping Support Standard Specification For Comp3 Project [22] and appropriate external coating systems shall be specified in accordance with PROJECT Specification For Fixed Facilities Protective Coating For Comp3 Project [13].

Mitigations against CUPS:

• The pipe and primary support in direct contact / welded connection shall be of the same material.

• When there is a dissimilar material exist as part of the support, it shall not be in direct contact

with the pipe to avoid galvanic corrosion.

• To avoid crevices by full welding

• Supports which eliminate crevices and improve inspection ability

• Support design should be free draining.

• There should be no direct contact between piping and piping support component that is made of different material of construction, either insulating sleeve, PTFE isolation or reinforcing pad (same material as the pipe) with continuous welding (shop welding) will be provided

9.3 Mechanical Degradation

Mechanical threats/damage mechanisms such as cavitation, pulsations, fatigue and abrasion are not covered but shall be considered for candidate materials in function of their service.

Brach connections (e.g., for instrument line connection) should be braced or gusseted to prevent possible risk of vibration induced failure.

9.3.1 Low-temperature Embrittlement

Low temperature embrittlement is a phenomena where there is sudden loss of toughness at around the ductile-to-brittle transition temperature. Brittle fracture can occur under such condition when under stress (residual or applied) where the material exhibits little or no evidence of ductility or plastic deformation. Hence, consideration shall be given to all possible low temperature operating conditions such as cold de-pressurisation, where susceptible metallic material may suffer from brittle fracture.

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Brittle fracture Low temperature embrittlement is best prevented by using materials designed for low temperature operation including upset and auto-refrigeration events. The Minimum Design Metal Temperature (MDMT) is the minimum allowable temperature to prevent brittle fracture and shall be considered in material selection of equipment and piping component. The minimum design metal temperature of some commonly used material is provided in Table 9-3.

Table 9-3: Minimum Design Metal Temperature of Some Commonly Used Materials

MATERIAL TYPE

CS CS for Low Temperature Application Austenitic Stainless Steel (SS 316, SS317) Super Austenitic Stainless Steel (6 Mo SS) 22Cr DSS 25Cr DSS Copper Alloys (e.g. CuNi 90/10, Ni-Al-Br) Nickel Alloys (e.g. Alloy 625, Alloy 825, Alloy C-276) GRP/FRP Titanium (Grade 1 through 4)

MINIMUM DESIGN METAL TEMPERATURE -29°C (1)

-46°C (2)

-196°C

-196°C

-46°C -46°C

-196°C

-196°C

-35°C -75°C

Notes:

(1) Carbon steel may be used in piping systems with a minimum design temperature of –29 °C if the nominal wall thickness is less than 12.7 mm, or as specified in ASME B31.3. For lower design temperatures or higher thickness, impact testing shall be performed.

(2) If impact tested at -46°C

9.4 Degradation of Non-Metallic Materials

Degradation of non-metallic materials occurs by the following mechanisms:

• Solvation

• Thermal degradation

• Chemical reaction such as oxidation (affects chemical bonds), hydrolysis, radiation

• UV degradation from external

• Heat aging

Different material has different response to chemicals depending on the resin component in the composite polymer matrix. Chemical compatibility of non-metallic material shall be confirmed by ASTM immersion tests at design condition and test certificates shall be provided.

To reduce the risk of degradation of non-metallic material, a supplementary layer may be proposed by manufacturer to enhance the surface finishing, the UV resistance performance, and other functions.

Explosive Decompression (ED) is the rapid expansion of a rubber part due to absorbed gas upon rapid release of external pressure. Generally, high-pressure gases, such as CO2 or CH4, are the most damaging to rubber. Any gas can be absorbed and cause explosive decompression. It is also known as Rapid Gas Decompression (RGD). It affects Elastomer Seals in Process systems.

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Selection of elastomer to be based on limitations of Appendix 3 and qualifications as per Specification for Elastomer and Thermoplastic Selection Ref [21].

