AR-FEN-30-DOEC-420010_rev01 - Material Selection and COR Prevention Philosophy for Pipelines

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MATERIAL SELECTION AND CORROSION PREVENTION PHILOSOPHY FOR PIPELINES, RISERS AND I-TUBES Document Type: Phase:

PHI BE

System / Unit:

35

Discipline:

Equipment:

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Document Reference: AR-FEN-30-DOEC-420010 Revision

COR 2

Contractor reference number: NA

01

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AFD

Rev. Date 28/JUL/2017 Page 2 of 22

TABLE OF CONTENT 1

Introduction .................................................................................................................................... 4

2

Reference Documents ................................................................................................................... 6 2.1

COMPANY General Specifications .................................................................................... 6

2.2

Project Specifications ......................................................................................................... 6

2.3

Codes and Standards ........................................................................................................ 7

2.4

Other References ............................................................................................................... 7

2.5

Definitions .......................................................................................................................... 7

3

Acronyms ....................................................................................................................................... 8

4

List of HOLDS ................................................................................................................................ 8

5

Main Conclusions .......................................................................................................................... 9 5.1

Pipelines............................................................................................................................. 9

5.2

Risers ................................................................................................................................. 9

5.3

I-Tubes ............................................................................................................................... 9

6

Design Data .................................................................................................................................. 10 6.1

Export Pipeline Operating Conditions .............................................................................. 10

6.1.1

Pressure ......................................................................................................................................................... 10

6.1.2

Temperature ................................................................................................................................................... 10

6.2

Export Pipeline Process Data .......................................................................................... 10

6.2.1

CO2 content .................................................................................................................................................... 10

6.2.2

Flow Rate........................................................................................................................................................ 10

6.3

MEG Pipeline ................................................................................................................... 10

6.4

Design Life ....................................................................................................................... 10

7

External Corrosion Control ........................................................................................................ 11 7.1

Corrosion in Seawater ..................................................................................................... 11

7.2

Corrosion during Installation ............................................................................................ 11

7.3

Electrical Interconnection ................................................................................................. 11

7.4

Coatings ........................................................................................................................... 11

7.4.1

Coating Systems ............................................................................................................................................. 11

7.4.2

Extent of Coating ............................................................................................................................................ 12

8

EXTERNAL CATHODIC PROTECTION....................................................................................... 13

9

INTERNAL CORROSION/EROSION ............................................................................................ 14 9.1

Corrosion Assessment ..................................................................................................... 14

9.2

Erosion Assessment ........................................................................................................ 14

10

INTERNAL CORROSION CONTROL .......................................................................................... 15

10.1

During Installation and Commissioning ........................................................................... 15

This document is the property of TOTAL AUSTRAL. It must not be stored, reproduced or disclosed to others without written authorisation from the Company. R:\652618\Typing\DOCS\Docs\Natives\COR\AR-FEN-30-DOEC-420010_rev01 - Material selection corrosion prevention phi pip ris i-tubes\AR-FEN-30-DOEC-420010_rev01 - Material selection corrosion prevention phi pip ris i-tubes.docx

MATERIAL SELECTION AND CORROSION PREVENTION PHILOSOPHY FOR PIPELINES, RISERS AND I-TUBES Document Type: Phase:

PHI BE

System / Unit:

35

Discipline:

Equipment:

NA

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Document Reference: AR-FEN-30-DOEC-420010 Revision

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Rev. Date 28/JUL/2017 Page 3 of 22

10.2

Wet Storage ..................................................................................................................... 15

10.3

In Service ......................................................................................................................... 15

10.4

In-service Monitoring ........................................................................................................ 15

10.5

Compatibility of Chemical Treatments ............................................................................. 16

11

SELECTION OF MATERIALS ...................................................................................................... 17

11.1

Export Pipeline ................................................................................................................. 17

11.1.1

Solid Erosion Corrosion / Pure Erosion ........................................................................................................... 17

11.1.2

Microbial Induced Corrosion............................................................................................................................ 17

11.1.3

Top of Line Corrosion...................................................................................................................................... 17

11.2

MEG Pipeline ................................................................................................................... 17

