fi ts msg 001 material selection

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FFAACCIILLIITTIIEESSIINNTTEEGGRRIITTYYDDEEPPAARRTTMMEENNTT

ZADCO

(MSG)

No. FI/TS/MSG/001

CORNELIUS O. EMENIKE FRANCIS J. EGAN OBAID S. KHATEM0

PREPARED BY REVIEWED BY APPROVED BY

METALLURGIST FIP TEAM LEADER FI MANAGERREV.

Date: 30 September 2003 Date: Date:

MATERIAL SELECTION GUIDELINES


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FACILITIES INTEGRITY DEPARTMENT Date: 30 Sep 2003

FI/TS/MSG/001MATERIAL SELECTION GUIDELINES

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REVISION CONTROL SHEET

REV NO. DATE OF ISSUE DESCRIPTION

A 31 May 2003 Issued for intra discipline check

0 30 Sep 2003 Issued for implementation


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FACILITIES INTEGRITY DEPARTMENT Date: 30 September 2003


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TABLE OF CONTENTS

(Click the subject to browse)

1. PURPOSE...............................................................................................................................................................................................6

2. SCOPE.....................................................................................................................................................................................................7

3. DEFINITIONS .........................................................................................................................................................................................7

3.1. Integrity...................................................................................................................................................................................................7

3.2. Asset........................................................................................................................................................................................................7

3.3. Risks........................................................................................................................................................................................................8

3.4. Risk assessment must address:......................................................................................................................................................8

3.5. Key Performance Indicators (KPIs) and Assurance...................................................................................................................8

3.6. Review, Improve and Change...........................................................................................................................................................8

3.7. Responsibilities....................................................................................................................................................................................8

4. ACRONYMS .........................................................................................................................................................................................10

5. REFERENCES .....................................................................................................................................................................................11

6. GENERAL PRINCIPLES OF MATERIAL SELECTION................................................................................................................12

6.1. Design life and system availability requirements.....................................................................................................................12

6.1.1Some Comments On Materials/ Corrosion..................................................................................................................................13

6.1.2Galvanic corrosion ............................................................................................................................................................................13

7 MATERIAL SELECTION FOR SPECIFIC APPLICATIONS /SYSTEMS...................................................................................14

7.1 Well completion ..................................................................................................................................................................................14

7.1.1Downhole Tubing Selection in ZADCO ........................................................................................................................................157.2 Topside facilities ................................................................................................................................................................................17

7.3 Oil and gas processing.....................................................................................................................................................................18

7.4 Seawater systems..............................................................................................................................................................................18

7.5 Recommendation:..............................................................................................................................................................................23

7.6 Water Injection ....................................................................................................................................................................................23

7.7 Recommendation:..............................................................................................................................................................................23

7.8 Bolting materials for piping, equipment, structural and sub sea applications .................................................................23

7.8.1Corrosion Protection of the Bolting system...............................................................................................................................24

7.8.2ZADCO specification for structural application are summarized below:...........................................................................25

7.9 Subsea production and flowline systems...................................................................................................................................257.10 Flexible flow lines and risers..........................................................................................................................................................29

7.11 Subsea production control systems.............................................................................................................................................29

7.12 Drilling and workover risers............................................................................................................................................................30

7.13 Pipeline systems................................................................................................................................................................................30

7.14 Sour services ......................................................................................................................................................................................31

7.15 Chains and mooring lines for floating units ...............................................................................................................................31

8 DESIGN LIMITATIONS FOR CANDIDATE MATERIALS ............................................................................................................31

8.1 Materials for pressure retaining purposes..................................................................................................................................32

8.1.1General..................................................................................................................................................................................................32

8.1.2Material Selection for pumps..........................................................................................................................................................32

8.1.3Firewater pumps.................................................................................................................................................................................32


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8.1.4Seawater Lift (Winning) Pump........................................................................................................................................................33

8.1.5Injection pump ....................................................................................................................................................................................33

8.1.6Main Oil Line Pumps .........................................................................................................................................................................33

8.1.7Downhole Pump .................................................................................................................................................................................338.1.8Other Rotating equipment ...............................................................................................................................................................34

8.1.9Valves....................................................................................................................................................................................................34

8.1.10 Instruments ....................................................................................................................................................................................34

8.1.11 Life Saving ......................................................................................................................................................................................34

8.2 Gratings ................................................................................................................................................................................................38

9 GUIDELINES ON GENERAL PROPERTIES AND PRECAUTIONS WHEN USING SPECIFIC MATERIALS ..................40

9.1 Carbon Steel........................................................................................................................................................................................40

9.2 Clad carbon steel...............................................................................................................................................................................40

9.3 Stainless steels...................................................................................................................................................................................40

9.4 Martensitic & Ferritic SS ..................................................................................................................................................................41

9.5 Duplex SS (DSS) .................................................................................................................................................................................43

9.6 Super Duplex Stainless Steel (SDSS)...........................................................................................................................................44

9.7 Aluminum and its Alloys ..................................................................................................................................................................45

9.8 Copper-Nickel Alloys ........................................................................................................................................................................46

9.9 Nickel and its Alloys ..........................................................................................................................................................................47

9.10 Titanium and its alloys. ....................................................................................................................................................................48

9.11 Metallic Coating ..................................................................................................................................................................................49

9.11.1 Electroless Nickel Plating (ENP)...............................................................................................................................................49

9.12

Polymeric Materials ...........................................................................................................................................................................49

9.13 Reinforced Plastics............................................................................................................................................................................50

9.14 GRP Piping...........................................................................................................................................................................................50

9.15 Passive Fireproofing Materials.......................................................................................................................................................50

10 APPENDIX A (MATERIAL SELECTION DIAGRAM) ................................................................................................................53

11 ZADCO FAILURE INVESTIGATION (Appendix-B) .............................................................................55

1. INTRODUCTION..................................................................................................................................................................................55

2. FAILURE MECHANISMS ...................................................................................................................................................................55

2.1. Ductile Fracture/Ductile Overload .................................................................................................................................................55

2.2. Brittle fracture.....................................................................................................................................................................................56

2.3. Fatigue failure .....................................................................................................................................................................................56

2.4. Creep Failure .......................................................................................................................................................................................57

2.5. Wear Failures ......................................................................................................................................................................................57

2.6. Distortion Failures .............................................................................................................................................................................58

2.7. High Temperatures softening .........................................................................................................................................................58

2.8. Erosion Corrosion ..........................................................................................................................................................................59

2.9. Fretting Failure....................................................................................................................................................................................60

2.10.Corrosion Induced Failures.............................................................................................................................................................60

2.11.General Corrosion..............................................................................................................................................................................60

2.11.1. Pitting ...............................................................................................................................................................................................60

2.11.2. Crevice Corrosion.........................................................................................................................................................................61

2.11.3. Microbiologically induced corrosion (MIC) ............................................................................................................................62


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2.11.4. Galvanic Corrosion. .....................................................................................................................................................................63

2.11.5. Stress Corrosion Cracking (SCC) ............................................................................................................................................63

2.11.6. Chloride induced stress corrosion cracking (CSCC) ...................................................................................................64

2.11.7. Wet H2S (Sour) Corrosion...........................................................................................................................................................652.11.8. Dealloying attack ..........................................................................................................................................................................66

2.11.9. Liquid Metal Embrittlement (LME) ............................................................................................................................................66

2.11.10.Corrosion under insulation (CUI) .............................................................................................................................................67

3. DEGRADATION OF NON-METALLIC MATERIALS ....................................................................................................................69

3.1. Swelling and dissolution..................................................................................................................................................................70

3.2. Chemical Degradation ......................................................................................................................................................................70

3.3. Thermal Degradation.........................................................................................................................................................................70

3.4. UV degradation...................................................................................................................................................................................71

3.5. Explosive Decompression...............................................................................................................................................................71

4. REFERENCES .....................................................................................................................................................................................71

5. FLOW DIAGRAM FOR FAILURE INVESTIGATION ....................................................................................................................75


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.. PPUURRPPOOSSEE

This document (MSG) is part of ZADCO Asset Integrity Management System (AIMS),

see fig. 1 below, which identifies the strategies required to effectively manage materialsfor all ZADCO assets. MSG is a component of the integrity of ZADCO assets. Itexamines, inter alia, asset availability. Life cycle cost approach will be its main focus.

