AD156-447-G-01221_1

ABU DHABI MARINE OPERATING COMPANY (ADMA-OPCO}

EPC WORKS FOR

EZ16E: FACIIITIES FOR 4 NEW GAS INJECTORS AND3 BARREN TOWERS IN ZAKUM FIETD

EZ24E.ZADCO UZ 75OK WP.3A PROJECT

ADMA-OPCO CONTRACT NO:

167188MDR PROJECT NO:

D6221,

PROJECT

FACILITY

DISCIPLINE

DOCUMENTTYPE

DOCUMENT CTASS

WP3A

ZKGIP

MATERIALS AND CORROSION ENGINEERING

Report

t

ADMA DOCUMENT NUMBER : AD156-447-G-OL227

DOCUMENTTITLE Materials Selection and Corrosion Control Report - WP3A

PROJECT DOCUMENT ARE CONTROLTED DOCUMENTS

REV]SIONS ARE DENOTED A IN THE RIGH HAND MARGIN OF EACH PAGE

\ /^' '.1\v \$-"/I 27-O4-t4 ISSUED FOR REVIEW t{rr $[r NV UIJ "

REV. DATEPURPOSE / DESCRTPTION OF

REVISIONPREPARED BI REVIEWED 8Y QA/QC PEM

Page 1 of54

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EZ24E= ZADCO UZTSOKWP-3A PROJECT

affiCHANGE RECORD

REVISION NO.REVISION

DATEREVTSED SECilON(S) / PAGE(Sl REVISION DESCRIPTION

A 2t-o4-14 rDc

1 27-O4-t4 IFR

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EZ16E= FACILITIES FOR 4 NEW GAS INJECTORS AND3 BARREN TOWERS IN ZAKUM FIELD

EZ24E= ZADCO VZ750KWP-3A PROJECTffi

HOLDS REGISTER

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ABU DHABI MARINE OPERATING COMPANY (ADMA-OPCO)EPC WORKS FOR

EZ16E: FACILITIES FOR 4 NEW GAS INJECTORS AND3 BARREN TOWERS IN ZAKUM FIELD

EZ24E: ZADCO UZ750K WP-3A PROJECT

TABLE

1

2

3

4

5

6

6.1

6.2

6.3

6.4

7

7.1

7.2

7.3

7.4

7.5

I8.1

8.2

8.3

8.4

8.5

8.6

8.7

8.8

TABLE OF CONTENTS

OF CONTENTS

INTRODUCTION

PURPOSE

EXECUTIVE SUMMARY

SCOPE

TERMINOLOGY / DEFINITIONS / ABBREVATIONS

REFERENCED DOCUMENTS

Order of Precedence

Company Standards and Guidelines

lnternational Codes and Standards

Project Documents

DESIGN CRITERIA

Design Life

Corrosion conditions

Software

Environ mental Conditions

Fluid Profiles and Compositions

CORROSION RISK ASSESSMENTS

General

lnternal Corrosion Prediction

Comparative Effects of COz and HzS

COz Corrosion

HzS Corrosion and Cracking

Under Deposit Corrosion

Condensing Gas Phase Corrosion

Corrosion of CRA Materials

8.8.1 Crevice and Pitting Corrosion

8.8.2 Resistance to CISCC

Oxygen Corrosion

AD156-447-G-OLZ2L

MATERIAL SELECTION AND CORROSION CONTROL:1

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Document TitleRevision

REPORT - WP3APage 4 of 54

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EZ24E: ZADCO UzTSOKWP-3A PROJECT

8.10

8.11

8.12

8.13

8.14

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10

10.1

10.2

10.3

10.4

10.5

10.6

10.7

10.8

10.9

11

11.1

11.2

11.3

11.4

11.5

11.6

12

External Corrosion

Other Corrosion Considerations

Sour Service Considerations for Non-Metallic Materials

Liquid Metal Embrittlement - Zinc

Low Temperature Considerations

MATERIALS SELECTION CRITERIA

CANDIDATE MATERIALS

Carbon Steel

Ferritic Nickel Steels

Austen itic Stainless Steels

Super Austenitic Stainless Steels

Duplex Stainless Steels

Nickel Based Alloys

CRA Lining / Cladding and Internal coating

Bolting Materials

GRE/FRP

MATERIALS SELECTION

Carbon Steel with Corrosion Allowance

Corrosion Rate Predictions

11.2.1 Injection Gas

Pig Launcher / Receiver

Corrosion Inhibitor Injection Pump

Material Selection Summary Table

Hydrotest

CORROSION INHIBITOR PHILOSOPHY

12.1.1 General

12.1.2 Inhibitor Effectiveness and Availability

12.1.3 Operation and Reliability

12.1.4 Chemical Performance

12.1.5 Delivery System Design

12.1.6 Injection Locations and Equipment

12.1.7 Inhibitor Type and Indicative Injection Rates

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14

12.2 External Corrosion

13 CORROSION MANAGEMENT AND PHILOSOPHY

13.1 Corrosion Management Philosophy and Monitoring

13.2 Corrosion Monitoring Techniques and Equipment

13.2.1 Access Fittings for Corrosion Monitoring Equipment

13.2.2 Hydrogen Probes

13.2.3 Wall Thickness Monitoring

13.2.4 Field Signature Methods

13.2.5 Summary of Corrosion Monitoring Options

INSPECTION AND MAI NTENANCE

14.1 Selection of inspection grades for equipment and piping

14.1.1 Inspection Grade 0


14.1.3 lnspection Grade 2


14.2 Data Collection and Inspection Frequency

14.3 Key Performance Indicators (kpi)

14.4 Data Assessment and Corrosion Reporting

14.5 Maintenance Philosophy

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ADL56-447-G-OL2ZLMATERIAL SELECTION AND CORROSION CONTROL REPORT - WP3A1 Page 6 of54

ABU DHAB| MARTNE OPERAT|NG COMpANy (ADIJ|A-OPCO)EPC WORKS FOR


EZ24E= ZADCO UZ750KWP-3A PROJECTffi

INTRODUCTION

ADMA OPCO intends to achieve additional 100 MBPD Oil productions from Lower Zakumfield (50 MBPD each to be produced from Zakum Th-lV & Th-V). To achieve this production,40 new infill wells are required of which 32 would be oil producers, 4 gas injector wells and 4water injector wells. ADMA has awarded, under a single contract, an EPCI scope of workcomprising of the following three project packages.

o Facilities for 4 New Gas Injectors in Zakum Field (4Gl)

The design will source 120 - 2OO MMSCFD of Injection gas from the existing ZK-GIP Train-3compressor discharge header located at ZK-GIP. The injection gas will flow through a 15 kmlong 12" sub-sea pipeline to the ZK-300 platform via ZK-182 platform designed with throughpigging capability launching from ZK-GIP to a receiver located at ZK-300. At ZK-300, the gasreceived will be injected into the two new gas injector wells drilled from ZK-300 (30 - 80MMSCFD each well). The gas received at ZK-182 will be injected to the two new gasinjectors drilled from this tower (20 - 80 MMSCFD each well).

In addition to the above, the 4Gl scope also includes provision of new equipment and pipingto be installed on ZK-300 associated with the replacement of an oil transmission subseapipeline (by others), which includes process piping, pig launcher and Cl package.

o Modifications on GIP (WP3A)

As a part ol UZ750K project of ZADCO, a new gas injection pipeline from ADMA-OPCO ZK-GIP to ZADCO Central lsland is required to export HP treated gas from ZK-GIP which shallbe selectively used for gas injection and gas lift in ZADCO artificial islands. Modifications arerequired at existing ADMA-OPCO GIP platform which includes installation of top sidefacilities related to new gas injection pipeline (by others) and hook up to existing systems atGIP.

o Facilities for 32 New Oil Producers in Zakum Field (3 Barren Towers)

Out of the 32 New Oil Producers, 10 wells will be drilled from the 3 existing Wellhead Towers2K114.5174.5, 2K153/61 and Z,K158176. These 3 towers are currently barren and nonoperational. The purpose of this project package is to modify through design; procurement;fabrication and installation; all existing facilities to receive the produced Oil.

2 PURPOSE

The report provides materials selection and corrosion control philosophies as updated andfinalised during detailed design for WP3A GIP Modifications Project.

Under the Contract, CONTRACTOR is required to update the FEED materials and corrosionreports by preparing a Project Specific Material Selection & Corrosion Control Report.However, no FEED document covering WP3A scope is available and the basis and

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EZ24E: ZADCO UZ750KWP-3A PROJECT

nnwphilosophies presented in this report have been drawn from FEED documents issued for 4GlProject

3 EXECUTIVE SUMMARY

The objective of this study is to define materials selection basis and corrosion controlphilosophies for WP3A project whose scope includes new topsides piping, pig launcher and

corrosion inhibition pump associated with a new 10" gas injection subsea pipeline (by

others), which transports dehydrated gas from ZKGIP to Central lsland.

The following documents form the basis of this study:

. Guidelines for Material Selection. GDL-O12

r Specification for Materials for Sour Service, SP-1000;

. Maintenance Strategy, STR-001;

. Corrosion Management Strategy, STR-002;

. Code of Practice for lnspection and Testing of Plant In-Service, CP-107 Part 1.

Material selection is complimented by corrosion monitoring to ensure that the design life will

not be adversely compromised during service and to ensure the safe and economic operatinglife of a facility. The monitoring may also be used to:

. Verify that the operating parameters are within the design envelope for the topsidefacilities.

. Optimize inspection intervals as part of a risk-based inspection (RBl) programme and

to detect changes in corrosivity that will invalidate inspection periods or endanger theproject facilities.

The primary philosophy is that corrosion monitoring has been specified when:

o Loss of corrosion inhibition availability and process upsets lead to rapid metal loss.

. Changes in the operating environment can lead to significant increase in thecorrosivity of the environment towards carbon steel, either with or without corrosioninhibitors.

. The outcome of corrosion monitoring can lead to timely re-assessment and

adjustment of the system of corrosion management and optimization of inhibitordosing.

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EZ24E= ZADCO UZ750KWP-3A PROJECT

The functional requirement of the corrosion monitoring system is that it should be able todetect and quantify trends in the corrosivity of the fluids and shall do so within a time frame

short enough to enable ADMA-OPCO to initiate or adjust corrosion mitigation measures

before significant metal loss has occurred. The report also covers the following aspects:

. ZKGIP piping and equipment design criteria and process data;

. Corrosion assessment for CO2 and other mechanisms such as HzS stress corrosion

cracking along with corrosion allowances, corrosion monitoring, maintenance and

inspection;

. Low temperature effects as a result of blowdown / depressurisation.

Corrosion predictions have been generated using the Electronic Corrosion Engineer version

5 (ECE-S) software package whose results are summarized in Appendix 1. When corrosion

inhibitor injection is considered in the ECE-5 model, Cl availability and efficiency values 95%

have been assumed.

Injection gas fluids handled by topside piping and equipment are potentially corrosive

due to the combination of COz and HzS content. Despite minimal amounts of water,

the injection gas behaves as a supercritical fluid in the operating envelope presented.

An essentially dry gas has been examined in this study within the respective flow

rates and adequate corrosion allowance specified in the SELECT phase validated

after establishing the requisite design data and performing corrosion assessments forthe process design parameters of the respective topside piping sizes involved.

Due the corrosive nature of the fluids in the presence of HzS, intermittent inhibitor

injection during upsets (injection gas) is recommended to prevent excessive HzS

pitting, along with NACE MR0175/1SO15156 requirements.

The performance of inhibitors (i.e. the proportion by which they reduce the natural

corrosion rate) must be proven prior to deployment. This is initially achieved via

laboratory tests. Operational tests must follow deployment (using corrosion monitoring

facilities in the process) to prove that the laboratory results are being achieved in thefield. lt should be noted that extensive screening and testing has been carried out by

ADMA-OPCO for oil and gas production inhibitors with selection ultimately based on

this. Technical definition and qualification of corrosion inhibitor and associated

injection rates is the responsibility of ADMA-OPCO under the Contract.

Finally, the performance of the chemical must be periodically reviewed by field

testing. lt is assumed that final chemical selection will be performed by ADMA-

OPCO's chosen chemicals vendor to ensure that the inhibitor availability should be at

least 95% over the design life with dosage for dry gas lines maintained at 0.25

L/MMSCFD.