11.3

Restrictions to Cathodic Protection .................................................................................. 17

11.4

Fasteners and Fittings ..................................................................................................... 18

12

ASSEMBLY ................................................................................................................................... 19

12.1 13

AFD

Use of Grease and Lubricants ......................................................................................... 19

APPENDIX 1 – EXPORT PIPELINE CORROSION ASSESSMENT ............................................ 20

13.1

Norsok M-506................................................................................................................... 20

13.2

FreeCorp .......................................................................................................................... 21

13.3

Summary .......................................................................................................................... 22

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MATERIAL SELECTION AND CORROSION PREVENTION PHILOSOPHY FOR PIPELINES, RISERS AND I-TUBES Document Type: Phase:

PHI BE

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1

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Status

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Rev. Date 28/JUL/2017 Page 4 of 22

Introduction

FENIX gas field is part of the Cuenca Marina Austral (CMA-1) license, operated by TOTAL AUSTRAL in Tierra del Fuego, Argentina. CMA-1 offshore fields have been developed in phases: Hidra Centro & Hidra Norte (1990’s), Carina & Aries (2000’s), Vega Pleyade (2015). FENIX would be developed in the same manner as the previous fields, i.e. with a minimum wellhead platform sending its production to onshore Total operated facilities at Rio Cullen via a near 77km long multiphasic pipeline.

Figure 1.

: Overview of COMPANY Field Development

FENIX planned development consists of several phases. FENIX phase 1 development covers three dry tree wells with maximum production capacity of 10 MScmd and MEG supply from onshore. Potential FENIX phase 2 would be the connection of up to four sub-sea wells to the two risers left by phase 1 for this purpose, while potential phase 3 would imply the ultimate connection to a future compression platform when field depletion makes it necessary. The purpose of this document is to specify the external corrosion prevention measures to be implemented on the FENIX project taking into account the 20 years design life. The purpose of this document is to define: • • •

selection of materials of construction for pipelines, risers and I-tubes; avoidance of corrosion during assembly and installation; design of corrosion control systems.

in relation to the FENIX Offshore project.

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MATERIAL SELECTION AND CORROSION PREVENTION PHILOSOPHY FOR PIPELINES, RISERS AND I-TUBES Document Type: Phase:

PHI BE

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Rev. Date 28/JUL/2017 Page 5 of 22

The materials selection and corrosion control for the entire subsea development shall be to a common standard. This philosophy covers the following: • • •

The offshore sections of the export pipeline and the MEG pipeline; All risers and I-tubes associated with the Export and MEG pipelines; Risers for future development.

The present document shall be read in conjunction with the COMPANY General Specifications and project specifications listed in Section 3. CONTRACTOR shall be responsible for bringing any ambiguity or inconsistencies to the COMPANY’s attention. The philosophy covers • • • •

Material Selection philosophy for the components detailed above; Control of materials in Purchased Items; Control of corrosion during fabrication, testing and installation; Control of internal and external corrosion throughout the service life

Decommissioning is not included in this Philosophy. The onshore facilities at Rio Cullen are outside of the ENGINEER scope.

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MATERIAL SELECTION AND CORROSION PREVENTION PHILOSOPHY FOR PIPELINES, RISERS AND I-TUBES Document Type: Phase:

PHI BE

System / Unit:

35

Discipline:

Equipment:

NA

Class:

Document Reference: AR-FEN-30-DOEC-420010 Revision

COR 2

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01

Status

Rev. Date 28/JUL/2017 Page 6 of 22

2

Reference Documents

2.1

COMPANY General Specifications

[1] GS-EP-COR-001_rev15

Corrosion Control on Production Facilities: Design and Construction

[2] GS-EP-COR-004_rev03

Limiting Flow Velocities Calculations for Erosion Corrosion Purpose

[3] GS-EP-COR-100_rev12

Cathodic Protection of Offshore Structures

[4] GS-EP-COR-102_rev10 [5] GS-EP-COR-161_rev08 [6] GS-EP-COR-163_rev08

AFD

Design of Cathodic Protection of Submarine Pipelines by Galvanic Anodes Internal Corrosion and Erosion-Corrosion Monitoring: Design and Installation Chemical Treatments for Corrosion Control: Engineering and Construction Requirements