This will be correlated with reviews and analysis of design and process parameters/fluidchemistry. MSG will be used to meet the requirements of statutory regulations in linewith HSEMS.

Fig. 1 Shows MSG as a part of AIMS

PROCESSES ASSETS

ASSURANCE

HSEMS ZBRMS

AIMS

DESIGN

PROCURE

BUILD/ INSTALL

OPERATE

CORROSION

MANAGEMENT

INSPECTION

MAINTENANCE

CHANGE

PIMS

SIMS

EPRS

LEMS

PSV

I MS

MMS

MSG

THIS DOCUMENT

WELLS

PIPELINES

STRUCTURES

PRESSURE EQUIP

ROTATING EQUIP

ELECTRICAL EQUIP

INSTRUMENTS

EMERGENCY& LIFE SAVING

CMS

POMS PEMS

WIMS

CAMS


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.. SSCCOOPPEE

MSG addresses the optimum material selection of piping, pipelines and equipment within

ZADCOs business units. It aims at minimizing the risk of failure for a given design life of

say 30 years. This document also addresses materials failure investigation and

subsequent recommendation as input to asset integrity from concept, through design

and maintenance to abandon.

Fig 2. The integrity life cycle of an asset is considered as per the following diagram: (See

CMS for details)

QA/QC

BUILD/

PROCURE

CORROSION

OPERATE

COMMISSION

DESIGN

CHANGE

REVIEW/

IMPROVE

MAINTAIN

INSPECTION

ASSET INTEGRITYMANAGEMENT SYSTEM

CONCEPT ASSURANCE ABANDON

.. DDEEFFIINNIITTIIOONNSS

3.1. Integrity

An asset has integrity if it operates as designed for its assigned life (or greater)with all its risks kept as low as reasonably practicable, or as nominated.

3.2. Asset

In the context of this document, an asset is an engineered piece of equipment. Itcan be categorized into business unit (BU), process train/unit (e.g. Crude


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stabilization), equipment type (e.g. pipelines, structures) or equipment tag

numbers.

3.3. Risks

Risk assessments are done, either qualitatively or quantitatively to ensure that allmaterial selection activities are fully justified and prioritised in accordance withboth economic necessity and ZADCOs commitment to health, safety and theenvironment. ZBRMS will be followed.

3.4. Risk assessment must address:

Probabilities of failure

Safety consequences of failure

Economic consequences of failure Environmental consequences of failure

3.5. Key Performance Indicators (KPIs) and Assurance

The effectiveness of MSG will be judged by materials/equipment attaining theiroptimal life at a minimum OPEX. However, service failures may not be attributed

to wrong material selection. For example, a bad design, e.g. a high level of torquecan lead to premature failure of a good bolting material. Hence, it is prudent tocarry out failure investigation to address the questions why, how and what.

Therefore, decisions can be made on material upgrading due to changingoperating environment or like to like replacement for materials that have attained

economic life

3.6. Review, Improve and Change.

This involves intimacy with technological developments, which may conferobsolescence or change the boundary conditions for the application of existing

materials. For example, NACE MR0175-2003 has apparently deleted Monel 400from the list of materials for sour service application.

3.7. Responsibilities

Below (Table-3.1) is a responsibility matrix adapted from CMS. This gridhighlights the relationship among various ZADCO departments for the upkeep ofasset integrity.


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Table 3.1

ASSET INTEGRITY RESPONSIBILITY MATRIX

ASSET

PROCESSWELLS PIPELINES STRUCTURES LIFTING PE PSVs ELECT RE INST.

EMERG.FIREFIGHTING

LIFESAVING

PROCESSTIA

DESIGN FD/SSE FI FE FE FE FE FE FE FE FE BU FE

PROCURE ADMA CM CM CM CM CM CM CM CM CM CM CM

BUILD/COMM. SSE FE FE FE FE FE FE FE FE FE FE FE

OPERATE BU BU BU BU BU BU BU BU BU BU BU BU

CORR.MGMT FIP FIP FIP FIP FIP FIP BU BU BU FIP FIP FIP

CMS FIP FIP FIP FIP FIP FIP BU BU BU FIP FIP FIP

MSG FIP FIP FIP FIP FIP FIP BU BU BU FIP FIP FIP

INSPECTION/TEST WORC FIP FIP FIP BU BU BU BU BU BU FIP FIP

MAINTENANCE WORC FIP BU BU BU BU BU BU BU BU BU FIT

REVIEW/IMPROVE FD FIP FIP FIP FIP FIP BU BU BU BU BU FI/FE

CHANGE/REPAIR SSE/FD FIP BU BU BU BU BU BU BU BU BU FE/BU

ASSET TIC WORC FIP FIP FIP FIP FE FE BU BU BU BU

NB: Position indicators used are those current at time of writing and the roles and indicators may change with time.


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.. AACCRROONNYYMMSS

AFFF Aqueous Film Forming Foams

AIMS Asset Integrity Management System

CAPEX Capital Expenditure

CMS Corrosion Management System

CPT Critical Pitting Temperature

CRAs Corrosion Resistant Alloys

CTOD Crack Tip Opening Displacement

EPRS Emergency Pipeline Repair System

GMAW Gas Metal Arc WeldingGRP Glass Reinforced Plastic

GTAW Gas Tungsten Arc Welding

HAZ Heat Affected Zone

IMS Inspection Management System

LEMS Lifting Equipment Management System

LTHAZ Low Temperature Heat Affected Zone

MIC Microbial Induced Corrosion

MIG Metal Inert Gas

MMS Maintenance Management System

MSG Material Selection Guideline

NPSH Net Positive Suction Head

OPEX Operating Expenditure

PEMS Pressure Equipment Management System

PIMS Pipeline Integrity Management System

PREN Pitting Resistant Equivalent NumberPSVs Pressure Safety Valves

SIMS Structures Integrity Management System

SRB Sulfate Reducing Bacteria

TIG Tungsten Inert Gas

WIMS Well Integrity Management System


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.. RREEFFEERREENNCCEESS

1. ZADCO HSEMS

2. ZBRMS

3. AIMS

4. CMS

5. PIMS

6. Piping specifications, Z0-TS-P-05010

7. Coating Specification, Z0-TS-Y-02010

8. ZADCO Specification for instrument materials, Z0-TS-J-01050

9. ZADCO Specification for rotating equipment, Z0-TS-M-01050

10. American Iron and steel institute (AISI)11. American society for Testing and Materials (ASTM)

12. American Petroleum Institute (API)

13. The American society of mechanical engineers (ASME)

14. The unified Numbering system (UNS)

15. API 5L specification for Line pipe

16. Specification for wellhead and Christmas tree equipment.

17. ASME B 31.3 Process piping

18.ASTM A 193 specification for carbon steel bolts and nuts, upto 60,000psiTensile Strength stainless steel bolting Materials for Higher - Temperature

Service

19. ASTM 194 specification for carbon and Alloy steel Nuts for bolts for High-pressure and High temperature service

20. ASTM A 307 specification for alloy steel bolting materials for non-structuralapplication

21. ASTM A 320 Specification for alloy steel Bolting Materials for lowtemperature service.

22. ASTM A 325 specification for carbon steel bolting materials for offshore

applications.