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ABU DHABI MARTNE OPERATING COMPANY (ADMA-OPCO)EPC WORKS FOR


EZ24E: ZADCO UZ75OK WP-3A PROJECT#*ffift

Topsides CRA piping sections do not require any internal corrosion monitoring except forexternal coating checks for solid SS316L piping which would be subjected to CISCC due tothe environmental conditions (>60"C) envisaged for the project. Primary mechanism forcorrosion control for topsides carbon steel piping and equipment will be via corrosioninhibitors (during upsets only) and external painting, along with hydrogen probes and regularultrasonic testing (via online UT-Mats) on remaining thickness of the associated piping when

it comes to corrosion monitoring. The use of ER probes and WLC have been specified formonitoring the pipeline (pipeline not in scope).

ADMA-OPCO Technical Standard CP-107 shall from the basis for inspection and

maintenance of topsides equipment and piping. This subject is addressed in documentAD156-447-G-01255.

SCOPE

The objective of this study is to define the philosophy for internal and external corrosionmitigation of the modified GIP topside facilities within WP3A scope.

A corrosion assessment of topside piping and equipment has been carried out, primarily

assessing internal corrosion by COz in the presence of H2S, based on profile cases provided

by COMPANY, refer Appendix 1. Suitable materials for piping and associated mechanicalequipment along with corrosion management, monitoring, maintenance and inspectionmethods are also discussed accordingly.

Document No


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Table 1 - Summarv of Tooside Material Selected

$ystemsAnalysed ilocSelected Remarks

Topsides ProcessPiping

CS+3mm(NACE)

Injection gas is essentially dry with minimal internal corrosion expected. HzS pitting

corrosion worries may necessitate Cl injection provision at ZKGIP to cater for process

upsets. Dew point monitoring to be part of design.

ER probes, Corrosion coupons, regular UT checks and hydrogen probe monitoring forCS (NACE) piping in order to meet KPI specified in Table 4. External Painting, in

accordance with Painting Manual - MNL-01, should be applied and should be checked

as part of KPl.

Pig Launcher /Receiver

CS+3mm CA(NACE)

Recommended to remove process fluid after each use and inert under nitrogen.

Cl Pump SS316LPiping between pump and injection point is Alloy 625, in accordance with COMPANYreouirement

ABU DHABI MARINE OPERATING COMPANY (ADMA-OPCO)EPC WORKS FOR


EZ2AEI. ZADCO UZTSOKWP-3A PROJECT

5 TERMTNOLOGY / DEFINITIONS / ABBREVATIONS

:

ADMA or ADMA OPCO Abu DhabiMarine Operatinq CompanyAPI American Petroleum I nstituteBcn Bulk Corrosion RateBrcn Bulk lnhibited Corrosion RateBOL Bottom-of-LineCA Corrosion Allowancecl Corrosion InhibitorCMP Corrosion Monitoring PointCOMPANY Abu Dhabi Marine Operatino Companv (ADMA-OPCO)

CP Cathodic ProtectionCRA Corrosion Resistant AllovCS Carbon Steelcscc Chloride Stress Corrosion CrackingDBB Double Block & Bleed

EPC CONTMCTORMcDermott Middle East Inc., - Appointed by the COMPANY to carry

out Engineering, Procurement, Fabrication and lnstallation of the

project.

FEED Front End Engineering Design

GG II Gas Gatherinq PlatformGIP Gas Iniection Platform (ZWSC)

GPF Gas Processinq FacilitiesHP Hiqh PressureLcn Local Corrosion RateMOC Materials of ConstructionNACE National Association of Corrosion Enqineers

PROJECTEngineering, construction, installation and commissioning worksrelating to 4 new gas injectors and topsides oil replacement workson ZKGIP, ZK-182 and ZK-300 platforms

Tcp Top-of-Line Corrosion RateUZ Upper ZakumWHT Well Head TowerZCSC Zakum Central Super ComplexZK Zakum

6 REFERENGED DOCUMENTS

6.1 ORDER OF PRECEDENCE

1. Statutory Legislation and Regulation inclusive of ADNOC standards and codes of practice

2. EPC Scope of Work

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ABU DHABI MARTNE OPERATING COMPANY (ADMA-OPCO)EPC WORKS FOR


EZ24E: ZADCO UZ 7 sOR WP-3A PROJECT

L-€J$'IDFfi

6.3

3. FEED and REFEED documents (data sheets, job specifications, design basis, project philosophies,drawings, etc)

4. ADMA-OPCO Standard Engineering and HSE Documents

5. BP Recommended Practices & Specifications for Engineering

6. International Codes and Standards

6.2 COMPANY STANDARDS AND GUIDELINES

DOCUMENT TITLEGDL-012 ADMA OPCO Guideline for Matertal SelectionMNL-01 ADMA OPCO Paintinq ManualsP-1000 ADMA OPCO Specification for Materialfor Sour ServicesSTR-OO2 ADMA OPCO Corrosion Manaqement Manual

BP GP 36-10 Guidance of Practice of Metallic Material Selection

INTERNATIONAL CODES AND STANDARDS

PROJECT DOCUMENTS

DOCUMENT TITLEAD156-447-G-01224 Process Desiqn BasisAD156-447-D-12001 PFD - ZKGIP WP3AAD156-447-D-12002 MSD - ZKGIP WP3AAD156-447-D-12026 Heat and Material Balance - WP3AAD156-447-G-01255 Corrosion Control Manual- WP3A

DESIGN CRITERIA

This report is based on the following documents and the design parameters given therein:

o Process Design Basis

. Heat and Mass Balance

DESIGN LIFE

MOC selected shall be such that they minimize the life cycle cost while maintaining the

appropriate level of integrity required.

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6.4

7.1

DOCUMENT TITLE

NACE MR0175/tSO15156Materials for Use in HzS Containing Environments in Oil and GasProduction

NORSOK M-OO1 Materials Selection

ABU DHABI MARTNE OPERATTNG COMPANY (ADMA-OPCO)EPC WORKS FOR

EZ'|6E= FACILITIES FOR 4 NEW GAS INJECTORS AND3 BARREN TOWERS IN ZAKUM FIELD


For the carbon steel piping and equipment, a minimum service life of 30 years has beenconsidered. Increased design life may be required for individual items as provided in ITT JobSpecifications, refer Section 11.

coRRosroN coNDriloNs

. The topside piping and equipment shall be designed for COz corrosion with H2S

presence, making the gas sour when wet.

o For fluid composition and process conditions, data given in process design basis andH & MB tables will be used.

Injection of corrosion inhibitor, if necessary, will be considered to be able to achievean availability factor of 95o/o using the "Availability Model" as simulated in ECE-S.

The injection gas is essentially dry or with small presence of free liquid water,however, in the event of upstream upset conditions, wet gas could enter the pipelinecausing corrosion in the associated topside receiving facilities. Under thesecircumstances, the topside piping and equipment corrosion assessment philosophywill be conservatively based on normal operating and upset conditions with free waterpresent in the topsides piping and equipment based on the water flows provided in

Appendix 1.

7.3 SOFTWARE

Commercial software 'Electronic Corrosion Engineer'version 5.1.1 (ECE-S) has been used topredict carbon steel corrosion rates for process systems handling well fluids. Acid gases,

when present in the process stream in co-existence with free water, forms acidic liquid which

can be highly corrosive to carbon steel, according to partial pressure, temperature, flow rate,water cut and other variables.

ECE-S is based on historic semi-empirical DeWaard Milliams equations developed in the1970s which have been improved and modified with best fit analysis to a large number offlow loop data carried out under controlled conditions. ECE-S recognizes two reactions, onecontrolled by electrochemical processes at the liquid/metal interface and the other controlledby the mass transport rate of corrosive species to the liquid/metal interface.

Corrosion modeling of well fluids is not an exact science and different industry models give

different predictions. The correlation of the output to actual conditions is heavily dependentupon the accuracy and validity of the input data. As such, the ECE-S corrosion software isnot a standalone expert system but a tool intended to support expert analysis by thecorrosion engineer taking into account all information available, including operational historyand maintenance records of similar existing facilities which may be provided by the Operator.

7.2

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ABU DHABT MARTNE OPERAT|NG COMPANY (ADMA-OPCO)EPC WORKS FOR


EZ24E= ZADCO UZ7$OK WP-3A PROJECTffi

7.4 ENVIRONMENTAL CONDITIONS

The environmentaltemperatures used in the simulation are given below:-

Ambient air temperature

Ambient seawater temperature (atseabed):

Am bient seawater tem perature:

Mean average summer temperature:

Mean average winter temperature:

Maximum temp. of metal exposed to sun:

Min:9"C (48.2"F)

Min: 17'C (62.6'F)

Min: 16'C (60.8'F)

34'C (93.2"F)

20"c (68'F)

85'C (185'F)

Max:45'C (113'F)

Max: 36'C (96.8'F)

Max:36'C (96.8"F)

7.5 FLUID PROFILES AND COMPOSITIONS

Fluid profiles and compositions used to generate corrosion rate data are provided inAppendices 1.

CORROSION RISK ASSESSMENTS

GENERAL

Topsides piping and equipment may be subjected to long or short term corrosive attack byeither the line product and/or external corrosive media. External corrosion protection isinvariably achieved by the application of an external painting system for carbon steels andonly necessary for CRAs when operating/environmental temperatures leave them susceptibleto chloride induced stress corrosion cracking (CISCC).

Various methods are available to mitigate internal corrosion, depending on the type andseverity of anticipated corrosion.

8.2 INTERNAL CORROSION PREDICTION

Internal corrosion may take many forms depending on the fluid composition and processoperating conditions. For CS piping and equipment handling process fluids, the most likelyform of attack is by acidic gases such as COz or H2S in the presence of free water.Significant levels of wet HzS which place process piping and equipment operating conditionsin the sour service region can require precautions against sulphide stress corrosion cracking(SSCC) and hydrogen induced cracking (HlC). Such requirements will generally necessitatespecific controls over pipe/plate chemical composition and heat treatment condition andmaximum allowable hardness of base material and weldments.

Corrosion inhibitor availability of g5% has been considered for lines when/where Cl ispresent. This is a high value of availability and will require a high standard of inhibitor supplyand corrosion monitoring to adjust the flow of inhibitor in the upstream pipeline whenapplicable.

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8.1

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Where corrosion rates require a corrosion allowance in excess of 6mm over the design life,corrosion resistant alloys shall be considered. The recommended materials of constructionwhen specified, is catered to take into account corrosion occurring from both surfaces,external atmospheric (via suitable coatings) and internal process fluids (via corrosionallowance).

To provide an economic solution, vessels made from carbon steel can be metallurgicallycladed with CRA or internally coated with inorganic coatings supplemented by cathodicprotection and internal corrosion allowance, as appropriate.

Note that H2S induced cracking of carbon steel piping and/or weldments can take place overa relatively short time at areas where the hardness exceeds the maximum allowed per NACEMR 0175 i.e. Rockwell C22. Considering the presence of HzS in the gas (minimum of0.1mol% or 1000ppm), coupled with high operating pressure resulting in high partial pressureof HzS in the process streams, NACE MR0175 requirements shall apply accordingly.Therefore, despite the gas injection process streams handling an essentially dry gas, in orderto avoid worst case process scenario during process upset conditions, the selected MOCshall comply with NACE MR0175/lSO 15156 requirements.

8.3 COMPARATTVE EFFECTS OF CO2 AND H2S

The effect of such corrosive gases depends, as discussed above, on the partial pressures ofthe gases and their respective dissociation constants. The effect of the HzS on the overallcorrosion rate is significant and it is not masked by the presence of COz.

Selection of materials to combat corrosion relies mainly on the type of corrosion anticipated(e.9. whether general or localised [pitting]), the confidence in predicting the rate and type ofcorrosion, risk of failure and life cycle cost.

lgnoring the environmental sensitive cracking aspects of corrosion problems associated withsour service, low levels of hydrogen sulphide can affect CO2 corrosion in different ways. H2S

can either increase COz corrosion by acting as a promoter of anodic dissolution throughsulphide adsorption and affecting the pH or decrease sweet corrosion through the formationof a protective sulphide scale. The exact interaction of H2S on the anodic dissolutionreactions in the presence of COz is not fully understood.