[7] GS-EP-COR-201_rev10

Galvanic Anodes

[8] GS-EP-COR-220_rev11

Three Layer Polyethylene External Coating for Pipelines

[9] GS-EP-COR-225_rev06

Polyethylene and Polypropylene Coatings for Bends and Fittings

[10] GS-EP-COR-233_rev00

Risers Coatings

[11] GS-EP-COR-350_rev13

External Protection of Offshore and Coastal Structures and Equipment by Painting

[12] GS-EP-COR-356_rev03

Corrosion Protection of Fasteners for Subsea and Topside Applications

[13] GS-EP-COR-560_rev10

Physical and Chemical Treatment of Hydrostatic Test Water

[14] GS-EP-SPS-029_rev05

Metallic Materials for Subsea Production Facilities

[15] COMPANY TEC/COR N°17- Material Selection and Corrosion Control Philosophy Report for FENIX 064 rev00 Phase 1 Pre-Project

2.2

Project Specifications

[16] AR-FEN-10-DOEC-253001

Heat and Mass Balance

[17] AR-FEN-10-DOEC-420001

Material Selection and Corrosion Prevention Philosophy for Topsides

[18] AR-FEN-20-DOEC-423001

Jacket Cathodic Protection & Monitoring System Calculation Note

[19] AR-FEN-30-DOEC-424011

Pipeline Cathodic Protection Specification

[20] AR-FEN-30-DOEC-424010

Painting and Coating Specification for Pipelines

[21] AR-FEN-30-DOEC-424011

Pipeline Cathodic Protection Specification

[22] AR-FEN-30-DOEC-424012

Painting and Coating Specification for Risers and I-Tubes

[23] FEN-05503-DOMG-FEMGMOM-000045 [24] FEN-05503-DOEC-FEECTQR-000030

Corrosion Meeting #2 Technical Query – Pressure and Temperature for Sealines

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MATERIAL SELECTION AND CORROSION PREVENTION PHILOSOPHY FOR PIPELINES, RISERS AND I-TUBES Document Type: Phase:

PHI BE

System / Unit:

35

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2.3

01

Status

AFD

Rev. Date 28/JUL/2017 Page 7 of 22

Codes and Standards

[25] ASTM A194 (2017) [26] ASTM A320 (2015) [27] BS 6004 (2012)

Standard Specification for Carbon Steel, Alloy Steel, and Stainless Steel Nuts for Bolts for High Pressure or High Temperature Service, or Both Standard Specification for Alloy-Steel and Stainless Steel Bolting for LowTemperature Service Electric Cables. PVC Insulated and PVC Sheathed Cables for Voltages up to and Including 300/500 V, for Electric Power and Lighting

[28] BS EN 12496 (2013)

Galvanic Anodes for Cathodic Protection in Seawater and Saline Mud

[29] BS EN ISO 2081 (2008)

Metallic and other Inorganic Coatings. Electroplated Coatings of Zinc with Supplementary Treatments on Iron or Steel

[30] DNV-RP-B401 (2010)

Cathodic Protection Design

[31] DNV-RP-F112 (2008) [32] ISO 21457 (2010) [33] ISO 15589-2 (2012) [34] ISO 21809-1 (2011) [35] Norsok M-506 (2005)

2.4

CO2 Corrosion Rate Calculation Model

Other References

[36] FreeCorp

2.5

Design of Duplex Stainless Steel Subsea Equipment Exposed to Cathodic Protection Petroleum, Petrochemical and Natural Gas Industries - Materials Selection and Corrosion Control for Oil and Gas Production Systems Petroleum, Petrochemical and Natural Gas Industries - Cathodic Protection of Pipeline Transportation Systems - Part 2: Offshore Pipelines Petroleum and Natural Gas Industries - External Coatings for Buried or Submerged Pipelines Used in Pipeline Transportation Systems - Part 1: Polyolefin Coatings (3-Layer PE and 3-Layer PP)

Corrosion Prediction Software (V1.0) : Institute for Corrosion and Multiphase Technology, Ohio

Definitions

COMPANY (CPY)

Means Total Austral.