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10 Appendices

Appendix 1 Appendix 2 Appendix 3

ECE 5.8 Corrosion Prediction Modelling Basis The Effect of H2S in ECE 5.8 Modelling Service Limitations for Elastomers and Thermoplastics

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10.1 Appendix 1

ECE 5.8 Corrosion Prediction Modelling Basis

For this project, ECE version 5.8 model is proposed for use to model the expected CO2 general corrosion rates, taking benefit of ECE ability to model the effect of H2S within its built-in feature and the likelihood of pitting occurrence– as elaborated in Appendix 2 – The Effect of H2S in ECE 5.8 Modelling.

Electronic Corrosion Engineer (ECE) is a CO2 corrosion model that enable quantitative estimation of corrosion rates and support selection of materials for oil and gas production systems and process facilities. ECE is frequently updated and improved for corrosion analysis and firmly based on laboratory data, field calibration studies. The latest version of the ECE modelling is ECE 5.8 – the version proposed for use in this project. It is an implementation of the de Waard Corrosion Model. The original de Waard corrosion model was largely based on experimental flow loop data produced at IFE. The following papers provide the basis of the de Waard corrosion model.

•

Influence of Liquid Flow Velocity on CO2 Corrosion: A Semi-Empirical Model

• Predictive Model for CO2 Corrosion Engineering in Wet Natural Gas Pipelines

The de Waard model has been altered slightly in different versions of ECE 5. The main elements and equations of the ECE 5 model is available in the following paper.

• Corrosion Prediction and Materials Selection for Oil and Gas Producing Environments

The above paper describes the ECE 4 version but the core features of the CO2 corrosion model are the same in ECE 5.

Just like de Waard Corrosion Model, ECE 5.8 begins with the worst-case CO2 corrosion rate with further refinement taking consideration of the following factors when applicable, more details are available in Section 10.1.1:

• Effect of H2S

•

Influence of protective scale

• pH and water chemistry

• Oil-wetting (water cut, flow velocities and etc)

• Condensation of water concerning TOL corrosion

• Organic acids

• Glycol

•

Inhibition

• Top of line corrosion

• Flow regime

• Piping elevation

• Erosion-corrosion

10.1.1 Applicability of ECE 5.8 Corrosion Modelling for NFPS

There are many CO2 corrosion modelling available in the public domain and commercially. Some are categorized as empirical, and some are mechanistic in nature. Naturally, very different results can be obtained when the models are run for the same cases due to the different philosophies being used in the development of these models.

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The most important factor in selecting a suitable model among these CO2 corrosion models is not the ability to predict CO2 or H2S corrosion but the ability of a model to provide a realistic view on the actual corrosivity of the system under evaluation and subsequently supporting the evaluation for the applicability of CS / LAS application (limited to maximum 3 mm CA as per Section 8.1.2). Factors of consideration is given as the following:

• Application limit of the model for NFPS’s design parameter that stipulated under Section 6

• CO2 and H2S corrosion are complex, so as the synergistic effect of the influential parameters. A

field and laboratory data calibrated model is a preferred option.

• Consider and quantify the influence of applicable environmental parameters on corrosion under

various conditions for NFPS

• Ability of the model to cover all credible damage modes for CO2 and H2S corrosion (general and

localized corrosion)

All the above consideration has been reviewed for the ECE 5.8 model and confirmed suitable for use in this project. The following paragraphs provide more details on the review and the effect of H2S is provided in Appendix 2.

All models have limitation in use with respect to environmental conditions. The application limit of the ECE 5.8 model is up to maximum limit of 100 mol% of CO2, up to 50 mol% of H2S, maximum of 1000ppm acetic acid, maximum limit of 5000ppm bicarbonate and 500,000kg/d of glycol injection rate. The key project design parameters that presented under Section 6 are well within the application limit of the proposed ECE 5.8 software.