For similar conditions, oil and gas installations could experience lower corrosion rates in sourconditions compared to completely sweet systems. This is due to the fact that the acidcreated by the dissolution of hydrogen sulphide is about 3 times weaker than that of carbonicacids, but HzS gas is about 3 times more soluble in hydrocarbon phase than COz gas. As aresult, the effect of both CO2 and H2S gases on lowering the solution pH and potentiallyincreasing corrosion rate are fundamentally the same. ln addition, hydrogen sulphide mayplay a significant role on the type and properties of the corrosion films, improving orundermining them.

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Literature data on the interaction of H2S and CO2 is still limited since the nature of theinteraction is highly complex. The majority of open literature indicates that COz corrosion rateis reduced in the presence of HzS at ambient temperatures. Nevertheless, it must beemphasized that H2S may also form a non-protective layer and that it may catalyse theanodic dissolution of bare steel.

Steels may experience some form of rapid, localised corrosion in the presence of H2S,

although very little information is available. Published laboratory work has provedinconclusive, indicating that there is a need to carry out further studies in order to clarify themechanism. ln spite of the work on H2S corrosion of steels, no equations or models areavailable to accurately and reliably predict its effect on corrosion, as is the case for CO2corrosion of steels.

As a general rule in COz containing environments the presence of H2S can:

lncrease the corrosion risk by either:

o facilitating localized corrosion, at a rate greater than the generalmetal loss or localized rate expected from CO2 corrosion, or

o preferentially forming an FeS corrosion product that is lessprotective than an iron carbonate corrosion product

Decrease the corrosion risk by promoting the formation of an FeScorrosion product film through either

o replacing a less protective iron carbonate film, or

o forming a combined protective layer of iron sulphide and ironcarbonate

In the presence of both acidic gases, the corrosion process is governed by the dominantacidic gas. The presence of HzS in COz containing producing environments has led to theintroduction of COzlH2S ratio which considers three different corrosion domains based on thedominance of corrosion mechanism as affected by the dominating acid gas.

1. CO2/H2S < 20

o Corrosion dominated by HzS

o FeS as the main corrosion product.

2. 20 < CO2|H2S < 500

o Mixed CO2/H2S corrosion dominance

o A mixture of FeS and FeCO3 as the main corrosion products.Document No : AD156-447-G-OI22IDocument Title : MATERIAL SELECTION AND CORROSION CONTROL REPORT - WP3ARevision : 1 page 16 of 54

ABU DHAB| MARTNE OPERAT|NG COMPANY (ADMA-OPCO)EPC WORKS FOR



3. CO2|H2S > 5oo

o COz corrosion dominates

o FeCOs as the main corrosion product.

Iniection Gas

In reference to Appendix 1, the COzlH2S upper and lower cases for injection gas are:-

Highest CQzlHzS. 29.7

Lowest CO2/H2S: 15.2

Where the ratio is less than 20, corrosion will be H2S dominated and protective iron sulphidefilms will be present and the general corrosion rates are therefore driven by the partialpressure of the HzS and for all practical purposes, the COz effect is considered minimal interms of general corrosion rates since the formation of FeS would reduce CO2 corrosionsignificantly. The FeS scale, although quite tenacious, is relatively brittle and can spall of athigh fluid velocity. The steel areas exposed after spalling will then become anodic to theresidual FeS scale and pitting attacks may occur at these bare areas. Accumulation of thescale can accelerate corrosion if water is present.

Where the COz/HzS ratio slightly exceeds 20, corrosion regime can be dominated by eitherH2S and CO2, r€sulting in mixed corrosion pattern in which the highest localised corrosionrate is not expected to exceed predicted CO2 corrosion rate.

8.4 CO2 CORROSTON

CO2 corrosion is normally of a more generalised nature taking place over an extended periodof time it is time dependent and may occur in high velocity or turbulent areas where water ispresent.

The gas composition, as observed from Appendix 1, contains levels of COz ranging from 2.39mole% to 3.04 mole% for the injection gas under the various cases to be analysed. Thesystem is assumed to be oxygen free (< Sppb oxygen).

ECE-S corrosion rate data presented in Appendices 1 take into account COz presence in thefluids for each stream modeled.

The principal variables that impact the COz corrosion rate are:

. coAggJ_Hkjlplgf'9* g"oltg_f1:_ilcrease the partial pressure of Co2, which resultsin q9.fe-carbAqlc.gcid,in the,gqyggus phase and reduces the pH, thereby increasingthe corrosion rate.

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o Temperature - Higher temperatures increase reaction kinetics up to the point where aprotective scale is formed.

e Pressure - lf free gas is present, higher pressures increase the partial pressure ofCO2, which reduces the pH of the aqueous phase and thereby increases the corrosionrate. lf there is no free gas present, no more CO2 can go into solution as the pressureis increased and therefore pumping a liquid to higher pressure has no effect on thecorrosivity of the fluid.

MEG / TEG content - The presence of glycol affects the solubility of iron corrosionproducts in the water phase and can have a significant inhibiting effect on thecorrosion rate depending on the weight percent of glycol.

Water composition - Produced formation water containing bicarbonate (HCO -; fonscan buffer the pH and make the produced water phase less corrosive.

Organic acids - The presence of organic acids such as acetate can result in corrosionrates higher than those predicted by traditional COz models.

Flow regime - The flow regime can affect the distribution of the aqueous phase (andcorrosion inhibitor), the time of water wetting over which corrosion occurs and thehydrodynamic shear stress at the pipe wall. Flow velocity affects mass transfer ofcorrosive species to the pipe wall and corrosion products from the pipe wall, and cantherefore result in flow-enhanced corrosion or film stripping of corrosion products andcorrosion inhibitor.

8.5 H2S CORROSTON AND CRACKTNG

The HzS present in the gas usually helps in reducing the corrosion by formation of ironsulphide film. However, if the film is not perfect and gets damaged, a corrosion cell is formedbetween the sulphide film and bare metal resulting in severe corrosion in the form of pitting.Scale debris can be carried along the process streams and will deposit in pockets of valvesand areas of lower flow velocities. As such, accumulation of the scale would ultimatelyaccelerate corrosion if water is present during process upsets. The debris would alsodecrease Cl efficiency because it represents a very large surface area onto which the Cladsorbs.

The other main problem with the presence of HzS in the gas is the formation of atomichydrogen due to corrosion reaction causing hydrogen embrittlement that can lead to crackingof ferritic carbon steel materials. Apart from this problem, there are two other problems whichcan cause cracking of ferritic materials which are; Sulphide Stress Corrosion Cracking(SSCC) and Hydrogen Induced Cracking (HlC) due to hydrogen uptake and embrittlement.

In general for carbon steels, H2S corrosion will not be a problem for essentially dry gassystems. However, cracking in the form of SSCC and hydrogen embrittlement will be a

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problem if the hardness of the material is high, especially the weld areas with wet gaspresent. The environment conditions under which HIC and SSCC can occur have beendefined in NACE MR0175/1SO15156.

The NACE-ISO standard MR0175/1SO15156 provides guidelines for the usage of variousmaterials under conditions that can be described as "sour". Sour service is defined usingMR0175 option 1:

. HzS partial pressure (pHzS) < 0.3 kPa_a (0.05 psia), no special precautions arerequired.

. H2S partial pressure (pH2S) > 0.3 kPa_a (0.05 psia), SSCC / HIC resistant materialsare required.

Considering minimum 1000ppm HzS is expected, service is considered as "severe sour" forservice pressures above 1461.4 psia with pH ranging between 3.5 and 4.5 as shown inFigure 1. Since pressures are not expected to be lower than 5000psig, carbon and low alloysteel shall follow NACE MR0175 / 1SO15156 Appendix 2 requirements including limitationson hardness, heat treatment and chemical compositions.

Fioure 1: Sour Service Limits

It should be noted that material compliance with NACE MRO17S / ISO 15156 does notnecessarily provide protection against HlC. This sensitivity is related to carbon steel and rowalloy steel containing non-metallic sulphide inclusions. The cracking damage in these steelsis very often time dependant and is re-produced by controlled rolling related to the flux ofatomic hydrogen generated by the corrosion reactions at the metallic surfaces. Combining ofatomic hydrogen into hydrogen gas is a cumulative process and builds up hydrogen gaspressure which eventually leads to HlC.

SSCC can be avoided by ensuring the equipment and piping components are fabricated frommaterials conforming to NACE MR0175/lSO 15156. Conformance would require appropriate

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Ii r-5

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EZ24E= ZADCO UZ750K WP-3A PROJECT

heat treatment of the steel to lower the material yield strength to less than 620MPa and thehardness to below RC22. The microstructures produced by quenching and tempering ofsteels have also been found to increase resistance to general corrosion as well as resistanceto SSCC.

The susceptibility of carbon steel to HIC can be mitigated by controlling chemicalcomposition, in particular reducing the concentration of MnS inclusions in steel. A reductionin inclusions is usually achieved by lowering the sulphur content of the steel to below0.003%.

Addition of trace elements, such as calcium, to the steel to give residual CalS ratio in therange 2-4 provides shape control of MnS inclusions. Shape control reduces the propensity toHIC because calcium reacts with the MnS to form an inter-metallic sulphide that is notdeformed during the forming of vessels. Therefore the spherical shape of the inclusions isretained and they are not rolled into platelets where atomic hydrogen can accumulateforming hydrogen gas leading to cracking problems.

Since this problem is mainly related to the rolling process, HIC testing of forged materials is

essentially not required. However, ADMA-OPCO Technical Standard STD-108 may requireHIC testing (subject to Company relaxation by bidder clarification) in accordance with NACETMO284 ensuring that Crack Length Ratio (CLR), Crack Thickness Ratio (CTR) and CrackSensitivity Ratio (CSR) requirements are less than 1Oo/o,3o/o and 3% respectively.

For seamless piping in process plants or topside facilities, HIC testing is usually waived if thematerial is very low sulphur and it has been calcium treated for inclusion shaping. HIC testingthough is particularly of importance for carbon steel pressure vessels when used for sourservice ensuring hardness is kept below 248HV10. Seamless carbon steel piping shall beHIC resistant with similar hardness requirements in place.

When not otherwise qualified by laboratory tests and field experience, corrosion resistantalloys shall follow the requirements and environment limitations given in NACE MR0175 /1SO15156-3:2009. NACE provides environmental limitations for CRA materials. A typicallimitation applicable to NACE compliant austenitic stainless steel for general equipment is:

. 60oC maximum temperature, 1 barg maximum H2S partial pressure, no specificlimitation on chloride content and pH.

The compliant austenitic stainless steel shall meet the heat treatment cold work andhardness requirement of NACE MR01 75llSO1 51 56.

Typical environmental limitations applicable to Duplex Stainless Steel (30 < PREN < 40, Mo>1 .5o/o) for general applications are:

. 232"C maximum temperature,0.l barg (1.Spsig) maximum H2S partial pressure, andno specific limitation on chloride content and pH.

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o Above 100'C, DSS piping/equipment shall be painted to avoid external CISCC andpitting.

The compliant Duplex Stainless Steel shall meet the heat treatment cold work and hardnessrequirement of NACE MR0175/1SO15156-3:2009, if selected for use in this project.

8.6 UNDER DEPOSIT CORROSION

Under deposit corrosion occurs in wet liquid hydrocarbon system where solids, usually sandfrom the reservoir or corrosion products, settle out in low flow or stagnant areas. The solidsthemselves can cause preferential corrosion under the deposit (due to the differences in thechemical environment and electrochemical potential under the deposit versus the bulk flow),can prevent corrosion inhibitor reaching the steel beneath the deposit, can disrupt theformation of protective corrosion product films, or provide a breeding ground for corrosivebacteria.

Under deposit corrosion is most common in carbon steel or lower grade stainless steelsystems (such as 304 and 316). Higher grade corrosion resistant alloys such as Alloy 625are not completely immune, but the instances are rare and of low corrosion rate so CRAsystems do not have to follow such rigorous prevention as carbon steel / stainless steelsystems.

In all systems, solids should be eliminated from the system where possible, either inupstream separators / slug catchers, or filters. Since the injection gas is treated gas, it isconsidered that under deposit corrosion is not a credible risk.

Where solids are expected to settle and cannot be removed upstream, carbon and stainlesssteel pipelines should be provided with pigging facilities and be subject to regular cleaningpig runs to remove the deposits mechanically.

8.7 CONDENSING GAS PHASE CORROSION

Condensing phase corrosion can occur in:

. Wet gas piping, where cooling of the gas will result in condensation of water at the topof the pipe (i.e. top-of{he-line corrosion).

. Under moisture condensing conditions in moisture-saturated vapour lines in gasplants due to temperature gradients across the pipe wall.