CONTRACTOR (CTR)

Means the named party with whom COMPANY will place a contract for engineering, procurement, supply, transportation, construction, installation and pre-commissioning of the facilities associated with the PROJECT

ENGINEER

Means DORIS Engineering

PROJECT

Means FENIX Development Project

VENDOR

Means any supplier of goods

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MATERIAL SELECTION AND CORROSION PREVENTION PHILOSOPHY FOR PIPELINES, RISERS AND I-TUBES Document Type: Phase:

PHI BE

System / Unit:

35

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3

4

01

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Rev. Date 28/JUL/2017 Page 8 of 22

Acronyms 3LPE

Three-layer Polyethylene

ASTM

American Society for Testing and Materials

BS

British Standard

CA

Corrosion Allowance

CI

Corrosion Inhibitor

CRA

Corrosion Resisting Alloy

DNV(GL)

Det Norske Veritas(Germanischer Lloyds)

EN

EuroNorm

H&MB

Heat & Mass Balance

HRC

Rockwell Hardness (C scale)

ISO

International Standards Organisation

MEG

Mono-Ethylene Glycol

MIC

Microbiologically Influenced Corrosion

PP

Polypropylene

PVC

Poly-Vinyl Chloride

ROV

Remote Offshore Vehicle

RP

Recommended Practice

SRB

Sulphate Reducing Bacteria

TLC

Top of Line Corrosion

UNS

Unified Numbering System

WCR

Water Condensation Rate

List of HOLDS HOLD1

Awaiting Safety Study completion

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MATERIAL SELECTION AND CORROSION PREVENTION PHILOSOPHY FOR PIPELINES, RISERS AND I-TUBES Document Type: Phase:

PHI BE

System / Unit:

35

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Document Reference: AR-FEN-30-DOEC-420010 Revision

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5

Main Conclusions

5.1

Pipelines

01

Status

AFD

Rev. Date 28/JUL/2017 Page 9 of 22

The following Table 5-1 summarises the materials of construction for the pipelines.

Pipeline

Material

24” Export Pipeline

CS + 3mm CA Note 1

4” MEG Pipeline

CS + 1mm CA

Note 1: CA based upon 100% corrosion inhibitory efficiency and 95% corrosion inhibitor availability in accordance with Company General Specification GS-EP-COR-001 Ref. [1] as maximum operating temperature is less than 90°C. Table 5-1: Pipeline Materials of Construction

5.2

Risers

The materials of construction shown in Table 5-1 above are also relevant for the risers except that the MEG riser shall have a minimum thickness of 10mm in the splash zone area, in accordance with the recommendations of Material Selection and Corrosion Control Philosophy Report for FENIX Phase 1 PreProject Ref. [15]. The 10mm minimum thickness shall also be applicable to future risers.

5.3

I-Tubes

The I-Tubes should be of carbon steel construction with a 6mm corrosion allowance. Internal and external coatings shall be in accordance with Project Specification for Painting and Coating of Risers and I-Tubes Ref. [22].

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MATERIAL SELECTION AND CORROSION PREVENTION PHILOSOPHY FOR PIPELINES, RISERS AND I-TUBES Document Type:

PHI

Phase:

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6

Design Data

6.1

Export Pipeline Operating Conditions

6.1.1

01

Status

AFD

Rev. Date 28/JUL/2017 Page 10 of 22

Pressure

The maximum operating pressure of the export pipeline at the top of the riser is 55 bar Ref. [24]. 6.1.2

Temperature

The maximum operating gas temperature at the entry to the export pipeline is 56°C Ref. [24].

6.2 6.2.1

Export Pipeline Process Data CO2 content

The CO2 content of the export gas is 0.12mol% Ref. [16].

Flow Rate 6.2.2 The maximum flow rate is 10 MScmd Ref. [24]. 6.3

MEG Pipeline

The MEG pipeline is considered to be a corrosion-free pipeline internally, as no corrodents are present.

6.4

Design Life

The design life of the Export pipeline and the MEG pipeline is 20 years.