23. EFC publication number 16: Guidelines on Material for carbon and Low alloy

steel for H2S Environments in oil and Gas production.

24. EFC publication number 17: corrosion resistant alloys for oil and gasproduction. Guidance on general requirements and test methods for H2Sservice.

25. ISO 898 mechanical properties of fasteners

26. ISO 11960 Steel pipes for use as casing or tubing for well (replaced API 5CT)

27. MTI Manual No.3: Guideline information on newer Iron and Nickel basecorrosion resistant alloys, Phase 1, corrosion test methods (appendix B,Method MTI-2)


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28. NACE MR 0175: Metals for Sulfide stress cracking & stress corrosion

cracking resistant in sour for oil field environment.

29. NACE RP0475: Selection of Metallic Material to be used in all phases ofwater handing for injection into Oil Bearing Formations

30. NORSOK standard M-001, Rev.2 November, 1997

31. Engineering equipment and materials users association (EEMUA)

32. Shell EP 2001-5024: Material Failure modes, mitigation methods andgeneral material properties F.Egan, S. Frost, I. Rippon and L. Smith

33. API RP 17B recommended practice for flexible pipes, 3rdedition.

34. ASTM A 123: Standard Specification for Zinc (Hot-Dip-Galvanized) coatingson iron and steel products.

35. DIN EN ISO 1461: Hot dip galvanized coatings on fabricated iron and steel

articles Specifications and test methods (ISO1461: 1999)

.. GGEENNEERRAALLPPRRIINNCCIIPPLLEESSOOFFMMAATTEERRIIAALLSSEELLEECCTTIIOONN

The process flow diagram (PFD) and the process conditions usually precede thematerial selection diagram (MSD). The process parameters dictate the material of

construction (MOC). The MOCs for equipment and piping is reflected in the PFD.Details such as corrosion allowance, symbols/notes for individual materials, corrosion

monitoring and injection points fabrication and inspection requirements are shown in theMSD. Examples are shown in the Appendix A.

Material selection shall be optimised, considering investment and operational/

maintenance costs, such that life cycle cost (CAPEX & OPEX) are minimised whileproviding acceptable safety and reliability. As a minimum, attention shall be paid to:

Corrosivity, taking into account specified operation conditions including start-up and

shutdown conditions.

.. .. DDeessiiggnnlliiffeeaannddssyysstteemmaavvaaiillaabbiill iittyyrreeqquuiirreemmeennttss..

Failure probabilities, failure modes and failure consequences for human health,

environment, safety and materials assets

Inspection and corrosion monitoring possibilities.

The final material selection shall address the following additional factors:

Priority shall be given to materials with good market availability and documentedfabrication and services performance.

The number of different materials shall be minimised considering stock, costs,interchangeability and availability of relevant spare parts.


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Deviations from materials selections specified in this guideline may be

implemented if an overall cost, safety and reliability assessment shows to be morecost effective. Such deviations may include replacing CRAs with carbon steel.

Inspection, corrosion and structures are covered by PIMS, CMS and SIMS.

6.1.1 Some Comments On Materials/ Corrosion

Any component permanently exposed to seawater and for which

efficient cathodic protection cannot be ensured, shall be fabricated in

materials immune to corrosion in seawater. Exceptions are components

where corrosion can be tolerated. Material selection should take into

account probability for and consequence of component failure.

The following materials are regarded as immune to corrosion whensubmerged in seawater at ambient temperature:

Alloy 625 and other nickel alloys with equal or higher PREN value.

Titanium alloys careful about CP, pure methanol (


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Install internal sacrificial anodes through access fittings near the

interface, e.g. resistor controlled CP. This works only when the systemis filled up with a conductive liquid, and special precautions during

commissioning and shut-in is required.Generally, at galvanic connections between dissimilar materials withoutisolation/distance spool, it can be assumed that the local corrosion rate

near the interface is approximately three times higher than the averagecorrosion rate, decreasing exponentially away from the interface within a

length of 5 pipe diameters. This should be used to estimate themagnitude of the corrosion allowances. Particular system may havehigher corrosion rates, which depends on area ratio and material

combinations.

For connections between copper alloys and stainless steel/nickel

alloys/titanium, the use of easily replaceable spools with added wallthickness shall be evaluated.

In hydrocarbon systems, isolating spools shall be avoided and transitions

shall normally be made in dry, inhibited or other areas with low Corrosivity.

Corrosivity evaluation in hydrocarbon systems:

Evaluation of Corrosivity shall as a minimum include:

CO2-content

H2S Concentration

Oxygen content and concentrations of other oxidizing agents.

Operating temperature and pressure

Acidity, pH

Halide, metal ion and metal concentration

Velocity, flow regime and sand production

Biological activity.

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Introduction

This section gives requirements to material selection for specific areas and systems.

7.1 Well completion

All well completion materials, including elastomers and polymeric materials, shallbe compatible with produced fluid. In addition, the materials shall as a minimumbe compatible with the following well intervention fluids with additives for relevantexposure durations:

Completion and packer brine fluids

Mud acids (HCI-hydrochloric acid, HF- Hydrofluoric acid)


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Stimulation fluids

Scale inhibitors

Methanol

7.1.1 Downhole Tubing Selection in ZADCO

Downhole materials selection for UZ producers is based on a corrosionmodel (ZADCORE) developed by Taywood Engineering Ltd.

Based on well parameters, recommendations are made for carbon steelwith inhibitor squeeze, 13% Cr or Alloy 28 & alloy 825.

The output for the recommended material is based on the ground of

technical suitability and economics taking into consideration the life cyclecost (LCC) and risk assessment. As of today, ZADCO uses either carbon-

steel or 13% Cr tubing.

After GBT material upgrading, to alloy 28 & alloy 825 may benecessary because of a potential increase in the partial pressure of

H2S.

Gas injection wells were completed with carbon steel after evaluation

of the well conditions. ADMA-OPCO used the same material for gasinjection well.

Gas lift wells were completed with 13% Cr for all items located belowchemical injection points (side pocket mandrel) and carbon steel abovethe injection point with the provision of corrosion inhibition at the

surface.

Material selection for well completion is given in table 7.1


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Table 7.1 Material selection for wells, sheet 1 of 2

WELL TYPE TUBING AND LINER Completion equipment(where different from

tubing / liner) Notes

13 Cr is Base Case.See table 8.1 for design limitations.

1

Low alloy steel. (Option for systemswith low corrosivity /short lifetime)

13 Cr 1,2

Production

13% Cr and 15% Cr alloys modified

with Mo/Ni, duplex and austeniticstainless steel and nickel alloys are

options for high corrosivity

3

Deaeratedseawaterinjection

Low alloy steel UNS N09925, Alloy 71822Cr or 25 Cr duplex

2, 4, 7

Low alloy steel with GRP or other

lining

Titanium. See also table

8.1

5,8,9

Low alloy steel for short design life Titanium. See also table8.1

Raw

seawaterinjection

Titanium for design limitations Table 8.1

Low alloy steel 13 Cr (Limitations as for

tubing for this service)

1, 2,6

Low alloy steel with GRP or otherlining

13 Cr (Limitations as fortubing for this service).

1, 5

13 Cr. Provided oxygen < 10 ppb, seealso table 8.1

1

Produced

water andaquiferwater

injection

22Cr duplex, alloy 718, N09925.

Provided oxygen


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Notes

1. For fluids with a partial pressure of H2S above 0.1 bar or pH below 3.5, 13Cr shall

have a maximum SMYS of 560 MPa (80 ksi). Limiting the strength is generallyrecommended to avoid hydrogen stress cracking caused by hydrogen formed bygalvanic corrosion of the casing.