The rate of corrosion in wet gas process streams is dependent on the rate of moisturecondensation across the pipe wall and the COz partial pressure in the gas. The process gastemperature before going into the topside facilities is warm downstream of compressor(-65"C) and the mean external ambient temperature is relatively high, which will limit the rateof moisture condensation on the pipe wall. Also, since the liquid has been knocked out from

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the gas prior to delivery from ZKGIP and the gas behaves as a supercritical fluid at theoperating pressure envelope.

8.8 CORROSION OF GRA MATERIALS

8.8.1 Grevice and Pitting Corrosion

Stainless steels can be susceptible to pitting corrosion, crevice corrosion and chlorideinduced stress corrosion cracking (CISCC). Resistance of stainless steels to pitting corrosion,crevice corrosion and to some extent CISCC is related to alloying elements that increase thestability of the passive layer. The elements commonly attributed to the stability of the passivelayer are chromium (Cr), and molybdenum (Mo). Dissolved nitrogen (atomic) also has animportant effect on the resistance to localized corrosion. lt is common to express thisresistance as a pitting resistance equivalent (PRE) number.

A commonly accepted formula for PRE is as follows:

PRE number = o/oCr + 3.3%(Mo + 0.5W) + 16%N

The PRE number required to confer resistance to crevice corrosion and pitting increases withthe general aggressiveness of the environment and the temperature. For any givenenvironment, there is a maximum temperature above which pitting corrosion will occur. Thistemperature is defined as the critical pitting temperature (CPT). Similarly there is atemperature above which crevice corrosion will occur for any given environment called thecritical crevice temperature (CCT). The higher the PRE number, the greater the indicatedresistance to crevice and pitting corrosion for example 31655 may typically have a minimumspecified PRE number of 25, Duplex SS PRE number is 35 while Super Duplex SS has aPRE number of 40.

A comparison of pitting and crevice corrosion resistance for a number of stainless steels inthe solution annealed condition as measured by ASTM G48 procedures (1oo/o ferric chloride)is given as follows:

Type

SS316L

SS9O4L

6Mo

22Cr DSS

25Cr SDSS

ccr fc)

-10

12

38

13

38

cPT fC)

10

42

72

33

78

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Critical temperatures for materials in the as-welded condition would be expected to beslightly lower. Higher critical pitting or crevice corrosion temperatures indicate greaterresistance to the initiation of these forms of corrosion. The CPT and CCT of 22o/oCr DuplexStainless Steel is well above those of SS 316.

8.8.2 Resistance to CISGG

CISCC is a phenomenon which is a complex interplay of stress, halide ion concentration(chloride ion in the case of a marine environment), oxygen or oxidising agent andtemperature. lt is fairly commonly accepted that the threshold stress required to produce thephenomenon is quite low and that stresses produced from welding are more than sufficient tocause cracking. Given the difficulty associated with removing the stress from the system, theonly way of preventing the phenomenon is to apply the material at service temperaturesbelow the threshold temperature. This threshold temperature is a function of materialproperty, which varies for different types of stainless steel.

Corrosion resistant materials like SS 316L and 22o/oCr Duplex SS when required to be usedabove the threshold temperature, shall be externally protected with suitable coating systemsto prevent CISCC at operating temperatures in excess of 60oC for SS 316L and 100oC for22o/oCr Duplex SS.

8.9 oXYGEN CORROSTON

Hydrocarbon systems are generally oxygen free, but small amounts (parts per billion) ofoxygen ingress into a system can have a dramatic effect on corrosion rates and theperformance of corrosion inhibitors, particularly in carbon steel systems. This is particularlytrue of sour systems where oxygen ingress can result in the formation of elemental sulphurresulting in severe pitting.

All systems, irrespective of material, should be designed to minimise oxygen ingress into thesystem, both directly (from feed streams), but more importantly from secondary streams suchas injected production chemicals and even oxygen in the nitrogen purge gas on compressorseals. Chemical handling areas should minimise the exposure of chemicals to air, and pumpsshould be designed to be leak-free, as oxygen can migrate upstream through chemical leaks,commonly experienced in pump or valve glands.

8.10 EXTERNAL CORROSION

Carbon steel piping and equipment exposed to a humid and marine atmosphere will besubject to atmospheric corrosion. Since atmospheric corrosion is an electrolytic process, thepresence of water is required. Apart from splashing by sea spray, and wetting by delugeincidents and rainstorms, surfaces can have an adsorbed layer of water if the relativehumidity of the surrounding atmosphere is sufficiently high. lt is generally accepted thatrelative humidity in excess of about 7oo/o lead to adsorbed layers of water molecules. This

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layer in combination with salt contamination from the marine environment will lead to generalsurface corrosion and possible pitting corrosion

External corrosion of offshore facilities arises due to hot humid marine conditions. For theoffshore facilities, the corrosion is mainly due to hot humid marine conditions and to rainwater exposure. The external corrosion is assumed to be zero on the basis that all exposedcoatings will be maintained as required with the recommended painting system as perADMA-OPCO Technical Standard MNL-01.

Insulated systems can be prone to corrosion under insulation (CUl). The susceptibility to CUIis dependent on the temperature range of operation, the age of the coating and the conditionof the insulation. CUI has been observed on systems operating between -5"C and 150"C.CUI is a concern in both carbon steel and stainless steel systems. Due to the risk of CUl,where possible, insulation should not be used for personnel protection (to prevent coldburns). Metal mesh cages installed around the system provide the same function, have norisk of CUI and allow access for inspection.

GUI can be averted by good insulation practices and proper coating. Properly installed andmaintained insulation simply prevents the ingress of large quantities of water. Sometimes,small quantities of water will get through the insulation. Therefore, a high quality immersiongrade coating shall be used (underneath the insulation) for equipment operating in thetemperature range at which CUI occurs. The details on type of insulation to be used and thecoating systems for each material category shall be detailed out in the respectivespecifications.

For equipment and piping fabricated from Austenitic stainless steel, whenever insulation isused, all insulation materials shall be chloride free (Cl- <10ppm), with similar requirements tobe specified in the project insulation specification, as and when applicable.

All corrosion resistant materials under insulation shall be coated with an immersion gradephenolic coating. External corrosion protection of structures, equipment, piping andinstruments will be accomplished by the application of protective coatings in accordance withADMA-OPCO Technical Standard, MNL-01 while external corrosion protection of immersedstructures, piping, equipment, etc., shall be achieved by Cathodic Protection complementedby suitable coating in accordance with ADMA-OPCO Technical Standard, MNL-O1.

Following equipment / piping installation, the bare carbon steel vessels / piping shall beinternally protected with a temporary corrosion protection treatment which may be nitrogenfilling, vapour corrosion inhibitor treatment or desiccant bag installation.

8.11 OTHERCORROSIONCONSIDERATIONS

Apart from above corrosion problems, various other corrosion considerations encountered inthe offshore facilities will be taken into account during material selection:

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. Galvanic Corrosion. etc.

. Microbial/SRBCorrosion

Galvanic corrosion can be a result of coupling dissimilar materials in an electricallyconductive environment. The more noble material, generally the more alloyed material, will

act as a cathode and less noble as the anode. lf the cathodic area is large compared to theanodic area, then an accelerated localized corrosion rate can occur.

At dissimilar material connection interface, i.e. at connections between material of differentcorrosion resistances like SS316L to carbon steel. measures shall be taken to ensure that no

accelerated corrosion due to galvanic effect occur.

Usually, an insulation kit /gasket at combination flanges comprise of Phenolic I PE / Mylar

sleeves insulation gasket and washer to eliminate electrical continuity between the two

different materials and prevent galvanic corrosion. Carbon steel bolts used at combinationflanges should be fully preserved using denso tape and grease.

Galvanic corrosion should be controlled externally by coating the surfaces locally to lengthen

the thin "conductive water path" so that significant corrosion current will not pass. Externalgalvanic corrosion at a dissimilar metal junction requires continuous monitoring to ensure

soundness of external coating, insulation gaskets, sleeves and washer. Periodic

maintenance should be performed to restore any damaged external coating or insulating

material.

Internal galvanic corrosion can be avoided by using separation spools i.e. rubber-lined spools

of length equal to 5D to minimize the corrosion current flow (though the high pressure

considered in this project limits this) or if the piping is too small for rubber-lined spools, asacrificial spool. Also, the more noble material can be internally coated close to theconnection. The length of the coated section shall be minimum 10 pipe diameters.

It should be noted that low galvanic corrosion is expected to occur in dry gas process

streams. This is only an issue in continuous wet service which is not the case here. As aprecautionary measure, such interfaces should adopt the suggestions above to minimize any

effect of galvanic corrosion.

Microbial/SRB Corrosion is a problem with lines having high water cut. Since, the gas is dry,

MIC/SRB will not be a problem in this project.

8.12 SOUR SERVICE CONSIDERATIONS FOR NON.METALLIC MATERIALS

Notwithstanding the uncertainties associated with production fluids composition changes with

time, temperatures, pressures etc. ADMA-OPCO shall in conjunction with the equipmentsuppliers and the non-metallic materials suppliers endeavour to select the most appropriatenon-metallic materials for the various different applications.

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Nitrile (NBR) and Hydrogenated Nitrile (HNBR) elastomers are usually acceptable for H2S

levels of 10-100ppm and 100-1000ppm respectively based on seal geometry andtemperature but since H2S levels greater than 1000ppm are envisaged, Nitrile rubbers aretherefore not deemed suitable for this project. For HzS levels up to 57o mole, FKM "Viton"type fluoroelastomers or Tetrafluoroethylene- propylene copolymer (TFEP) "Aflas" shall beused. Above 5% mole H2S level, EFKM perfluoroelastomers (Chemrez or Kalrez) shall berequired. PTFE has excellent H2S resistance. Elastomeric seals shall be tested for resistanceto explosive decompression for systems rated equal to and above #000.

8.13 LIQUID METAL EMBRITTLEMENT - ZINC

Liquid Metal Embrittlement (LME) is one of the few embrittlement processes that have beenreceiving less of an emphasis due to increasing concerns on hydrogen embrittlement by HICand SSCC. In cases where LME has occurred, it has been mainly due to zinc embrittlementof austenitic stainless steels. lsolated failures have been attributed to welding in thepresence of residues of zinc-rich paint or to the heat treating of welded pipe components thatcarried splatter of zinc-rich paint. However, most of the reported failures due to zincembrittlement have involved welding or fire exposure of austenitic stainless steel in contactwith galvanized steel components.

In many cases, through-wall cracks cause leaks during hydrostatic testing. Typically, zincembrittlement cracks contain zinc-rich precipitates on fracture surfaces and at the very end ofthe crack tip. Cracking is therefore intergranular in nature.

Zinc embrittlement is a relatively slow process that is controlled by the rate of zinc diffusionalong the austenitic grain boundaries. Zinc combines with nickel and this result in nickeldepleted zones adjacent to the grain boundaries. The resulting transformation of face centredcubic (FCC) austenite to body centred cubic (BCC) ferrite in this region is thought to producenot only a suitable diffusion path for zinc but also the necessary stresses for initiatingintergranular cracking. Externally applied stresses accelerate cracking by opening priorcracks to liquid metal.

Although the melting point of zinc is 42OoC (788oF), no zinc embrittlement has been observedat temperatures below 570oC (1380oF), probably because of phase transformation anddiffusion limitations. There is also no evidence that an upper limit exists. In the case of zincrich paints, only those having metallic zinc powder as a principal component can causezinc embrittlement of austenitic stainless steels. Paints containing zinc oxides or zincchromates are not known to have caused zinc embrittlement. Therefore paint formulationsused should not contain metallic zinc, because of the possibility of inducing liquid metalembrittlement.

The best approach to the prevention of zinc embrittlement is to avoid orcontamination of austenitic stainless steel components in the first place. lnmeans using no galvanized structural steel, such as railings, ladders,

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mtntmtze zrncpractice, this

walkways, or

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!fficorrugated sheet metal, at locations where molten zinc is likely to drop on stainless steel

components if a fire occurs. However, many steel structures are usually hot dippedgalvanised. Uninsulated austenitic piping placed over galvanised structure should beseparated by providing polyethylene sheets to prevent overspray and splatter.

Where zinc rich primers are used, care shall be taken to avoid the contamination of austeniticstainless steel, nickel alloy or 9% nickel steels to avoid zinc embrittlement.