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MATERIAL SELECTION AND CORROSION PREVENTION PHILOSOPHY FOR PIPELINES, RISERS AND I-TUBES Document Type: Phase:

PHI BE

System / Unit:

35

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7

External Corrosion Control

7.1

Corrosion in Seawater

01

Status

AFD

Rev. Date 28/JUL/2017 Page 11 of 22

Seawater environments are aggressive to many materials, including carbon steel, and, dependent upon the seabed conditions, local corrosion cells may be set up as a result the activity of the oxygen is increased. In addition the low oxygen content increases the activity of anaerobic bacteria (sulphate-reducing bacteria, SRBs). A combination of cathodic protection and coatings shall be used as primary protection of pipelines and associated components on the seabed.

Corrosion during Installation

7.2

Pipelines may be susceptible to severe corrosion during installation if it is not protected during the period between submergence and full operation of the cathodic protection system. Corrosion can occur both externally and internally (refer to Section 11 for internal controls). Pipelines and associated components shall be provided with sufficient corrosion control (anodes and coatings) to provide protection from the time of installation. This may include temporary corrosion inhibition.

Electrical Interconnection

7.3

Local differences in electrical potential between different components can accelerate corrosion but this can be controlled by cathodic protection. To achieve complete protection, equipment must be electrically bonded into the cathodic protection system. The jacket and the pipelines shall be electrically continuous. For the subsea pipelines cathodic protection shall be provided in accordance with ISO 15589-2 Ref. [33], as amended by COMPANY Standard GS-EP-COR-102 Ref. [4]. For the I-Tubes and Risers, cathodic protection shall be provided in accordance with DNV-RP-B401 Ref. [30], as amended by COMPANY Specification GS-EP-COR-102 Ref. [4], as part of the Jacket P Design using sacrificial anodes located on the jacket.

Coatings

7.4

Cathodic protection shall be supplemented with a robust corrosion control coating to perform the following: • •

Enhance the distribution of cathodic protection of carbon steel and other grades of steel which are otherwise unsuitable for service in seawater for the project design life; Provide colour for identification and subsea visibility.

Coatings are not required to provide thermal insulation on subsea systems.

7.4.1

Coating Systems

The coating system for carbon steel shall be:

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MATERIAL SELECTION AND CORROSION PREVENTION PHILOSOPHY FOR PIPELINES, RISERS AND I-TUBES Document Type: Phase:

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•

7.4.2

01

Status

AFD

Rev. Date 28/JUL/2017 Page 12 of 22

for the Export pipeline, a multi-layer polyolefin system (3LPE) to 3.5mm thickness according to ISO 21809-1 Ref. [34] Class B3, as modified by COMPANY Specification GS-EP-COR-220 Ref. [8] and pipeline bends and fitting, to COMPANY Specification GS-EP-COR-225 Ref. [9]; For the MEG pipeline, a multi-layer polyolefin system (3LPE) to 2.3mm thickness according to COMPANY Specification GS-EP-COR-220 Ref. [8] and pipeline bends and fitting, to COMPANY Specification GS-EP-COR-225 Ref. [9]; for Risers and I-Tubes, coating shall be in accordance with Painting and Coating Specification for Risers and I-Tubes Ref. [22]. The requirement for an elastomer-based coating in accordance with COMPANY Specification GS-EP-COR-233 Ref. [10] for areas where Passive Fire Protection is required is on hold [HOLD1], pending Safety study completion. for bolting systems used subsea, the coating system shall be temporary and shall be zinc coating by electroplating applied in accordance with BS EN ISO 2081 Ref. [29] with conversion coating Type C or D. The coating thickness shall be 25 microns minimum, in accordance with Company General Specification GS-EP-COR-356 [12].

Extent of Coating

All factory-supplied components manufactured in carbon steel shall be coated over 100% of the exposed (to seawater) surface. The extent of coating of corrosion resistant materials (i.e. materials such as Austenitic stainless steels, which achieve full resistance to seawater corrosion at potentials significantly less negative than those required to cathodically protect carbon steel) shall be determined during cathodic protection design. The uncoated areas of carbon steel shall be limited to areas at the back of flanges to ensure full electrical continuity between bolting systems and the flange. The cathodic design of the pipelines will take account of the bare areas in determining current demand.