2. Low alloy steel with approximately 0.5% Cr and proper corrosion allowance for tubing.

Use of same CRA as for completion equipment shall be evaluated for liners.

3. Cold worked grades of duplex stainless steel shall be limited to 862 MPa (125 ksi)

SMYS and maximum 96 MPa (140 ksi) actual yield strength in longitudinal andtangential direction.

4. Detailed material selection for completion equipment to be based upon design

requirements and supplier experience.

5. For GRP lining, qualification is required unless field experience can be provided.

6. CO2 corrosion rates estimate shall be based on corrosivity evaluation. Corrosioninhibitors can be used in oxygen free systems provided acceptable from reservoirconsiderations.

7. Low alloy steel can be used in components located in lower sections of the well ifstrict dimensional tolerances in service are not required.

8. For short design lives and low temperatures, stainless steels or Ni-based alloys maybe considered for completion equipment.

9. Raw seawater contains oxygen and may or may not contain chlorine.

7.2 Topside facilities

Carbon steel can be used in topside systems where the calculated annualcorrosion rates is less than corrosion allowance divided by design life. Forinhibitors in topside systems corrosivity evaluation is necessary.

The piping materials shall be standardised on the following material types as faras practical:

Carbon steel ASTM A106 Grade B

Stainless steel Type 316

Stainless steel Type 22Cr and 25Cr duplex

Stainless steel Type 6Mo

Titanium

GRP

Other materials shall only be introduced after their performance and availabilityhave been considered.

Cast stainless steel Type 6Mo shall not be used for components to be welded.


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Material sections for topside facilities are given in table 7.2 with amendments asgiven below. A premise for the selections in the table has been limitation of

number of grades and types for each application.

7.3 Oil and gas processing

For evaluation of corrosivity in a vessel (i.e. separator or scrubber) and in theliquid carrying piping downstream the vessel, the CO2 and H2S partial pressuresin the gas carrying piping downstream the vessel can be used. To compensatefor the fact that these gases are not at equilibrium with the liquid in each vessel,the corrosion rate found by corrosivity evaluation shall be increased by 25% for

separators and liquid carrying piping downstream the separators. Nocompensation is required for gas scrubbers and liquid carrying piping downstream

scrubbers.

Pressure rating, maximum/minimum design temperature and size shall be taken

into account when selecting materials.

All components which may contact oil well streams shall be resistant against welltreating, well stimulating chemicals and other additives.

7.4 Seawater systems

Hot dip galvanized carbon steel can be used in seawater systems provided it is

documented to be cost efficient and replacement is planned for in design ifnecessary. If this material is evaluated for usage in firewater systems, specialattention shall be made to the risk for plugging of sprinkler/deluge nozzles.

Based on an evaluation in each case, internal cathodic protection of stainless

steel and other passive materials may be used for piping and components.

Graphite gaskets shall not be used in seawater piping systems.

For piping downstream heat exchangers it shall be taken into account that

relatively high operating temperatures may occur when marine fouling is notpresent inside the heat exchanger, i.e. initially and after cleaning operations.


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Table 7.2 MATERIALS FOR TOPSIDE FACILITIES

Facilities Materials Notes

Oil and gas production and processing Corrosivity evaluations shall be carried out

Wellhead equipment/X-mas tress

13 Cr4Ni, Low alloy steel with alloy 625 weld overlay API 6A 1

Piping and vessels 22Cr duplex, 25Cr duplex, 6Mo. 316

Thick wall vessels Carbon steel with 316, alloy 625, Alloy825 or 904 clad or weld overlay

Piping and vessels in low corrosivitysystems

Carbon steel

Inlet side of compressorsCarbon steel. Carbon steel with CRA weld overlay or solid CRA if required, basedupon corrosivity evaluations

Piping, vessels for produced water 316, 22 Cr duplex, 25Cr duplex, 6Mo, Titanium or GRP

Seawater systems and raw seawaterinjection

See also 7.4 4

Wellhead equipment/X-mas trees

Carbon steel with weld overlay

VesselsTitanium, GRP, carbon steel with internal rubber lining or organic coating incombination with cathodic protection.

Piping materials 6Mo, 25Cr duplex, Titanium, GRP

Piping components 6Mo, 25Cr duplex, Titanium, Alloy 625, Alloy C276, Alloy C22. 2,3

Valves in GRP systems GRP, Carbon steel with polymeric lining, NiAl bronze.Normally drained systems Copper base alloys, 6Mo, Titanium, Carbon steel for short lifetimes, e.g. 5-10 years. 4

Pumps 25Cr duplex, 6Mo, Titanium, 5.6

Deaerated seawater injection See also 7.1.

Wellhead equipment/X-mas treesLow alloy steel with Alloy 625 weld overlay in sealing surfaces.Design must allow for corrosion on non overlaid parts, API 6A

Piping Carbon steel, GRP.

Deaerated Tower Carbon steel with internal organic coating, plus Cathodic protection in bottom section.


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Pump and valve internals Provided CARBON STEEL HOUSING: 13Cr4Ni, 316, 22 Cr duplex, 25 Cr duplex. 6

Produced water and aquifer water injectionCarbon steel, 316, 22 Cr duplex, 6 Mo, Titanium, GRP.Wellhead and X-mas trees as for deaerated seawater injection.

Fresh and potable water Hot dip galvanized carbon steel, GRP, Poloypropylene, 316, Copper base alloys. 7

Drains and sewage

Open drain GRP, carbon steelClosed drain without oxygen 316, carbon steel

Closed drain with oxygen 22Cr duplex, 25 Cr duplex, 6Mo, Titanium, GRP

Sewage GRP, polyethylene.

Flare Systems

Relief system 316, 6Mo, low temperature carbon steel.

Burner components (Flare Tips)Alloy 800H, alloy 800 HT, Alloy 625; For temperatures below 650C: 310, HR120,RA330

Flare boom Structural steel with thermally sprayed aluminum.

Dry fuel gas and diesel Carbon steel

Piping Carbon steel

Tanks Carbon steel, GRP 8

Lubrication and seal oil 316, 22Cr duplex, 6Mo 9

Hydraulic fluid 316, carbon steel upstream filters.

Instrument air 316, carbon steel upstream filters.Inert gas/plant air piping Carbon steel, 316.

Instrumentation

Tubing 316, Titanium, 904L 5,10

Junction boxes/cabinets GRP, 316

Cable trays 316; Hot dip galvanized carbon steel in fully HVAC controlled areas.

HVAC ducts and units

Ventilation/air intake ducts 316, Hot dip galvanized steel 11


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Air handling units 316.

Seawater Coils Titanium

Active fire fighting systems

Dry CO2 systems Carbon steel

Freshwater/plant air/nitrogen 316 5

Glycol Carbon steel, 316Methanol Carbon Steel, 316

AFFF 316, GRP

Heating/cooling media Carbon steel. CRA in heat exchange tubes.

Miscellaneous chemical systems GRP, 316, 6Mo, Titanium 12

Bolting materials See 7.6

Notes:

1. Sealing surfaces of components In Type 13Cr4Ni shall be overlay welded with alloy 625. For wells with low corrosivity and/or short lifetime,low alloy steel with alloy 625 weld overlay in sealing surfaces only can be used.

2. Shall also be used for process-wetted parts of instrument systems.

3. See 8 for materials for pressure retaining purposes. Weld overlay can be applied to prevent crevice corrosion.

4. Copper alloys shall not be used in combination with CRAs and Titanium. Exception can be components in fire water systems, providedgalvanic corrosion can be avoided by proper isolation. If electrical isolation (15,000 ohm in dry system) is ensured and verified after

installation, mechanical connections between bronze/brass and noble alloys such as Type 6Mo and titanium alloys are acceptable.