8.14 LOWTEMPERATURECONSIDERATIONS

Low temperature embrittlement will be a problem where, process fluids handled are

cryogenic in nature.

For most of the ferritic steels, with the lowering of operating temperature below OoC or much

lower, they undergo a ductile to brittle transition in fracture behavior. At cold temperatures,the toughness of the steels become so low that even with a small impact load, the material

could fail in a brittle manner.

The prevention of low temperature embrittlement can be achieved by using, fully killed, finegrained carbon steel with improved toughness and use of Ni-alloyed ferritic steels, like 9%Ni.

For further cryogenic applications, it is recommended to use Austenitic stainless steels (e.9.

SS 304/316) up to - 196oC without impact testing.

For this high pressure dry gas piping, the lowest design temperature (LDT) shall be

determined and materials selected accordingly. For mechanical design as per ASME code,the LDT will be set as the minimum design metal temperature (MDMT). The vent system will

be assessed for suitability for low temperatures experienced as a result of blowdown of the

facilities. As far as possible, steels shall be impact tested at the standard specifiedtemperature in their material specification, e.g. -45oC for ASTM 4333 Grade 6.

In general, the following material selection guidelines may be used for low temperaturecomponents:-

. MDMT > 29oC:

. -45oC < MDMT < -29oC:

o -101oC < MDMT < -45oC:

o -196oC < MDMT < 101oC:

CS

LTCS

3.5 Ni

9Ni

9 MATERIALS SELECTION CRITERIA

The materials selection criteria are primarily focused on preventing both internal and externalcorrosion to withstand the process design conditions and to ensure non-contamination ofproduct. The selection is further driven by economics and ease of fabrication.

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The default material choice for hydrocarbon systems is primarily carbon steel. Corrosionpredictions (both internal and external) are made to estimate the carbon steel corrosion ratefor the given process conditions and a corrosion allowance is calculated for the design life. lfthis corrosion allowance is small enough to be economically and practically acceptable (forexample 1.5 - 6.0mm), carbon steel is usually adopted. Otherwise, carbon steel withcorrosion inhibitor injection will be the next best option to be considered. Depending on lifecycle cost analysis, corrosion inhibitor injection is planned for the project pipeline based onthe pitting expected due to the high H2S content within the dry gas being delivered. Thisadded on effect of inhibition can be considered to be effective for the topside piping up to thechoke valve at the respective WHT.

lf the inhibited corrosion allowance required is found to be excessive (> 6mm), alternativecorrosion resistant materials will be considered and recommended for use with costoptimization being the governing factor based on technical requirements fulfilled by theselected material.

For low temperature operations, the materials selection will be as dictated in Section 8.14.

Corrosion rate calculations and material selection have taken into account the variouscorrosion mechanisms described in Section 8. Evaluation of corrosivity has, as a minimum,considered the following factors:

. COz and H2S content

Oxygen content and other oxidising agents

Operating temperature and pressure

Organic acids, pH

Halide, metal ion and metal concentration

Velocity and flow regime, erosion conditions

Biological activity

Condensing conditions, etc.

Corrosion control strategy

Material availability and weldability

Service life

o Possible extreme and upset conditions.

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10 CANDIDATE MATERIALS

This section reviews the suitability of individual materials for the project facilities. Theadvantages and disadvantages of each material are considered such that recommendationsfor pipe work, vessels and equipment can be made.

10.1 CARBON STEEL

Carbon steel is the basic material considered for process and/or utility equipment, piping,

valves and fittings. Economically, it is the most suitable and the basis of this materialsselection report is to specify carbon steel wherever it is found to be acceptable for theprocess conditions studied. The dominant position of carbon steel as a material ofconstruction (MOC) is due to an un-matched combination of low material cost and excellentmaterial properties, such as a (relatively) high tensile strength, high modulus, excellentimpact resistance and high toughness, its largely isotropic material properties, the absence,in general, of any degradation ("ageing") of material properties over time, cost effectiveproduction routes and a reliable way to connect pipes (by welding).

Compared to its advantages, there are few drawbacks of carbon-steel that can limit itslifetime. The main integrity problem is internal corrosion as a result of the corrosive conditionof the process fluid handled. Other integrity problems are due to external corrosion, wherethe external coating and cathodic protection have failed to give sufficient external corrosionprotection. However, all the above problems can be controlled if a proper CorrosionManagement and Maintenance Strategy (CMMS) is adopted and followed. Considering theabove, it is therefore deemed feasible to use carbon steel for the topside piping and

equipment MOC with suitable corrosion allowance and having in place a good CorrosionManagement and Maintenance Strategy.

A corrosion allowance of 1.Smm will generally be selected for all non-corrosive processmedia fabricated out of carbon steel equipment and piping. For other equipment and piping,

where corrosion is expected to be < 0.1mm/yr, a corrosion allowance of 3mm will be

specified. ADMA- OPCO specifies that a minimum corrosion allowance of 3mm is required

for CS based on STR-002.

Carbon steel shall normally be selected for an accumulated corrosion less than 3mm unlessit can be demonstrated that corrosion resistant materials are more cost-effective.

Carbon steel may be selected if the accumulated corrosion is between 3-6mm, based on acase-by- case evaluation, taking into consideration the following:

o Risk assessment

o Additional Corrosion Monitoring

r Potential Cost Saving

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For low temperature operations, normalized fully killed steel is recommended up to -29oC asper ANSI/ASME B31.3. For temperatures down to -45oC, LTCS (ASTM A333 Grade 6) withimpact testing is specified.

10.2 FERRITIC NICKEL STEELS

For low temperature operations below -45oC, ferritic nickel steels are recommended, due toits very good ductileto-brittle transition property. Generally, 3.5%Ni steels are possible

options to be used down to -101oC and 9%Ni steels down to -196oC requiring a minimumcorrosion allowance of 1mm.

However, the main problem with these ferritic steels is the fabrication and problem ofhardness in the as welded condition, leading to cold cracking and failure. To avoid thisproblem, post weld heat treatment would be required.

Hence, considering the problem of fabrication, welding and cracking, Ferritic-Nickels steelsare not recommended for the current topside facilities under study.

10.3 AUSTENITIC STAINLESS STEELS

Austenitic stainless steel contains both Nickel and Chromium. The addition of substantialquantities of Nickel to high Chromium alloys stabilizes the Austenite at room temperatures.The most common composition of the standard Austenitics is 18%Cr - 8%Ni with addition ofother alloying elements. Type 304 and 316 are widely used in the process industry. The Type300 series alloys are more susceptible to attack from the marine environment (offshore andcoastal areas), in the form of chloride induced stress corrosion cracking (CISCC) andexternal pitting. The same problems can occur with internal process fluids if they containsufficient amounts of chloride and oxygen.

In comparison between SS304 / SS304L and SS316 / SS316L, the latter has got betterresistance to CISCC and pitting due to the presence of Mo. Hence, SS316 / SS316L will be

the recommended MOC to be used in this topside facility when the use of austenitic stainlesssteel is required. In addition, wherever fabrication by welding is involved, low carbon 'L'grade will be recommended to avoid cracking due to sensitization.

As an additional precaution, both insulated and non-insulated solid SS equipment and piping

above 60oC shall be externally painted in accordance to MNL-01 for low-risk service systems,SS316 and SS317 piping. However, it should be noted that external painting or coating maynot be an acceptable solution to prevent CISCC in high-risk piping systems subject to ADMA-OPCO approval.

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lt is recommended that the SS316 / SS316L material procured shall have minimum 2.5o/o Mo

to improve CISCC and pitting resistance of the material. However, in oxygen freeenvironments, the problem of chloride pitting and cracking is not an issue.

For instrument and hydraulic tubing, it is recommended that the above recommendation be

strictly followed with austenitic stainless steel supplied in the solution annealed condition.Alternatively, higher grades like SS316Ti or SS317 can also be considered. As per SP-1000,austenitic stainless steel instrumented tubing shall be PVC sheathed to prevent externalCISCC.

For low temperature applications, austenitic stainless can be considered safe to use up to -196'C without impact testing. The use of solid austenitic stainless steel material would onlybe necessary if blowdown requirements deem that the associated piping and equipmentwould necessitate the use of material capable of withstanding temperatures lower than -1000c.

10.4 SUPER AUSTENITIC STAINLESS STEELS

Super Austenitic Stainless Steels with higher Chromium and Nickel contents and with highMolybdenum content makes these steels more resistant to pitting and crevice corrosion thannormal stainless steel (300 series). Furthermore, due to its relatively high Nickel content incombination with high levels of Chromium and Molybdenum (6%) and high content ofNitrogen (0.2o/o), these steels have high mechanical strength, high ductility and impactstrength as well as good weldability.

These steels also satisfy the NACE requirements by passing both the Sulphide StressCorrosion Cracking (SSCC) and Chloride Induced Stress Corrosion Cracking (CISCC) tests.Due to its lower carbon content, these steels have good Inter Granular Corrosion (lGC)

resistance. Examples of the Super Austenitic Stainless Steels are as follows:

UNSNo.

Gommercial

Grade c Mn Si Cr Ni Mo N Others

s31254Avesta 254

SMO 0.0201.0

(max)1.0

(max)19.5-

20.517.5-

18.5 6.0-6.50.1 8-

0.22 Cu

N08904 SS 9O4L 0.0202.0

(max) 1.019.0-

23.023.0-28.0 4.0-5.0

0.1

(max) Cu

Hence, Super Austenitic Stainless can be considered as an alternative MOC; however, itscost may be prohibitive.

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10.5 DUPLEX STAINLESS STEELS

Duplex Stainless Steel derives its name from its microstructure, which is usually a mixture of50 - 50 blend, of both Austenitic and Ferritic structure. The combination of these two phasesresults in capturing the best mechanical and corrosion resistance properties for each phase.Duplex Stainless Steel has significantly better chloride (CISCC) resistance than normal 300series stainless steels. With nitrogen additions, these alloys have high strength, toughness,ductility and fabricability. These alloys are available in all forms of product due to their goodformability and are being used for highly corrosive lines. Examples of the Duplex StainlessSteels are as follows:

UNS No.Commercial

Grade c Mn Si Cr Ni Mo N Others

s31803SANDVIKSAF 2205

0.0201.0

(max)1.0

(max)22.5 5-6.07 3.5 0.05 Cu

Super duplex material should not be considered for wet gas systems since the material is

very sensitive to intermetallic precipitation and thus should be avoided.22%Cr duplex shouldbe specified. Even though most of the design codes permit use of DSS materials up to250'C, based on field experience of various operators, it is highly recommended to restrict its

use up to < 110oC. lf used above this temperature, it shall be either painted with a suitableepoxy paint system or metalized thermal sprayed aluminum (TSA) coating.

Hence, DSS can be considered as an alternative candidate material if necessary.

10.6 NICKEL BASED ALLOYS

Nickel is a versatile element and will alloy with most metals. While it is completely solidsoluble with copper, a wide solubility range between iron, chromium and nickel make it

possible for many alloy combinations to be obtained.

Nickel-based alloys are used in many applications where they are subjected to harshenvironments at high temperatures. Nickel-chromium alloys or alloys that contain more thanabout 1So/oCr are used to provide both oxidation and carburization resistance at temperaturesexceeding 760"C.

Nickel-based alloys offer excellent corrosion resistance to a wide range of corrosive media.However, as with all types of corrosion, many factors influence the rate of attack. Thecorrosive media itself is the most important factor governing corrosion of a particular metal.

lnconel 625, a Nickel-based alloy (58%Ni minimum) which is to be considered for this project,is a solid-solution matrix stiffened face-centred cubic alloy. The high alloy content of Inconel625 enables it to withstand a wide variety of severe corrosive environments. Inconel 625

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retains its excellent ductility and toughness at low temperature and can be used for lowtemperature applications as identified in Section 8.14.

In mild environments such as the atmosphere, fresh and sea water, neutral salts and alkalinemedia, there is almost no corrosion attack. In more severe environments, the combination ofnickel and chromium provides resistance to oxidizing chemicals, whereas the high nickel andmolybdenum contents supply resistance to non-oxidizing environments.

The high molybdenum content also makes this alloy very resistant to pitting and crevicecorrosion, as mentioned in Section 8.8.1. The columbium within the alloy acts to stabilize itagainst sensitization during welding, thereby preventing subsequent intergranular crackingand the high nickel content provides freedom from CISCC.