CO2 corrosion is a complex electrochemical reaction. Hence, models that have been evaluated using field and laboratory data should preferably be used for the project. ECE 5.8 corrosion model is categorized as semi-empirical model which emphasizes on empirical correlations (both field and laboratory data) designed for horizontal and vertical flows for flowlines and tubing and suitable for application for oil and gas production system and processing facility.

The flow regime and hydrodynamics properties of fluids that influence flow regimes (e.g. stratified, waxy, annular mist, slug etc.) can affect the estimated corrosion rate due to turbulence intensity and mass transfer. Liquid holdup is another important hydrodynamic parameter for gas-liquid flow. When two- phases are transported in a pipe, the flow velocity is frequently inadequate to uniformly transport both phases at the same rate. As a result, the gas flows faster than the liquid and there is a hold-up of liquid that may accelerate corrosion. Liquid holdup is strongly dependent on gas velocity and the angle of pipeline / piping inclination. ECE 5.8 takes into account of these effects on the predicted corrosion rates.

One of the key features of the ECE 5.8 model is the ability to predict the presence and the effect of the protective corrosion film on corrosion to avoid over estimation on the corrosivity of the system under assessment.

Both general corrosion and localized corrosion are credible damage modes for this project due to the presence of CO2/H2S gases. Hence, apart from the general CO2 corrosion, focus should also be placed on the effect of H2S on localized corrosion in the process facilities. It has been concluded that the protective scale behaviour is not universal and certain conditions render it ineffective resulting in high localized pitting corrosion. Potential isolated pitting rate may be credible if the protective adherent scale breakdowns. The qualitative risk of localized pitting and the quantitative estimation of the rate can be modelled and predicted by using ECE 5.8.

High API gravity gas condensates will give little or no protection against corrosion since their water/oil emulsion breaks easily, leaving water free to contact the steel surface for commencement of CO2/H2S corrosion. This concept is in-line with the ECE 5.8 calculation model.

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pH provides the indication of H+ concentration in an aqueous solution which directly determines the corrosivity of an electrolyte as the H+ concentration play the key role in the cathodic reduction process that driving the acidic corrosion and at the same time affecting the solubility limit of the protective scale and subsequently the protective scale precipitation rate. Hence, the accuracy of the pH calculation is important to reflect the actual corrosivity of the system. ECE 5.8 model provides in-situ pH by considering a wide range of species in the calculation including the fugacity of the CO2 at the actual operating condition. For the case of NFPS where H2S is present, when the solubility limit of the FeS is exceeded, pH calculation is based on charge balance. The range of species that being considered in the pH calculation are as the following:

CO2, H2CO3, HCO3

-, CO32-, H2S, S2-, H+, OH-, H2O, Fe2+, CH3COOH and CH3COO-

10.1.2 Assumptions for ECE 5.8 Corrosion Rate Calculation

The following assumptions have been made:

• The selection of the materials of construction shall be based on the premise that the hydrocarbon

processing streams observe the following:

o Do not have oxygen present within; and o Do not have elemental sulphur within.

• The composition range of produced water in NFPS production shall be as per stipulated by the

design basis in Section 6.

• Once the pitting corrosion rate is calculated, sour pitting risk predicted by ECE is checked. ECE will indicate the pitting severity risk as “Low”, “Moderate”,” High” and “Very High”. Based on the risk, these numeric factors will be applied to the pitting rate:

o Low – Insignificant - 0.0

o Moderate – 0.3

o High – 0.5

o Very High – 0.75

• Assessment of the corrosion rate of carbon steel is based on pCO2 and pH2S in the gas phase (for gas or multiphase systems). In liquid-only streams, the CO2 and H2S content of the water shall be determined by the partial pressure of CO2 and H2S at the location when the liquid was last in equilibrium with the gas, e.g. the upstream separator as per ISO 15156.