5. See 8.1/8.2 for design limitations.

6. Ceramic filled epoxy coating can be used for shorter lifetime, e.g. 5-10 years.

7. Large diameter piping and tanks can bee made in internally coated carbon steel. Tanks not intended for potable water, shall in addition becathodically protected. GRP polypropylene and coating used for potable water shall be accepted by the national health authorities.

8. Tanks in carbon steel shall have 3mm corrosion allowance at the bottom section. In addition the bottom and roof shall be coated. Externalcathodic protection is recommended for tank bottoms. Also secondary containment (GRP lining up to 1m) is recommended for hydrocarbontank bottoms. This is ZADCO s practice.


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9. Type 316 is acceptable up to operating temperature 70C provided it is located indoor or in sheltered areas and not insulated.

10. For uninsulated stainless Type 316 instrument piping downstream a shut-off valve, normally no extra precautions are required, providedprocess medium temperature is below 85C and there is no flow in the instrument piping.

11. Hot dip galvanized steel can be used in living quarter and domestic areas.

12. The combination of chemical and material has to be considered in each case. Titanium or GRP shall be used for hypochlorite systems.


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7.5 Recommendation:

It is recommended to limit pressure rating of seawater systems to 10 bar in order

to be able to use qualified valves in GRP and carbon steel with polymeric lining. Ifcarbon steel valves with polymeric lining is considered for CRA based piping

systems, the valve design shall be critically assessed with respect to possibleaccelerated galvanic corrosion.

7.6 Water Injection

Water injection covers systems for injection of deaerated seawater, raw untreatedseawater and produced water. Please see NACE RP 0475-98.

Corrosivity evaluations for deaerated injection seawater shall, for conventional

deaeration process be based on a maximum operating temperature of 30C andthe following Oxygen Equivalent levels (oxygen equivalent = ppb oxygen+0.3ppbfree chlorine).

50 ppb for 90% of operation time

200 ppb for 10% of operation time, non continuous.

Even if the specification for the deaeration equipment gives more strict

requirements, the above shall be basis for the material selection. If the specifiedOxygen Equivalent nor temperature is above 50 ppb or 30C respectively for

normal operation, the basis for material selection shall be subject to specialevaluation.

7.7 Recommendation:

For carbon steel submarine injection flow lines the corrosion allowance should beminimum 3 mm. In injection water system where alternating deaerated seawater,

produced water, aquifer water and/or gas could flow through the systems,material selection shall take this into account. All components which may contactinjection water or back-flowing fluids shall be resistant against well treating

chemicals or well stimulating chemicals in case of back-flow situations. Forcarbon steel piping, the maximum velocity shall be 6m/s.

.. Bolting materials ffoorrppiipp iinngg,,eeqquuiippmmeenntt,, ssttrruuccttuurraa llaannddssuubbsseeaaaapppplliiccaattiioonnss

The general bolting material for bolt diameters above 10 mm in piping systemsand equipment shall be carbon or low alloy steel selected in accordance with the

ASTM Standards listed in table 7.3 below. Bolts with a diameter


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Table 7.3 Temperature range for bolting materials

Temperature

range (C) BOLT NUT

Size range

(mm)

A 320 Grade L7 A 194 Grade 4/S4


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7.8.2 ZADCO specification for structural application are summarized

below:

For sub sea application, ASTM A325 type 3 shall be used.

For above sea (normal structural) application, ASTM A325 type 1

galvanized shall be used.

For non-structural application, e.g. staircase, hinges, door, ASTM A 307

grade A galvanized shall be used.

For topside applications, the strength class shall not exceed ISO 898class 10.9

For submerged bolts, the strength class shall not exceed ISO 898class 8.8, ASTM A 320 Grade L7 or A 193 Grade B7.

Bolts with a diameter above 25 mm shall be impact tested to thesame requirements as for the steels to be bolted.

If other bolting materials are required due to corrosion resistance or other

reasons, the material shall be selected in accordance with the generalrequirements of this document. For subsea applications, Alloy 625 shall

be used when corrosion resistant bolts are required at ambienttemperature It shall be verified that the materials have acceptablemechanical properties at the actual design temperatures.

Bolts screwed into component bodies shall be of a material that iscompatible with the body with respect to galling and ability to disassemble

the component for maintenance, if relevant. Risk for galvanic corrosion,thermal coefficient if relevant, and for sub sea applications the effect ofCathodic protection, shall be considered.

Carbon steel and/or low alloy bolting material shall be hot dip galvanizedor have similar corrosion protection. For submerged applications, wherethere is a risk that dissolution of a thick zinc layer may cause loss of bolt

pretension, electrolytic galvanizing or phosphating shall be used.Electrolytic galvanizing shall be followed by post banking. For subsea

installations the use of poly tetra fluoro ethylene (PTFE) based coatingscan be used provided electrical continuity is verified by measurements.

Cadmium plating shall not be used.

7.9 Subsea production and flowline systems

Material selections for subsea production and flowline systems are given in table

7.4 for carbon steel flowline the requirements given in 7.13 apply.

Recommendation:

Metal to metal seals that may be exposed to seawater without cathodic protectionshould be made in corrosion resistant alloys such as UNS R30035, R30003, alloy

C-276. Generally, metal to metal sealing materials shall be more noble than

surrounding surfaces.


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All polymeric/elastomeric materials shall be qualified and the performance

documented in all relevant exposure conditions in accordance with 9.12 of thisdocument

For leveling systems and other systems mainly used for installation, carbon steelshall be considered.

All bolting materials shall comply with 7.8

Restrictions for maximum SMYS and actual yield strength shall apply for allcomponents exposed to ambient seawater with cathodic protections.


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Table 7.4-Material selection for subsea production and flowline systems

APPLICATION MATERIALS NOTES

Wellheads and X-mas trees

Wellhead equipment/X-mas trees for production 13 Cr4Ni, Low alloy steel with Alloy 625 overlay. Relevant API/ISO standards 1

Wellhead equipment/X-mas trees for deaeratedseawater

Low alloy steel with Alloy 625 weld overlay in sealing surfaces. Design mustallow for corrosion on not-overlayed parts. Relevant API/ISO standards.

1

Wellhead equipment/X-mass trees for aeratedseawater

Carbon steel with weld overlay

Wellhead equipment/X-mass trees for produced waterand aquifer water

As for production

Retrievable equipment internals 13 Cr or CRAs with higher PREN

Non-retrievable equipment internals, incl. X-masstrees

Alloy 718 or CRAs with higher PREN

Subsea Manifold Piping

Piping systems for well fluids 6Mo, 22 Cr duplex, 25 Cr duplex

Piping for deaerated seawater 6Mo, 25 Cr duplex, Carbon steel can be used for shorter design life, i.e. lessthan 15 years

Piping for gas Carbon steel, 22 Cr duplex, 6 Mo, See corrosivity parameters.

Piping for produced water and aquifer water 22 Cr duplex, 25Cr duplex, 6Mo. Carbon steel can be used for shorter designlife (i.e. less than 6-8 years) and if low corrosivity.

Piping for raw seawater TitaniumHydraulic fluids/glycol/methanol 316 2

Chemical injection and annulus bleed systems 316

Retrievable valve internals 13Cr, 17-4 PH, Alloy 718

Non-retrievable valve internals Alloy 718.

Subsea Rigid Flowlines

Oil and Gas Carbon steel, 13Cr 22Cr duplex or CRA clad carbon steel. Material selectionshall follow guidelines on corrosivity.