It is in the resistance of Inconel 625 to intergranular corrosion due to sensitization that thealloy shows outstanding performance. In general, nickel-chromium and nickel-iron-chromiumalloys are subject to severe intergranular corrosion in some very aggressive environments ifthey are heat-treated to produce sensitization. lnconel 625 however shows unusual stabilityafter being welded or when subjected to heat treatments that result in serious sensitization ofother nickel-chromium and nickel- iron-chromium alloys.

lnconel filler metal 625 is a nickel-chromium-molybdenum product designed for weldinglnconel 625 to itself and other materials. When used to weld Inconel 625 to dissimilar metals,the filler metal tolerates a high degree of dilution yet maintains characteristic properties.

Hence, Inconel 625 would be a very suitable material to be used in this project. However,due to its extreme cost, its application should be limited in lieu of other cost effectivematerials available to serve the intended purpose of application. Due to the propertiesmentioned above, such as corrosion resistance, excellent ductility at low temperatures, goodweldability with itself and other dissimilar metals and its resistance to low temperature creepeffects, lnconel 625 could be selected as an effective transition spool between SS316Lpiping and CS piping or between adjacent CS piping for venting or purging sections whichmay be subjected to rapid transition from high to low temperatures. However, electricalisolation should be ensured at such dissimilar metal junctions using insulating flange kitscomplete with bolt protection such as denso tape and grease for the corresponding carbonsteel bolts to avoid galvanic corrosion of carbon steel in contact with a more noble metal.External painting should be provided and such flange junctions should be continuouslymonitored and maintenance of external coating and insulating material performed whenrequired.

UNSNo.

Comrnercial

Gradec Mn, Si s,P Cr Fe Mo

Nb+Ta

Otherc

N06625 Inconel6250.01

(max)0.5

(max)0.015(max)

20.0-23.0

5.0

(max)8.0-

10.0

3.1 5-

4.15Ti, Co, Al

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10.7 GRA LINING / GLADDING AND INTERNAL COATING

The advantages of clad materials are that they can handle highly corrosive internal fluidscontained within a thin corrosion resistant barrier while the strength of the vessel is providedby economically cheaper outer carbon steel.

Lined / Clad pipes are manufactured mainly by these two processes:

o Metallurgically bonded pipe

. Mechanically lined pipe

Amongst the two processes, the metallurgically bonded pipes are superior in properties andhigher in cost. The mechanically lined pipes are slightly inferior (liner collapse), however,cost effective in comparison. As per ADMA-OPCO requirements, lined CRA piping is notconsidered for this offshore facility. lf necessary, only CRA cladded CS will be an acceptableoption subject to ADMA-OPCO approval of its use. Therefore, CRA cladded CS shall bemetallurgically bonded and may be applied by roll bending during plate manufacture,explosive bonding or by weld overlay.

For piping and equipment utilizing pressures above 20 Barg and temperatures above 80oCwhen carbon steel corrosion allowance is not acceptable (i.e. > 6mm), metallurgically bondedCRA cladding shall be used with SS316L or Inconel 8251625 being the preferred overlaidmaterial instead of considering a solid CRA option.

It should however be noted that the price difference between solid CRA and CRA-clad steelvessels or piping decreases with decreasing wall thickness. For vessels and piping with wallthickness less than 10mm-1Smm, solid CRA option should be considered, ensuring thetemperature limits specified in the above sections for the particular CRA of choice areadhered to.

Amongst the above three materials mentioned, considering the process fluid is more or lessoxygen free and service is essentially dry gas except for process upsets, SS316L would besufficient and economically attractive when compared to the costlier higher Nickel Alloys ofInconel 825 and 625.

Hence, SS316L metallurgically clad pipes are deemed feasible for use in this project ifnecessary and can be considered as an option for the piping and equipment if inhibitedcorrosion rates are deemed to be in excess of 6mm for the carbon steel substrate. The useof cladding would also lead to a maintenance-free solution in terms of corrosion mitigationand monitoring.

Due to manufacturing limits, piping with diameters less than 4" shall apply solid CRA whencarbon steel corrosion allowance is not acceptable (i.e. > 6mm) and CRA clad requirementsare only usually considered for piping with diameters > 6" taking into account the pricedifference that the wall thickness would afford as specified above.

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Internal coatings / linings are also considered less expensive for equipment in continuous wetservice where temperature and process conditions are milder thus reducing the requirementof metallic cladding.

Where organic coatings / linings are not possible due to the unwanted maintenancenecessary after 3-5 years or due to limitations posed by temperature and pressure, superiorquality Belzona coating or metallic cladding can be considered.

{0.8 BOLTING MATERIALS

The general flange bolting material for bolting in piping systems and equipment for carbon orlow-alloy steel and other selected material shall be in accordance with ADMA-OPCOTechnical standard STD-1 26.

Bolts screwed into component bodies shall be of a material that is compatible with the bodywith respect to galling and shall allow disassembly of the component for maintenance, ifrequired. The risk for galvanic corrosion and leakage due to differences in the thermalexpansion coefficient shall be considered.

Carbon steel and/or low-alloy bolting material shall be hot-dip galvanized or have similarcorrosion protection. Hot dip galvanizing of bolting shall be performed in accordance with SP-1015. Cadmium plating shall not be used.

10.9 GRE/FRP

Glass Fibre Reinforced Epoxy (GRE) and/or Fibre Reinforced Plastics (FRP) are commonlyused for seawater (firewater) service and water lines because of their chemical resistance.However, GRE has limitations in terms of operation and maintenance, due to limitedstrength, ductility and the need for more elaborate supports. The allowable designtemperature range for GRE is -40oC to 95oC and up to 80oC for vinyl ester-based FRP. Theyshould also not be used for systems with operating conditions above 4OBarg.

Therefore, GRE / FRP can be recommended for use in low-pressure piping systems such asfor handling potable water or firewater systems. Dry GRE/FRP piping should be deliveredfireproofed and should pass the necessary requirements placed on it by local authorities.However, except for flanges and fittings, wet GRE/FRP piping shall not be fireproofed.

As an alternative to fireproofed GRE/FRP piping for firewater dry deluge systems, 90/10CuNi can be recommended as it has good corrosion resistance in stagnant seawaterbecause the copper content gives good antifouling properties. The maximum velocity shouldbe 3.5 m/sec in continuous service.

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11 MATERIALS SELECTION

11.1 CARBON STEEL WITH CORROSION ALLOWANCE

CS plus corrosion allowance shall be the default material unless alternatives are fully justifiedby life cycle analysis, taking into account theoretical corrosion predictions and other keyfactors.

Corrosion allowance is defined as being extra wall thickness added during design tocompensate for any reduction in wall thickness by corrosion (internally/externally) duringdesign life.

In determining the corrosion allowance, the following factors are taken into consideration:

o Predicted corrosion rate:

. Design life;

. Expected form of corrosion damage;

. Expected reliability of planned techniques and procedures for corrosion mitigation(e.9. chemical treatment of fluid, inhibitor availability and efficiency, external coating,etc.);

. Expected sensitivity and damage sizing capability of relevant tools for integritymonitoring, time to first inspection and planned frequency of inspection;

o Conseguences of sudden leakage, requirements to safety and reliability; and

r Potential for down-rating (or up-rating) of operating pressure

11.2 CORROSION RATE PREDIGTIONS

Appendix 1 provides corrosion rate predictions generated by ECE-S for all cases considered.

11.2.1 Injection Gas

From Appendix 1, it can be seen that predicted bulk corrosion (Bsp) rates are very low for allcases modeled. The basis for this is there is no or insufficient liquid water to drive wetcarbonic acid corrosion, coupled with protection benefit from iron sulphide films which form inthe presence of H2S.

For a design life of 30 years, a minimum corrosion allowance of 1 mm would be deemedsufficient for the ZKGIP topside injection gas piping in WG3A scope. However, as identifiedin SELECT phase and STR-002, a CA of 3mm shall be adopted. This is considered to bemore than sufficient to cater for the corrosion rates expected during normal and upset

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conditions. On this basis, CS + 3 mm CA compliant with project sour service requirements is

recommended for topsides piping carrying injection gas.

As an added contingency, corrosion inhibitor injection would provide added assurance in

case wet upset was prolonged or process conditions changed during well life. With the 3mm

CA adopted at 95% availability, 3mm corrosion allowance is sufficient and the Cl injection

system would be operated only in the event water was detected entering the system or as aresult of negative feedback from corrosion monitoring systems at injection gas pipeline

departure and/or arrival.

In the unlikely event sour pitting corrosion is initiated, ECE indicates penetration rates could

be significant. However, for dehydrated gas service with very occasional presence of liquid

water, sour pitting is not considered a credible threat. Refer Section 12 for Cl requirementsto mitigate pitting.

1{.3 PIG LAUNCHER / RECEIVER

The permanent pig launcher to be installed on ZKGIP under WP3A scope is recommended tohave pigging barrels, end closures and associated piping fabricated from CS (NACE) + 3mm

CA considering the launcher / receiver is in a depressurized condition while on stand-by.

Nitrogen purging is recommended to ensure better corrosion control.

ln compliance with ITT job specification, Pig Launcher 447-L-2200 shall meet an increased

design life of 40 years. From corrosion control standpoint, this increased design life is safelyaccommodated by carbon steel with the 3mm corrosion allowance since the launcher is used

infrequently and will be drained, dried and interted during stand-by periods.

11.4 CORROSION INHIBITOR INJECTION PUMP

Undiluted inhibitor chemicals can be corrosive to carbon steel. On this basis. corrosioninhibitor pump, 447-P-2417, shall be SS316 or SS316L.

11.5 MATERIAL SELECTION SUMMARY TABLE

,|1.6 HYDROTEST

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String / Piping / Equipment Materials SelectedCorrosionControl

Remarks

Injection gas piping/headers/manifolds

- all platformsCS-SOUR + 3mm CATrim: Alloy 625

DehydrationHzS controlled corrosion,protective iron sulphide filmsassumed

Cl lniection Pumo SS316 or SS316L CRA

Pig Launcher / Receivers CS-SOUR + 3mm CA Draining/drying/inertingafter use

Cl PipingU/S pump: SS316LD/S pump: Alloy 625

CRA

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During hydrostatic testing of the topside facility using seawater, the appropriate chemicalinhibition should be added to the test water e.g. bactericide, oxygen scavenger and filmforming agent. Ultimately, the piping should be dried (e.9. glycol swabbing, vacuum drying,etc.) and nitrogen purged to a dew point of -20oC minimum before it is commissioned toensure that the piping is dry before the gas is allowed to flow.

For SS316L piping, seawater shall be avoided and fresh water with chloride concentrationless than 30ppm shall be used. lf unavoidable, only potable water with chloride level lessthan 100ppm shall be used afterwhich the piping system shall be flushed with chloride freewater as soon as possible as per SP-1021 .

12 CORROSION INHIBITOR PHILOSOPHY

12.1.1 General

Where high corrosion rates are predicted for carbon steel piping operating conditions, variousmethods may be available to reduce the rate of corrosion and these are listed below:

. cool the fluid:

continuous inhibition; film forming amine is injected into the piping to coat the pipewall and prevent corrosion;

internal coating; non-metallic materials can theoretically be applied to the internalsurface of the pipe to prevent the carbonic acid coming into contact with the steel butpractical use of internal coating from corrosion prevention point of view is notrecommended;

use of corrosion resistant alloys either as solid pipes or as cladding layers on carbonsteel substrates;

removal of COz gas; processing plants are available which can remove COz andhence prevent the formation of carbonic acid;

. dehydrate the gas; reduce the water dew point below the minimum operatingtemperature in the piping such that no free water will be available to initiate carbonicacid corrosion.

Often the most effective techniques are dehydration, cooling and/or continuous/intermittentinhibition (batch inhibition is operationally very onerous). Appropriately, ADMA-OPCO haveemployed dehydration and cooling at ZKGIP prior to delivery of the sour injection gas to limitcorrosion effects. However, it is also advised that intermittent inhibition be recommended asanother technique to be applied in ZKCGIP to limit H2S pitting and at the same time reducemesa corrosion if any during upsets. Internal coating is problematic (see below), alloy

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EZ24E: ZADCO UZT5OKWP-3A PROJECT

materials such as Duplex SS can expensive and CO2 removal plants are considered to offerno advantage over the drying facilities already installed at ZKGIP.