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10.2 Appendix 2

The Effect of H2S in ECE 5.8 Modelling

NFPS Offshore production systems is expected to occur in the H2S dominated corrosion region (refer to Section 9.1.2). In this H2S-dominated corrosion regime, tenacious sulphide scales may form on the internal surfaces of carbon steel production equipment and piping, which may significantly reduce the corrosion rate relative to the CO2 corrosion rate. However, if the sulphide layer is incomplete or partially protective in the service environment, aggressive pitting attack will occur. The review of the suitability of the ECE 5.8 model has considered these important scenarios.

The effect of the presence of H2S on corrosion in the ECE model is threefold:

• Covering the steel with a protective iron sulphide layer

•

Increasing the acidity of the water and thereby increasing the corrosion rate

• Scavenging the dissolved Fe2+ ions by forming Fe- sulphide precipitates, which decrease the pH

and increase the corrosion rate

The first scenario refers to when H2S is present with complete and protective film formation. The film forming prediction by ECE are based on field data for H2S partial pressure from nil to about 15 bar, which is well within the design limit as stipulated in Section 6 and FEED Materials Design Basis Memorandum. The film corrosion rate predicted by ECE in many cases lower than for other corrosion models but still over-predicted in the filming corrosion rates in this range compared with field data (entirely empirical in ECE sour corrosion prediction). Which means, it is still being conservative but at a lesser degree than other prediction models.

It is commonly reported in the industry that FeS layer can sometimes suffer from isolated spots of breakdown and lead to occurrence of pitting corrosion. For this reason, ECE model does an additional calculation of the corrosion rate without the filming effect (pitting rate without the H2S factor). The difference between the pitting rate (without H2S effect) and the filmed surface corrosion rate (with H2S factor) may be indicative of the likelihood that pitting occurs and the risk is predicted based on the statistical data of ECE.

The presence of H2S has a profound impact on the chemistry and corrosivity of the fluids at which, the precipitation of FeS reduces the concentration of the dissolved irons which decreases the pH. When the dissolved iron is precipitated as FeS, this H2S-containing environment is more acid than without the FeS film because there is no dissolved iron carbonate. The corrosion rate in this environment is taken as a possible rate of pitting corrosion.

The exact interaction of H2S on the anodic dissolution through sulfide adsorption and affecting the pH is a highly complex process and not fully understood. This reflects the current development of the CO2 prediction modelling in the industry concerning the effect of H2S. ECE 5.8 as a fully empirical (sour) based or field and laboratory data calibrated model is suitable and being proposed for NFPS use.

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10.3 Appendix 3

Service Limitation for Elastomers and Thermoplastics

Table A3-1: Service Limitation for Elastomers

Material (1)

Examples of Common Name or Trade Name

Useful Service Temperature Range C (F)

Nitriles (NBR)

Hydrogenated Nitriles (HNBR or HSN) Fluoroelastomers (FKM)

Fluoroelastomer (FEPM-ETP)

Fluoroelastomer (FEPM-TFE/P)

Perfluoro- elastomers (FFKM) Ethylene Propylene (EPDM) (1)

Buna-N, Nitrile Hycar®, Kynac® Zetpol® EOL® 101 Therban® Viton® A Viton® E60 Viton® A401C FKM 1 Viton® B FR58/90, FKM 2 Viton® GF FKM 3 Viton® GLT FR25/90 FKM 3 Viton® GFLT FKM 3 Viton Extreme®

Aflas® Fluoraz® Kalrez® Chemraz® Parofluor® Vistalon®

−30 to 120C (5) (−22 to 250F) −23 to 135C (−10 to 275F)

−18 to 177C (0 to 350F)

−10 to 177C (+14 to 350F)

7 to 177C (+20 to 350F)

−30 to 177C (−22 to 350F)

−23 to 177C (−10 to 350F) 10 to 200C (7) (+50 to 392F) 10 to 218C (7) (+50 to 425F) −18 to 232C (0 to 450F)

−51 to 150C (−60 to 300F)