4,5,6


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APPLICATION MATERIALS NOTES

Deaerated seawater injection Carbon steel 4

Produced water and aquifer water injection Carbon steel, 22 Cr and 25Cr duplex, 6Mo. 5

Raw seawater injection Titanium, 6Mo, 25Cr duplex, internally plolyethylene lined carbon steel

Hydrate Inhibitor Lines Carbon steel, 316, 22 Cr duplex 7

Subsea Production Control systems

Umbilicals, metallic 25Cr duplex, encapsulated, Titanium 8,9,10Umbilicals, polymer hoses Polyamide 11, Thermoplastic elastomer (TPE), High strength carbon or high

strength polymer fibres11

NOTES

1. Sealing surfaces of components TYPE 13 Cr4Ni shall be overlay welded with Alloy 625.

2. Carbon steel and stainless steel with lower PRE than Type 316 can be used provided documented by field experience and/or tests,

3. Flexible pipe should be considered as alternative to rigid pipe. Carbon steel clad with CRA can be used as alternative to solid CRA, Guidanceon selection of CRAs for injection is given in table 7.1.

4. Carbon steel and weld metal can be alloyed with approx. 0.5% chromium for oil production and deaerated seawater injection flowlines toimprove corrosion resistance.

5. Type 25Cr and type 13Cr to be documented with respect to feasibility/weldability.

6. Cost effectiveness of using duplex stainless steels with a lower alloying content than for Type 22Cr should be considered.

7. Carbon steel can be used if acceptable from cleanliness point of view.

8. See Table 6.1 for limitation for titanium in methanol service.

9. Type 22Cr duplex can be used if Cathodic protection can be ensured. For 25 Cr duplex without Cathodic protection, external polymericsheathing is required.

10. Carbon steel with external protection (Cathodic protection in combination with coatings- organic or thermally sprayed aluminium) can be usedif acceptable from cleanliness requirements point of view.

11. Documented functionability in relevant fluids with extrapolation of service life is required. Not to be used for methanol service.


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7.10 Flexible flow lines and risers

Generally the requirements of API RP 17B and Det Norske Veritas Guidelines for

Flexible Pipes shall be satisfied. Due consideration shall be made to evaluatethe possibility of failure due to corrosion and/or corrosion-fatigue of the steel

reinforcement caused by the internal and/or the external environment. If sourconditions apply, the effect of H2S on steel reinforcement and inner liner shall be

considered. The gas diffusing through the polymeric sheets shall be consideredwet. If welding is performed on reinforcement wires, the resulting reduction instrength shall be taken into consideration in the design.

Measures to avoid internal galvanic corrosion by proper material selection and/orelectrical isolation shall be ensured at all interfaces to neighboring systems such

as at subsea production manifold piping and flowlines.

The material for the inner metallic layer of non bonded pipe can be stainless steeltype 316 provided pitting corrosion and local erosion penetrating the liner do not

deteriorate the functional performance and reliability of the flexible pipes. Thechoice of inner material shall take into account the possibility of being exposed to

seawater during installation and commissioning.

The following shall be documented, material properties verifying consistencybetween the design requirements and the fabricated quality.

Documentation demonstrating that polymeric materials will be resistant to theinternal and external environment and maintain adequate, mechanical and

physical properties throughout the design life of the system

7.11 Subsea production control systems

For polymeric based hoses, material selection shall be based upon a detailed

evaluation of all fluids to be handled. The annulus bleed system will be exposedto a mixture of fluids, such as production fluid, methanol, completion fluid and

pressure compensating fluid. A hose qualification programme shall be carried outincluding testing of candidate materials in stressed condition, representative foractual working pressure, unless relevant documentation exists. The results from

qualification testing shall provide basis for service life extrapolation according tomethods such as Arrhenius plots.

For umbilical, the electric cable insulation material shall also be qualified for allrelevant fluids. The material selected for the electrical termination should be ofsimilar type in order to ensure good bonding between different layers. The

material selection for metals and polymers in electrical cables in the outerprotection (distribution harness) and in connectors in distribution systems shall

have qualified compatibility with respect to dielectric fluid/pressure compensationfluid and seawater. The functionability in seawater of the individual barriersrelative to the service life shall be documented.

The different parts of the components in hydraulic and chemical distributionsystems shall have documented compatibility with relevant process fluids,

dielectric fluid and seawater.


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7.12 Drilling and workover risers

The required accumulated exposed design life shall be defined at an early stage.

Material selection shall take into account if the part will be welded or not. Thestrength shall be limited to enhance ductility and toughness. The specified

minimum yield strength shall be limited to max. 640 MPa for unwelded parts (max.ISO 11960 Grade C90) and 560 MPa for welded parts (max. ISO 11960 Grade

L80). All welded parts shall be post weld heat-treated.

Resistance to sour conditions shall be taken into account for parts of the drillingand workover risers, which may be exposed to reservoir fluids during drilling and

testing. Compliance with sour services requirements shall be met, unless lessstringent requirements are justified.

For drilling risers a total erosion/corrosion allowance of minimum 6 mm shall be

included for accumulated design lives exceeding 10 years. For floating drillingand production units, the use of titanium for drilling risers shall be evaluated.

For work over risers manufactured from C-steel, reduction in wall thickness due tocorrosion shall be evaluated. Effects of corrosion shall be accounted for by a

minimum of 1 mm unless it can be demonstrated through routine maintenancethat a corrosion allowance can be eliminated.

7.13 Pipeline systems

For pipeline systems for processed oil and gas and for injection water, carbon

steel according to API 5L, grade X65 or lower shall be used. ZADCOspecification cover API5L X-52, X-60, X-65 and X-70 (water injection).

The line pipe material shall be specified and tested to verify acceptable weldabilityunder field welding conditions accounting for welding during barge installation andcontingency hyperbaric repair welding situations during construction and

operations. The latter shall also address replacement of anodes, unless doublerplates are used.

Where sour service requirements apply, this requirement shall also be fulfilledunder hyperbaric welding conditions down to the maximum water depth along the

pipeline route.

Pipeline systems containing gas shall be designed for a minimum designtemperature that takes into account possible blow down situations.

For the reel laying method, it shall be documented that the base material andweld zones have acceptable properties after the total accumulated plastic strainthat can be experienced during reeling and installation.

Pipelines for unprocessed or partially processed oil and gas shall be selected on

the basis of corrosivity evaluation.


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7.14 Sour services

Satah plant is exposed to sour environment. After GBT (gas break through) thewest, south and central complex of UZ and Zirku plant may be exposed to varying

degrees of sour services. Consequently, the risk of SSC and HIC for carbon steelcannot be ignored. Both NACE MR0175 latest edition and EFC 16 give guidelinesfor SSC and HIC respectively.

7.15 Chains and mooring lines for floating units

In mooring line systems a corrosion rate of 0.4 mm/year for splash zone, and 0.1mm/year for fully submerged conditions respectively, shall be used as basis forcorrosion allowance and lifetime estimates. An evaluation of possible corrosion

due to bacterial activity on the seabed shall be carried out.

Wire rope segments shall have a protection system consisting of an outerjacketing (typically polyethylene or polyurethane), galvanized wires and a fillermaterial to prevent ingress of water. In addition, zinc sacrificial wires may be

incorporated.

DDEESSIIGGNNLLIIMMIITTAATTIIOONNSSFFOORRCCAANNDDIIDDAATTEEMMAATTEERRIIAALLSS

Design limitations for the application of different material types, e.g. maximum/minimumtemperature, maximum SMYS and actual strength, weldability, etc, are defined in the

following.

The following general requirements apply for all steel types (including bolts):

For carbon and low alloy steels, the yield to tensile strength ratio (actual values)shall not exceed 0.9.

For materials intended for welding, SMYS shall not exceed 560 MPa.

Note: If this requirements can not be met, higher SMYS may be accepted providedadequate documentation showing acceptable properties with respect to weldability

and the in service properties of the base material, heat affected zone and weldmetal on both sides is presented.