Hence, for ZKCGIP, intermittent injection of corrosion inhibitor, which is the most practicalsolution, should be adopted for corrosion control during process upsets when the dehydrationsystem at ZKGIP is not operating at its intended capability. Dew point meters should beinstalled accordingly to capture any moisture detected within the injection gas stream.Injection of inhibitor into the dry gas stream is generally not required except when concern ofwater or wet products is detected by the dew point meters installed. The following factorsshall be considered during the selection of a corrosion inhibitor:

. The inhibitor should be subjected to a test programme, which evaluates all relevantfactors and ensures that the inhibitor will meet the specified inhibited corrosion raterequirements. The appropriate inhibitor solvent package shall be used (preferablyhydrocarbon-based) to minimize the risk of gunking in the system. This generallyrequires an inhibitor that has been specially formulated to avoid solvent evaporation,gunking in dry gas streams. Relevant factors include simulation of the fluid corrosivitywith respect to:

1. CO2 and H2S partial pressures

2. Temperature

3. Aqueous phase compostion

4. Hydrocrabon/condensate composition

5. Hydrodynamic shear stress at pipe wall

o Chemicalcompatibility with other injection chemicals that will be injected.

. Review of the effects of the inhibitor on the entire process stream from injection topoint of sale or disposal.

o Provision of initial pipeline filming and determination of long{erm injection rates undervarious flow rates and flow conditions.

Control and monitoring of usage.

lmpact on valve elastomers and toxicity of inhibitor.

Long-term supply.

Selection of suitable injection points (plus spares) and the ability to inject otherinhibitors if process conditions change.

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EZ24E= ZADCO UZ750KWP-3A PROJEGT

Review of system performance if inhibitor supply fails, including persistency, time forcorrosion to start, corrosion rates expected if not inhibited and any areas of high risk.

Effects of major operational changes (new reservoirs, compression, increased flowrates/water cut, etc.) on inhibitor performance.

Quality control at inhibitor supply.

Reliability of inhibitor injection system.

Methods of inhibitor injection.

Review of how the inhibitor will partition between the various fluids, and checking thatthe concentration of inhibitor is consistent with allowable discharge levels (bothcurrent and expected future levels) or sales specifications (e.9. acceptable level in thecondensate), as applicable.

Service requirements from inhibitor supplier.

12.1.2 lnhibitor Effectiveness and Availability

Corrosion inhibitor has been assessed as the primary means of corrosion management inintermittently or predominantly wet process streams to allow the use of carbon steel with anacceptable corrosion allowance, provided the chemicals used and the method of injectioncan effectively and reliably control the corrosion rate.

The inhibitor effectiveness comprises of the efficiency of the chemical in the process (howmuch it reduces the native uninhibited corrosion rate when dosed properly), and the reliabilityof the injection process (how often inhibitor is actually injected and available to inhibitcorrosion in the process). For ZKCGIP, the values for the inhibited corrosion rate andinhibitor availability (95% for single injection point) used has been specified.

A list of possible uninhibited events that could occur to limit the inhibitor availability isprovided in AD156-447-G-01255 which should be considered in design criteria to achieve theinhibitor availability of 95o/o. The inhibitor availability for ZKCGIP topside facilities is 95% forsingle point injection, but the corrosion allowance determination shall be based on:

Ensuring that the inhibitor chemical selected is able to achieve the specified inhibitedcorrosion rate irrespective of the corrosivity of the environment.

Ensuring that the dose of chemical is sufficient to be able to achieve this level ofprotection throughout the system to be protected, and that facilities to check thiseffectiveness (corrosion monitoring and sample points) are provided at appropriatepositions in the process.

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Ensuring that the inhibitor is injected in a manner that the full performance efficiencyof the chemical can be achieved throughout the system, by the appropriate location ofinjection points, and the specification of the proper injection apparatus (i.e. quills /atomizer).

Ensuring that the chemical injection system is sufficiently reliable to provide chemicalinjection for a defined percentage of the design life.

Ensuring that the onsite facilities are equipped with sufficient chemical storagecapacity to provide continuous supply of chemical for the maximum duration between

supplies, taking into account such factors as storms preventing offloading.

. Ensuring that the responsible party is committed to their assignment.

. Failure to ensure the target inhibitor effectiveness is met will reduce the life of thesystem, potentially below the required design life.

12.'1.3 Operation and Reliability

The quality of operation of the chemical injection system is critical to the effectiveness of theinhibitor treatment and therefore to the reliability of carbon steel systems. Factors include thequality and consistency of chemical supply, regular operator checks and/or control room

surveillance, pump and injector maintenance, injection adjustment and performance

verification to ensure the required corrosion inhibitor availability of 95o/o for the singleinjection point is achieved.

The initial injection rate for this essentially dry system shall be based on the following:

. 0.25litres / MMSCFD as per STR-002.

. Residual inhibitor concentration shall be at least 100 ppmv minimum in the waterphase, if any is present after cleaning pig runs.

Corrosion inhibitor injection pumps shall have the flexibility to inject 0.15 to 1.5 litres /MMSCFD.

12.1.4 Ghemical Performance

The chemical's ability to achieve the target inhibited corrosion rate must be proven prior todeployment. The type(s) of inhibitor required shall be based on recommendations specified in

AD156-447-G-01255, and checks should be made that suitable inhibitor products are

available locally from pre-qualified products to meet the intended service requirements.

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12.1.5 Delivery System Design

The detailed design of the system (i.e. placement of injection points, design of injectionatomizers, design of chemical supply systems, availability of pumps, potential for blockages,provision of alarms, quality of equipment purchased) will dictate the base mechanicalreliability of the system, and so have a strong effect on the overall effectiveness of theinhibitor treatment over the life of the field.

Table 2: Griteria for Inhibitor Svstem Desiqn to Meet Specified Svstem Availabilitv

tem Descriptionnhibitor Availability

)5o/o

Inhibitor demonstrated as suitable for the application

Inhibitor injection pumps High reliability

Back up pumps

Check that pump is operating Automated alarm

Pump planned maintenance Annual

Inhibitor tank levels Automated alarm

Report on inhibitor used (or report on compliance with kerperformance indicators) to responsible corrosion engineer

Weekly

Quarterly manual check on pump injection rate

No flow alarm (zero differential pressure across a criticalcomponent, or in line flow meters)

Liquid samples for analysis of residual inhibitor levels andwater chemistry Monthly

Corrosion monitoring system response timeResponse time such that total number of eventsx time to responde is < 4 days/yr

Typical choices for corrosion monitoring equipment andsystem response times

On-line ER probes, response time t hr to 1 dayand daily monitoring of inhibitor injection usage

Comprehensive review of uninhibited events Required

Allowed days inhibitor system downtime per year 18

Shut-in if inhibition system goes down for greater than adefined period of time Possibly (for high corrosivity systems)

ldentify Operations Technician with responsibility for theinhibition injection system

Corrosion Engineering I nvolvement Weekly review for compliance

Key Performance Indicators set for Operations Techniciansand Corrosion Engineers

The determination of the piping corrosion allowance for topsides facilities have been basedon the essentially dry nature of the sour gas supplied from ZKGIP. lf for any reason thisessentially dry gas becomes wet due to intermittent upsets, the corrosion managementsystem should be designed and operated in service on the basis of an inhibitor availability of95% due to the concerns of H2S pitting on the CS pipe wall when wet conditions arise.

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EZ16E: FACILITIES FOR 4 NEW cAS INJECTORS AND3 BARREN TOWERS IN ZAKUM FIELD


12.1.6 Injection Locations and Equipment

Intermittent corrosion inhibitor should be injected into the upstream gas as one of thecorrosion control measures. Corrosion inhibitor injection point should be provided at thefollowing location:

o Upstream of pig launching facilities prior to the dry injection gas entering the 10"

pipeline from ZKGIP.

Equipment and Fittinos

Chemical injection should be by a dedicated atomizing injection via high pressure chemicalinjection access fitting (available from Rohrbach Cossasco, Corrocean, Caproco, Cormon orCorTest) such that the inhibitor is injected into the mid-point of the pipe. The chemicalinjection points should be upstream of any pig launcher to prevent interference with the pigs.

Where possible, the injection fittings should be installed at areas of high turbulence to ensurethat the inhibitor will be adequately mixed into the stream. Preferably, the chemical injectionpoints should be installed on the top of the line wherever possible. Only access fittings withwelded or flanged tees shall be used for sour service. Threaded tee fittings shall not be

acceptable due to the likelihood and dangers of unwanted leakages caused by suchconnections when inappropriately installed. Further guidelines on chemical injection accessfittings are elaborated in SP-1033 with flare weld access fittings being the recommendedchoice for ADMA-OPCO.

Chemical Compatibilitv of lniection Locations

The issue of chemical compatibility needs to be addressed. The separation between theinjection points will be dependent on the chemical compatibility and the flow regime. Full

mixing can be expected after 10 pipe diameters along the pipe in a turbulent flow regime, butmay not be achieved at all in laminar flow unless a suitable quill design is used for mixing.

For topside piping and equipment, the minimum separation should be 10 pipe diameters or1m, whichever is greater, even if properly designed injection quills are used. lt should be

noted that the injection point should be on a section made in CRA with the length of CRAsection downstream of the injection point having a distance of 10 times the line diameter.

12.1.7 Inhibitor Type and Indicative Injection Rates

The type of corrosion inhibitor that is used will be dependent on the nature of the fluids (i.e.gas or condensate), the flow velocities and the water content. The dosage rate will bedependent on:

. The corrosivity of the fluids.

. The gas and/or liquid velocities.

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EZ16E= FAGILITIES FOR 4 NEW GAS INJECTORS AND3 BARREN TOWERS IN ZAKUM FIELD


r The inhibited corrosion rate that is required to achieve a specified corrosion allowanceand design life.

. The inhibitor formulation and the concentration of active ingredients in a particularvendor's product.

COMPANY in responsible for chemical selection and usage profile under the contract. Forinjection gas, COMPANY will inject Cl according to existing ZKGIP practices.

It is recommended that the chemical vendor should undertake laboratory testing to select thecorrosion inhibitor, initial dosing rate and compatibility with other chemicals to be used on thisproject.

The modern trend for gas system inhibitors is to use a water soluble / hydrocarbondispersible inhibitor, with high persistence, since the inhibitor is more likely to go with theaqueous phase where it is needed to provide corrosion protection. Typically, the corrosioninhibitor product would be injected into the fluids via an injection atomizer. Dilution of theinhibitor would only be required for particular applications if:

. The inhibitor pumping rates are low (e.9. < 1 litre I day) and these caused problems

with control over dosing rates for a particular type and size of pump.

Dilution is required to assist pumping for a particular chemical product or at a particulartemperature. lt is advised that forthe l0" pipeline (by others), the most appropriate corrosionmitigation method will be intermittent inhibition when the need arises.

12.2 EXTERNAL CORROSION

The philosophy for external corrosion protection of the carbon steel topside piping is basedon the use of suitable panting systems as specified by ADMA-OPCO Painting Manual, MNL-01 whereas the issue of CISCC for SS316L solid piping and equipment at temperaturesabove 60oC shall be overcome similarly with appropriate painting systems described withinMNL-01.

13 CORROSION MANAGEMENT AND PHILOSOPHY

13.1 CORROSION MANAGEMENT PHILOSOPHY AND MONITORING

It is advisable that whenever carbon steels and corrosion allowances / inhibitor are adoptedthat corrosion monitoring and internal inspection are applied. A carefully administrated anddetailed corrosion monitoring programme is recommended for the topside facilities isprovided in AD1 56-447-c-01255.

Corrosion monitoring and management requirement shall comply with ADMA-OPCO STR-002 and BP guidelines, GP 06-10 and GP06-70. The corrosion-monitoring programme shall

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be established to provide the right data and information to the overall integrity managementplan by apportioning the monitoring effort based on threat level to the various assets. Thecorrosion monitoring programme should establish interfaces, key performance indicators(KPl's), and appropriate reporting system and, most importantly, the review period(s). Theabove objective can be achieved by installing proper monitoring equipment at properlocations and collecting / receiving the data at regular intervals.

Corrosion monitoring is required for detecting and evaluating corrosion activity within thetopside piping and subsea gas injection pipeline (by others). lt has the following objectives:

. Optimizing application rate of chemicals used for corrosion control and inspectionintervals as part of a risk-based inspection (RBl) programme and to detect changes in

corrosivity that will invalidate inspection periods or endanger the project facilities,

o Providing early warning of equipment failure from corrosion processes,

. Allowing planning of maintenance procedures to minimize or prevent unscheduledplant shutdown.