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U (6) A Q A

A

A

A

U A Q U A

U

U

A Q Q

U (6) A Q A

A

U

A

U A Q U A

U

U

A Q Q

U (6) A Q A

A

A

A

U A Q U A

U

U

A Q Q

A

A Q A

A

A

A

A A A A Q

A

A

U Q A

A

A

A

A A A A A

A

A

A Q A

A

A

A Q A A A A

A

A

A

A

A Q Q

A Q Q

A

A A

A

U Q A Q

A

A

A Q A A A

A

A

A

U U

Key: A = Acceptable; Q = Qualification Required; U = Unacceptable

Notes: (1)

(2)

(3) (4)

(5) (6)

(7)

The acceptable fluid service for each material can be oil, condensate, gas, or a multiphase fluid with the exception of EPDM, for which the service type is gas only. EPDM swells extensively in liquid hydrocarbons and is not acceptable for liquids service. ED-resistant elastomer seals are available from specific suppliers whose names can be supplied by COMPANY. Note that CO2 has the greatest potential for inducing ED damage, but all gases can cause ED damage. See NACE MR0175/ISO 15156 for definition of sour service. All Viton® elastomers, with the exception of the GF and GFLT types, swell in 100% methanol. When the methanol is diluted with 10% water or more, the swelling is significantly reduced. Lower service temperatures require specially formulated Nitriles (e.g., arctic Nitriles). Viton® elastomers may be used with amine corrosion inhibitors at low temperatures such as 38–66C (100–150F) or lower. Consult with COMPANY for use at higher temperatures. Note minimum useful temperature of Viton Extreme® and Aflas®. Use at lower temperatures may be approved for special applications. Consult with COMPANY or lower temperature limits.

200-20-CE-DEC-00006 _00

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Classification: Internal

NORTH FIELD PRODUCTION SUSTAINABILITY (NFPS) PROJECT

COMP3 - NFPS OFFSHORE RISER/WELLHEAD PLATFORM & INTRAFIELD PIPELINES PROJECT

MATERIAL SELECTION PHILOSOPHY FOR COMP3 PROJECT

Table A3-2: Service Limitation for Thermoplastic

c i t a m o r A r e h t o & , e n e u o T , e n e l y X

l

s d n u o p m o C

A

A

A

) 3 (

) 3 (

S 2 H

.

i s p 5 0 0 < e c i v r e S S 2 H

A

S 2 H

.

i s p 5 0 0

e c i v r e S S 2 H

A

) 2 (

D E o t e c n a t s i s e R

A

A

A

A

A

A

A

y n A t a y t i l i

b i t a p m o C

l

o n a h t e M

n o i t a r t n e c n o C

A

A

A

i

9 < H p d u l F n o i t e p m o C e n i r B

l

i

9

H p d u l F n o i t e p m o C e n i r B

l

i

l

e d i r o h C c n Z r o e d m o r B c n Z

i

i

A

Q

A

) F  0 0 3 ( C  0 5 1 < s e t a m r o F

A

) F  0 0 3 ( C  0 5 1

s e t a m r o F

A

d i c A c i r o h c o r d y H

l

A

e c n a t s i s e R m a e t S

A

i

e d m o r B m u i c l a C

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

d u M d e s a B

r e t s E

A

A

A

d u M d e s a B

l i

O

A

A

A

s r o t i b h n

i

I

n o i s o r r o C e n m A

i

A

A

A

Material (1)

Examples of Common Name or Trade Name

Useful Service Temperature Range C (F)

Polyphenylene Sulfide (PPS)

Ryton®

Arlon®, PEEK

Teflon®, Avalon®

PEEK

PTFE

Notes:

−60 to 205C (−75 to 400F)

−60 to 260C (−75 to 500F)

−200 to 205C (−328 to 400F)

Key: A = Acceptable; Q = Qualification Required; U = Unacceptable

(1) The acceptance fluid service for each material can be oil, condensate, gas, or a multiphase fluids

(2) Thermoplastics are not normally subjected to ED damage.

(3) See NACE MR0175/ISO 15156 for definition of sour service.

200-20-CE-DEC-00006 _00

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Project: Q-32705 - Saipem COMP3 Folder: RFQ Files