For submerged parts that may be exposed to cathodic protection, the following shall

apply:

For carbon and low alloy steels, SMYS shall not exceed 700 MPa (725MPa for

bolts). The actual yield strength shall not exceed 950 MPa. Alternatively, it may beverified that the actual hardness in base materials does not exceed 292 HB. Forcarbon steel welds a max. limit of 350 HV10, applies. For stainless steels and non-

ferrous materials, resistance against hydrogen embrittlement shall be controlled byspecifying that the actual harness of the material shall be in accordance with NACE

MR0175, unless otherwise documented.

In case where the minimum design temperature is a limiting factor for a material,also temperature exposures during intermediate stages (such as manufacturing,

storage, testing, commissioning, transport, installation) shall be considered whenspecifying the minimum design temperature and handling procedures.


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The impact toughness test requirements given to, and the application of, the

specified structural material are based on a minimum design temperature of -10C.If lower design temperatures are applicable, sufficient fracture toughness properties

have to be verified. For the most critical design class, this shall include CTODtesting of base material, weld metal and HAZ at the minimum design temperature.

8.1 Materials for pressure retaining purposes

8.1.1 General

Materials shall be used within the limits given in table 8.1.

Recommended limitations for CRAs in sour service beyond NACE

MR0175 are given in table 6.2. It is emphasised that H2S limits for CRA

material categories are difficult to state on a general basis. Specific limitsfor the material type and grade to be used should be establishedaccordingly by testing according to EFC Publication no. 16 for carbon andlow alloy steel and EFC Publication no.17 for CRAs. For requirements to

manufacturing, heat treatment and material properties, reference is madeto NACE MR0175.

8.1.2 Material Selection for pumps.

Various pumps are used in the hydrocarbon industry. These are firewaterpumps, seawater lift pumps, injection pumps, main oil pumps and

downhole pumps. The operating conditions of these pumps vary thus,standby, intermittent or continuous. These conditions often govern the

type of pump to be used and their material of construction. Fluidcorrosivity, abrasion resistance, life and efficiency eventually dictatematerial selection. Galvanic corrosion is very important, as it is not always

possible to make the whole pump of same material. The extent ofgalvanic corrosion depends on fluid corrosivity. In addition to the pump

components, the interaction of the pump with other materials in the systemsuch as pipes and flanges shall also be considered. For example, asubmersible seawater pump in super duplex stainless steel will cause

accelerated corrosion of the adjacent pipework if it is attached to a coppernickel column pipe. Finally, the pump shall have sufficient net positive

suction head (NPSH) to prevent damage (cavitation) due to evaporation.

8.1.3 Firewater pumps

Low cost option would be SS 316 impeller in an austenitic cast iron bodysuch as Ni-resist. While these pumps can work well in operation, therehave been failures of the cases by stress corrosion cracking, particularly inwarmer waters. Another option is nickel aluminum bronze (NAB) impellerin an NAB or gunmetal body. While NAB has good resistance to corrosion

in clean seawater, it is very prone to attack due to sulfides produced understagnant conditions. For high reliability /high safety application, superduplex stainless steel is commonly used and it has given high reliability in

service.


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8.1.4 Seawater Lift (Winning) Pump

The same comments that were made for material selection of firewaterpumps, generally apply to seawater lift pumps. Additionally, corrosion

problems have been seen with NAB due to excessive chlorine levels atpump inlet. As for firewater pumps, super duplex stainless steel has

proved to give the high reliability required. However, ZADCO has badexperiences with Zeron 100 pump shaft and sleeve. Crevice corrosion is aproblem for the non-hydraulic (section above sea level). This section is

subject to near stagnancy when the pump is not operational. Monel K-500is another candidate for pump shaft.

8.1.5 Injection pump

When deaerated seawater is pumped, 316 stainless steel is commonlyused with alloy 625 overlay in critical crevice areas e.g. O seals. With

the need for high discharge pressure the use of duplex or super duplexstainless steel offered reduction in wall thickness due to its higher

strength. In addition, it is common to re-inject produced water later in afields life and this often contains chloride levels greater than that ofseawater plus substantial H2S concentrations, super duplex stainless steel

has good resistance to both chlorides and H2S and injection pumpshandling both produced water seawater are common nowadays.

8.1.6 Main Oil Line Pumps

The oil usually contains some water that has not been separated and thishas high levels of chloride. The pumps are usually of carbon steel casing

and shaft and with 13/4 martensitic stainless steel impellers and diffusersbecause of their erosion resistance. The carbon steel is often weld

overlaid with 309 or 316 stainless steel in critical areas to minimise theeffect of corrosion. These alloys work because the corrosion is not muchat low water content. Where higher water content (separation) are

expected it may be necessary to upgrade the materials. 316 stainlesssteel is not usually used because the oil is pumped hot (e.g. 60-70C)

and chloride stress cranking (SCC) may occur and the alloy also haslower strength than martensitic alloys. In this case duplex stainless steelgives increased resistance to corrosion and pitting as well as chloride

SCC. If strength requirement is satisfied, SCC should not be a problem forSS316 because oil is unlikely to be oxygenated.

8.1.7 Downhole Pump

These pumps are installed downhole and shall resist the aggressive fluids

both inside and outside. Also the elastomers shall be resistant to corrosivefluids including drilling fluids and injected corrosion inhibitors. Frequentlysand drilling mud or other abrasive media are mixed with the process fluid.

Because of the need to resist both wear and corrosion in hot brines which


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often contains high chloride concentrations it is essential to use materials

resistant to both corrosion and erosion. Typically the pipes and casingwould be super duplex stainless steel with cobalt-chrome alloy (stellite

type impellers. Bearing and seals would be weld overlaid or solid cobalt-chrome as a minimum. In very erosive media it is common to usetungsten carbide or other ceramics. Further details in API 610, NACE RP

0475, pump engineer, 02, 2003.

8.1.8 Other Rotating equipment

Turbine, compressors, pumps, fans; gearboxes are designed on vendorpackages supplemented by ZADCO specification ZO-TS-M-05010 pumps

were discussed in the preceding section. Each rotating equipment is

operated as per the specific plant and operation manual and maintained inaccordance with the MAXIMO PM schedule and the associated job plan.

8.1.9 Valves

Valves are used for both hydrocarbon and produced water services.

Details are given in ZADCO piping specification Z0-TS-P-05010 andNACE RP047. Carbon steel valves used for hydrocarbon services shouldhave the same corrosion allowance as the associated piping. Usually,

Carbon steel valves are adequate for hydrocarbon service. In wet gasand oil systems, stainless steel or other corrosion resistant alloy seats and

gates/balls should be used. In some cases weld overlay may be requiredfor some critical areas, areas of the cavity subject to erosion due topossible high velocities, ie, on seat pockets and body/stem seal areas of

the body, extending at least 20mm on both sides of the grooves andaround corners. Therefore, the overlay requirement is not on the

complete valve body.

8.1.10 Instruments

ZADCO instruments such as thermowells, control valves, PSVs,

transmitters, shutdown valves are constructed of corrosion resistantalloys, material selection is dictated by fluid analysis, ZADCO instrumentsare at low risk of sulphide stress corrosion cracking after GBT becausethey are made of corrosion resistant alloys and comply to NACErequirements. Further details can be obtained from ZADCO specification

for instrument material selection (Z0 -TS-I-01050).

8.1.11 Life Saving

ZADCOs life saving equipment (e.g. life boat, raft, jacket and buoy) are

constructed of GRP. BU in cooperation with the vendor maintains suchequipment. HSEMS and operations documents address all life saving

equipment. Testing and maintenance is covered in MMS and IMS.