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MATERIAL SELECTION AND CORROSION PREVENTION PHILOSOPHY FOR PIPELINES, RISERS AND I-TUBES Document Type: Phase:

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35

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Rev. Date 28/JUL/2017 Page 13 of 22

EXTERNAL CATHODIC PROTECTION

Cathodic Protection Design shall be based on ISO 15589-2 Ref. [27], as modified by COMPANY Specification GS-EP-COR-102 Ref. [4] for subsea pipelines, and as summarised in project pipeline cathodic protection specification Ref. [19].

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MATERIAL SELECTION AND CORROSION PREVENTION PHILOSOPHY FOR PIPELINES, RISERS AND I-TUBES Document Type: Phase:

PHI BE

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9

INTERNAL CORROSION/EROSION

9.1

Corrosion Assessment

01

Status

AFD

Rev. Date 28/JUL/2017 Page 14 of 22

The corrosion assessment has be undertaken in accordance with ISO 21457 Ref. [32], as modified by COMPANY specification GS-EP-COR-001 Ref. [1]. Design data from above section 6, together with the production fluid composition has been used to assess the potential for corrosion over the design life for the export pipeline and associated components. The corrosion assessment of the Export pipeline is presented in Appendix 1. The I-Tubes design shall include a corrosion allowance supplemented by internal corrosion coating.

9.2

Erosion Assessment

As agreed at Corrosion Meeting #2 Ref. [23], the work undertaken on erosion during the Pre-Project phase Ref. [15] has been used since there have been no changes to flow rates, sand production, pipeline sizes. Consequently, no solid erosion risk or pure sand erosion is foreseen on the 24” production sealine with regular sand production (i.e. 30kg/d sand rate with particle size 80μm).

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MATERIAL SELECTION AND CORROSION PREVENTION PHILOSOPHY FOR PIPELINES, RISERS AND I-TUBES Document Type: Phase:

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35

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Rev. Date 28/JUL/2017 Page 15 of 22

10 INTERNAL CORROSION CONTROL Protection of internal surfaces is required at all stages from fabrication through to the end of design life. The detailed philosophy for protection against corrosion is set out in this Section, however, the specific controls for each item of equipment must be stated on the drawings and approved by COMPANY.

10.1 During Installation and Commissioning Free flooding of components will present a risk of internal corrosion. Internal surfaces of line pipe shall be free of mill scale to provide a clean surface and to enhance tolerance of any inadvertent ingress of seawater. Blast cleaning may be used to remove mill scale. At sea bed pressure, entrapped air can support locally high rates of corrosion. Sufficient venting shall, therefore, be provided to allow entrapped air to be released during installation of the pipelines. The primary protection for the pipelines will be to prevent the ingress of raw seawater by the use of diver or ROV-removable covers. Facilities for diver or ROV replenishment of protective fluids shall be provided to cover for conditions where ingress of seawater may create a risk of corrosion.

10.2 Wet Storage To allow for changes in schedule, all items deployed subsea shall be suitable for prolonged insitu wet storage, by ensuring that internal fluids are treated so as to be benign with respect to corrosion. Cathodic protection systems shall be integral with the item to be protected to ensure that each discrete item deployed receives protection from the time of installation. Cathodic protection can cause scale formation on cathodic surfaces. Sealing surfaces are at risk of becoming contaminated and unsuitable for making a pressure tight seal. Sealing surfaces shall be covered or suitably treated so as to avoid such contamination. Pipework shall be installed with suitably robust end caps in place and with pipe filled with a non-corrosive fluid. Biocides (in liquid form) and glycol additions may be used to ensure that waters used for filling are effectively non-corrosive. The requirements of COMPANY Specification GS-EP-COR-560 Ref. [13] should be followed regarding water quality and treatment for prolonged wet storage. End caps used during wet storage shall be resistant to the pressures and incidental loads associated with deployment and extended wet storage. They shall also be removable by ROV. Facilities shall be available to allow additional chemical (e.g. biocide) to be added to a sealed space, should it be necessary to remove covers and replace them.