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Table 8.1 Metallic Materials for pressures retaining purposes

MaterialMin. designTem. (C)

ImpactTested

Other requirements Notes

Carbon and low alloysteel

1

API 5LGr.BASTM A33

Grade .63.5% Nickel steel

-29-46

-101

x

Martensitic Stainlesssteels

2,3

13Cr

13Cr valve trim parts

13Cr4Ni13Cr4Ni doubletempered

-10

-29

-46-100

x

Austenitic stainless

steels4

316

6Mo

-105-196

-105-196

x

Maxi. Operatingtemp.60C. Highertemperature acceptable

if full HVAC control.6 Mo seawater systems

with crevices:

Max. operating temp.15C, max. residual

chlorine 1.5 ppm.Without crevice: Max.

operating temp. 30Cand same chlorine level.

Duplex stainless steels 5

22Cr

25Cr

-46

-46

x

Maximum operatingtemperature 110C for22Cr and 120 C for 25

Cr if exposed to salineatmosphere.

Risk for cracking shouldbe assessed in systemsaffected by acidizing ifsulphide containingscales can be formed.Temperature limits for25Cr in seawatersystems as for 6Mo.

Nickel base alloys -196


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Table 8.1 Metallic Materials for pressures retaining purposes

Material

Min.

designTem. c

ImpactTested Other requirements Notes

Titamium base alloys 6Grade 2 -196 Seawater operating temperature

limits if crevices are present:Unchlorinated 95C, chlorinated85C, Brine 80C

Other grades 7

Copper base alloys Velocity limits for piping min 1.0m/s, max. cfr. BS MA 18. forintermittent service max. 10 m/s.

Not for stagnant conditions

8

90-10, 70-30, NiAlbronze, gun metal

Fresh seawater and normallydrained systems.

Admiralty brass, gunmetal, tin bronze

Fresh water normally drainedsystems

Aluminium base alloys -196 9

NOTES

1. Carbon steel API 5L Gr B be used in piping systems with minimum design temperaturedown to 15

0C for thickness less than 16 mm.

2. A corrosivity evaluation shall be carried out if temperature > 90C, or chlorideconcentration >5%.

3. Impact testing for well completion shall be carried out at 10C or the min. designtemperature if this is lower.

Use of 13Cr at temperature below 10C requires special evaluation.

4. Impact testing of austenitic stainless steel Type 316 and 6 Mo weldments has not beenconsidered necessary above 105C.

Type 6Mo stainless steel can be used in seawater systems with crevices above 15C ifcrevices are weld overlayed. No threaded connections acceptable in seawater systems.

5. Type 25Cr stainless steel can be used in seawater systems with crevice above 15C ifcrevices are weld overlayed. No threaded connections acceptable in seawater systems.

6. Shall not be used for hydrofluoric acid or pure methanol (>95%) or exposure to mercuryor mercury-based chemicals. Titanium shall not be used for submerged applicationsinvolving exposure to seawater with cathodic protection unless suitable performance inthis service is documented for the relevant operating temperature range.

7. Service restriction shall be documented for other Titanium grades.

8. Shall not be exposed to mercury or mercury based chemicals, ammonia and aminecompounds.

9. Shall not be exposed to mercury or mercury containing chemicals.


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Table 8.2 Proposed H2S limits for generic CRA classes

MaterialChloride

concentration,

max. %

Min. allowed

in-situ pH

Temperature,

max.C

Partial pressure

H2S, max. bar

Notes

Martensiticstainlesssteels

1,2

13Cr 55

33.5

9090

0.010.1

Austeniticstainlesssteels316 1

1

55

3.53.5

3.55

4060

6060

0.10.05

0.010.1

33

336Mo 5

53.55

150150

1.02.0

Duplexstainlesssteels

22Cr 31

3.53.5

150150

0.020.1

25Cr 55

3.54.5

150150

0.10.4

Nickel alloys 1

625 3.5 5 4

C276 >5 4

Titanium 3.5 >5 1

NOTES

1. If one of the listed parameters exceeds the given limit, it is recommended to test thematerial according to EFC Publication no. 17.

2. The temperature limit may be increase based upon evaluation of specific field data andprevious experience. Testing may be required.

3.The temperature can be increased to 120C provided completely oxygen free conditionscan be guaranteed.

4. No practical limits to temperature and chloride concentration for oilfield service.


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8.2 Gratings

Primary Structural Material: Carbon Steel

Secondary Structural Material: Carbon Steel

Tertiary Construction Material: Carbon Steel, Alloys, GRE and GRP

Gratings: Gratings for offshore structures that areinstalled from the first level above the

designated Splash Zone shall beconstructed of Cast Metal, which has beengalvanized to ISO 1461. They shall not be

painted.

Gratings: Gratings for offshore structures that areinstalled in the Splash Zone shall bemanufactured from non-metallic fibre re-enforced plastic materials that conform to

the required structural loading and fireendurance requirements of the installation.

They shall not be painted.

Gratings: Gratings for onshore structures shall beconstructed of Cast Metal, which has been

galvanized to ISO 1461. They shall not be

painted.

Stair Treads: Where stair treads are constructed fromcast metal grating materials the stair treadshall be galvanized to ISO 1461. They shall

not be painted.

Stair Treads: Where stair treads are manufactured fromflat or checker carbon steel plate they

shall be prepared and coated to Companyspecifications.

Stair Handrails and Handrail Posts: These items can be fabricated from carbonsteel or non-metallic fibre re-enforcedplastic materials that conform to the

required structural loading and fireendurance requirements of the installation.

Non-metallic materials are recommendedfor Splash Zones and shore based highcorrosion zones.


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Galvanizing shall be in accordance with the following standards:

ASTM A 123

ISO 1461

The minimum coating (Zinc) thickness shall be a function of the steel

thickness as follows: -

Steel Thickness mm Average Coating (Zinc) Thickness

To 1.5 mm 45 Microns

1.5 to 3 mm 55 Microns

3 mm to 6 mm 70 Microns

6 mm + 85 Microns


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FJE/COE/mhh 30/9

GGUUIIDDEELLIINNEESS OONN GGEENNEERRAALL PPRROOPPEERRTTIIEESS AANNDD PPRREECCAAUUTTIIOONNSS WWHHEENN UUSSIINNGGSSPPEECCIIFFIICCMMAATTEERRIIAALLSS

From the viewpoint of corrosion, the first material of choice for the designer is carbonsteel. If high rates of carbon steel corrosion are expected, CRAs or non-metallic should

be considered. However, CRAs may suffer from some types of localised corrosion orcranking mechanism under particular environmental conditions. Thus a corrosion

monitoring and inspection philosophy will generally be required regardless of materialsselection.

9.1 Carbon Steel

When carbon steel is selected for a part of the process stream or for other

systems it is susceptible to a variety of potential internal and external corrosion

risks. In many cases it should be acceptable to have corrosion occurring as longas the rate of attack is within manageable limits and there is some means ofchecking the type of corrosion damage and its extent. This is the essence of acorrosion management philosophy.

Care has to be taken when welding carbon steels to ensure that the weld andheat affected zone also have adequate strength and toughness for the

application. Welding procedures should be specified according to appropriatestandards and qualified to ensure that suitable mechanical properties will beobtained in the production welds.

For pipe system in corrosive service the weld should be compatible with the base

material in order to avoid local corrosion of weldment and heat-affected zone. Forsystems with sour service requirements the Ni content may be allowed up to 2.2%

9.2 Clad carbon steel

In corrosive hydrocarbon systems, cladding with corrosion resistant materials may

replace solid CRAs. The choice of cladding alloy will be dictated by the corrosivityof the environment, the selected cladding process and the availability. In practice

the number of cladding alloys used is fairly limited.

Fully clad components are widely applied (pipe, vesse

fi ts msg 001 material selection

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