10.3 In Service The well fluids contain water and acid gas (CO2). These fluids are capable of corroding carbon steel at a rate dependant on operating pressure and temperature. Chemical treatment shall be used (injected at the well head) to protect carbon steel pipe during normal operation. Alternatively CRA materials can be used without the need for corrosion inhibition. The corrosion inhibition system shall be selected on the basis of performance testing and shall be COMPANY approved in accordance with Company General Specification GS-EP-COR-163 Ref. [6].

10.4 In-service Monitoring There are no facilities for subsea corrosion monitoring. Requirements for monitoring, if any, will be defined during design of corrosion control systems in accordance with COMPANY Specification GS-EP-COR-161 Ref. [5]. Generally, monitoring will be installed on topsides – project report AR-FEN-10-DOEC-420001 Ref. [17], addresses the requirements for corrosion and erosion monitoring on topsides.

This document is the property of TOTAL AUSTRAL. It must not be stored, reproduced or disclosed to others without written authorisation from the Company. R:\652618\Typing\DOCS\Docs\Natives\COR\AR-FEN-30-DOEC-420010_rev01 - Material selection corrosion prevention phi pip ris i-tubes\AR-FEN-30-DOEC-420010_rev01 - Material selection corrosion prevention phi pip ris i-tubes.docx

MATERIAL SELECTION AND CORROSION PREVENTION PHILOSOPHY FOR PIPELINES, RISERS AND I-TUBES Document Type: Phase:

PHI BE

System / Unit:

35

Discipline:

Equipment:

NA

Class:

Document Reference: AR-FEN-30-DOEC-420010 Revision

COR 2

Contractor reference number: NA

01

Status

AFD

Rev. Date 28/JUL/2017 Page 16 of 22

10.5 Compatibility of Chemical Treatments Compatibility tests shall be performed on all chemical treatments (temporary and through life) to establish any adverse interactions with treatments which could become mixed.

This document is the property of TOTAL AUSTRAL. It must not be stored, reproduced or disclosed to others without written authorisation from the Company. R:\652618\Typing\DOCS\Docs\Natives\COR\AR-FEN-30-DOEC-420010_rev01 - Material selection corrosion prevention phi pip ris i-tubes\AR-FEN-30-DOEC-420010_rev01 - Material selection corrosion prevention phi pip ris i-tubes.docx

MATERIAL SELECTION AND CORROSION PREVENTION PHILOSOPHY FOR PIPELINES, RISERS AND I-TUBES Document Type: Phase:

PHI BE

System / Unit:

35

Discipline:

Equipment:

NA

Class:

Document Reference: AR-FEN-30-DOEC-420010 Revision

COR 2

Contractor reference number: NA

01

Status

AFD

Rev. Date 28/JUL/2017 Page 17 of 22

11 SELECTION OF MATERIALS 11.1 Export Pipeline The corrosion assessment presented in Appendix 1, indicates that a 3mm corrosion allowance is sufficient for the 20 year design life, provided that the corrosion inhibitor injected at the wellhead has a minimum of 95% availability. Top of the Line corrosion is not considered to be a problem as operating temperatures are low and temperature differentials small. 11.1.1

Solid Erosion Corrosion / Pure Erosion

No solid erosion risk or pure sand erosion is foreseen on the 24” production sealine with regular sand production (i.e. 30kg/d sand rate with particle size 80μm) based on Pre=Project Study Ref. [15]. 11.1.2

Microbial Induced Corrosion

MIC risk is low on the 24” production sealine and should be manageable with only operational pigging using hard plate pigs (to be optimized over time with consideration of the possible accumulation of sand / organic sludge and from bacterial monitoring results). Pig traps are made available for such operations. Physical and chemical treatment of hydrostatic test water shall be undertaken in accordance with Company General Specification GS-EP- COR-560 Ref. [13]. 11.1.3

Top of Line Corrosion

No further data on Water Condensation Rate is available since the Pre-Project Report Ref. [15], and, therefore, the same conclusions are drawn. Top of Line Corrosion has not been formally assessed as no Water Condensation Rate (WCR) profile has been provided at this stage. TLC is not foreseen for FENIX sealine due to a combination of low inlet temperature (