13.2 CORROSION MONITORING TECHNIQUES AND EQUIPMENT

Corrosion monitoring is concerned with the combined use of several different techniques forthe gathering of corrosion data. When only a single technique is used, the data will notgenerally provide sufficient information about the corrosion processes to allow reliabledecisions concerning future corrosion control actions. Taken together, the data from severaltechniques will enable corrosion to be assessed concurrently, both for the current level ofcorrosion activity and for accumulated metal losses over specific time periods.

Corrosion monitoring techniques would comprise those used during commissioning, such asROV CP measurements, with the addition of visual and NDT inspections at accessiblerepresentative points, corrosion monitoring ER probes / corrosion weight loss coupons (WLC)and inline inspection by intelligent pigging for the pipeline system and wall thicknessmonitoring for the topside facilities.

Only corrosion monitoring techniques not discussed in AD156-447-G-01255 such ashydrogen probes and wall thickness monitoring via UT-Mats for topside facilities areelaborated below. Access fittings for ER probes and WLC are discussed below.

13.2.1 Access Fittings for Gorrosion Monitoring Equipment

Both corrosion ER probes and WLC are to be installed on high pressure flare weld accessfittings in accordance with SP-1033 and located on an easily accessible area, allowing theuse of extractors for corrosion monitoring of the high pressure pipeline system.

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Document Title :

Revision :

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EZI6E: FACILITIES FOR 4 NEW GAS INJECTORS AND3 BARREN TOWERS IN ZAKUM FIELD

EZ24E= ZADCO UZ75OK WP-3A PROJEGT

All types of probes shall be installed at 6 o'clock position by preference through standard 2

inch access fittings. Sensitive elements should be in the water phase, if any, and preferably

flush- mounted. All access fittings installed at 6 o'clock shall have a sampling point to drain

accumulated solids before retrieving operations.

About 2m of clearance shall be available under the access fitting for the coupon / probe

retrieval. lf there is no sufficient clearance, access fittings shall be installed at the top of the

line but the coupon or probe element shall be flush-mounted in the water phase (about Smm

from the bottom pipe surface) especially when the water height in the line is low which is the

likely case here if water was to be present. Disc coupons are suitable for this purpose.

Local conditions of the corroding material may not be accounted for in any corrosion loss

data transmitted or recorded by probes, unless the devices have first been conditioned to

reflect the material condition at the containment wall. This includes the heat treatment

condition, the applied internal and external material stresses, the material composition,

external local conditions such as fluid velocity and turbulences.

13.2.2 Hydrogen Probes

The main objective of the probe is to monitor the hydrogen diffusion inside the low alloy

material. Such probe can be installed at locations where the diffusion of the hydrogen and

HIC is expected. Hydrogen monitoring measures the flux of hydrogen passing through the

steel piping and vessel walls and correlates this with the general corrosivity and the

possibility of hydrogen-related damage.

There are two basic types of hydrogen probes: "dry" and "wet".

Dry hydrogen probes operate on the internal vacuum pressure of the probe assembly. They

are attached to the pipe or vessel and sealed airtight. The quantity and rate of hydrogen

penetration is measured simply by monitoring the change in pressure on the vacuum gauge

of the probe. The rate of pressure build up can be related to the potential for hydrogen

damage occurring in the vessel or piping.

The wet probe has a cell, which contains an electrolyte, a counter electrode and a reference

electrode. A palladium foil is fixed between the probe and the pipe wall which acts as the

working electrode. The electrolyte in the cell is an oxidizing solution. Using a potentiostat, the

palladium foil is polarised and any atomic hydrogen migrating through the pipe wall into the

cell is oxidized. The current flowing in the cell is directly proportional to the rate of hydrogen

permeation through the wall of the equipment and provides a direct measure of hydrogen

activity. The hydrogen penetration is then measured. This type of cell requires regular

maintenance in the form of electrolyte replenishment and/or renewal.

As a minimum, one probe should be provided at each manifold for each WHT.

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V16E: FACILITIES FOR 4 NEW GAS INJECTORS AND3 BARREN TOWERS IN ZAKUM FIELD


13.2.3 Wall Thickness Monitoring

The use of UT compression wave probes to measure wall thickness is most commonly usedfor inspection purposes to detect and characterize metal loss. Manual methods on topsidepiping are the most common, but automatic systems are also available. The accuracy of themeasurement is approximately 1% of the wall thickness.

Wall thickness measurements are therefore always limited to certain locations as it is

impracticable to inspect a piping system completely. Regular UT check is required on non-piggable areas to ensure effective corrosion monitoring for topside equipment and piping.

Flexible UT-Mats can also be used at locations where installation and operation of intrusivemonitoring systems is difficult due to limited accessibility or high pressures. Sincetemperature limitations placed on UT-Mats is approximately 90oC, it would be applicable andrecommended for this project. UT-Mats are permanently installed in position and measuresthe wall thickness by the pulse-echo technique with the ability to provide on-line data.Flexible UT-Mats should be clamped appropriately and maintained to ensure no loss ofcontact would lead to misleading information on the remaining wall thickness.

13.2.4 Field Signature Methods

The Field Signature Method (FSM) comprises the measurement of the changes in an appliedelectric field within a pipe spool or a vessel wall caused by the loss of material from the innerwall due to internal corrosion. lt is a variation of the electrical resistance method.

The advantage over traditional methods is that non-uniform corrosion can be monitored, butthe detection limit is dependent on pin number and density. This method provides a threedimensional corrosion map with quantitative estimates of the loss in wall thickness across thearea covered by the pin affay. The data is presented graphically in mm/y.

The FSM technology can be used on both piping and vessels and has been used inrefineries. For applications where the maximum surface operating temperature is less than70'C (160'F), a data management module is normally attached directly to the equipment.Output from this module can be read from a remote PC. The same system is available for avessel or a specific area of concern on a vessel.

With the operating conditions being within 70oC (160"F), FSM may be considered. However,it is deemed to be costly for an essentially dry gas system which would probably besubjected to a maximum upset of 14 days/yr. Furthermore, software interpretation can bedifficult and software reliability has been problematic at times. As such, FSM is not deemedto be necessary for this essentially dry gas project.

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EZ24E: ZADCO UZ750KWP-3A PROJECTffi

13.2.5 Summary of Gorrosion Monitoring Options

Based on the COz corrosion rate calculations and MOC recommended along with study on

corrosivity of the particular streams, corrosion control monitoring options for each individual

system has been specified below:

Table 3 Gorrosion Monitorinq Option Based on MOG Selected

Corrosion Circuit MOC Selected Corrosion Monitoring Option

Topsides piping and

manifoldCS + 3mm CA(NACE)

ER probes, corrosion coupons and hydrogen probe monitoring

for CS (NACE) piping in order to meet KPI specified in Table 4.

External Painting to be checked.

Pig LauncherCS + 3mm CA(NACE)

Recommended to keep the facility free of process fluid after

each use.

14 INSPECTION AND MAINTENANCE

14.1 SELECTION OF INSPECTION GRADES FOR EQUIPMENT AND PIPING

CP-107 specifies the inspection grades that should be allocated to the topside piping and

equipment for the Zakum Crestal Gas Injection Project (ZKCGIP). The following are some of

the factors that are to be considered when assessing the lnspection Grade to be allocated forpiping and equipment:

. Severity of service duty and consequence of failure of the item;

. Previous history of similar equipment of similar on similar duties;

. The original standard of design, materials and construction;

. The age of the item and length of time it has been commissioned;

. The optimum utilization of components and materials.


This is the Grade in which all graded equipment should normally be assigned following thepre- commissioning inspection and until the initial thorough inspection is carried out. Asubsequent Grade is then determined thereafter.

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The recommended maximum interval for Grade 0 may be extended when, in the opinion ofthe inspection function, the maturity of the design, the operation conditions and the extent ofquality control during manufacture are sufficient to justify an extension.

14.1.2 Inspection Grade I

This Grade should be applied when the conditions of service are such that:

. Deterioration in whole or part is possible at a relatively rapid rate or at a known meanrate which restricts service life. or

. There is little evidence or knowledge of operational effects on which to predictbehaviour in service.

The inspection interval must be based on a thorough assessment of all relevant factors.



. Deterioration in whole or part has been shown to be at a reasonable and predictablerate, justifying an increased interval, and

. Knowledge of facts or actual behaviour in service is sufficiently reliable to justify an

increased inspection level.



r The item has successfully concluded a service period in Grade 2.

o Deterioration in whole or part has been shown to be at a low and predictable rate, and

. Facts and knowledge of actual service conditions are sufficiently accurate and reliableto justify an increased interval between inspections.

14.2 DATA GOLLECTION AND INSPECTION FREQUENCY

As a start, the data collection frequency can be as recommended in Table 4. However, thefinal data collection frequency should be, based on the Corrosion Management Str:ategy, . ,.

STR-002, and observed corrosion rate.

As per CP-107, the topside piping and equipment should have a pre-commissioninginspection before entering service for the first time and be initially allocated aS Inspection

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EZ24E= ZADCO UZ750K wP-3A PROJECTffi

Grade 0. They shall then be subjected to a first thorough inspection, as per CP-107, afterfollowing a carefully adjudged period of service as per Table 4. Offshore topside piping

systems shall be inspected in accordance with procedures outlined in PRO-107.

Subsequently, after the thorough inspection, the equipment and piping should be allocated tof nspection Grades 1,2 or 3 on the basis of Section 14.1 above by ADMA-OPCO's inspection

and maintenance personnel or observe an extended period as Grade 0 as deemed

necessary.

As an example, the risk to the CS piping after the pipeline and risers may be high as a result

of the higher flow rate observed compared to CS piping after gas flow within is reduced.

Therefore, the monitoring frequency and the number of monitoring points, in the form of

regular UT inspection, needs to be higher for CS piping that is subjected to higher flow rates.

14.3 KEY PERFORMANGE INDICATORS (KPr)

K Pl's as per Table 4 can be used effectively but they should be based on corporate goals ifthey are to have any relevance. These need to be further developed by ADMA-OPCO as part

of Preventive Maintenance Program.

14.4 DATA ASSESSMENT AND CORROSION REPORTING

All data should be assessed by ADMA-OPCO corrosion-engineering specialist, along with the

overall integrity management review team. The level to which information is reported will

depend upon the individual risk level as defined in the integrity management plan and therequisite planning.

For example, failure to meet the KPI at a pipeline CP test point may only result in a report to

technician level but continuing failure to meet the residual inhibitor KPI on the subsea gas

injection pipeline may result in a report to board level.

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Table 4: Recommended Inspection Requirements and KPI

Equipment -ocationInspection

Activity Data Gollected Interval Targeted KPI

Manifold andHeader & all other

CS TopsidesPiping

External

UTW.T.measurement

Remaining WallThickness

Half-yearly forfirst year and

as per CP-107Inspection

Graderequirementthereafter

< 0.1 mm/yr

VisualInspection

CoatingCondition Every 5 years

Without anydefects

HIC likelihood HydrogenProbe Reading

Half-yearly forfirst year and

as per CP-107Inspection

Graderequirementthereafter

Minimalhydrogendiffusion

through thepiping

S53l6UAlloy625 Cold Vent /Drain Drum &Vent Piping

ExternalVisual

inspection CoatingCondition Every 5 years

Without anydefects andabsence of

CISCC

14.5 MAINTENANCE PHILOSOPHY

Maintenance of topside piping and equipment shall be in accordance with ADMA-OPCO

Maintenance Policy Document POL-001. The maintenance strategy shall be in accordance

ADMA-OPCO Maintenance Strategy, STR-001.

Repairs and maintenance on piping and equipment shall not impair the safety level of the

piping system below the specified safety level. All repairs and maintenance shall be carried

out by qualified personnel, in accordance with agreed specifications and procedures. All

repairs shall be tested and inspected by experienced and qualified personnel in accordance

with agreed procedures.

Repairs may be required to a piping system in case of:

. Grooves, gouges, cracks and notches

o Metal loss defects (corrosion, erosion etc)

. Dents

. Leaks -

Piping systems with defects may be operated temporarily under the design conditions or

reduced operational conditions until the defect has been removed or the repair has been

carried out. lt must, however, be documented that the piping integrity and the specified safety

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level is maintained, which may include reduced operational conditions and/or temporaryprecautions. A temporary repair may be accepted until the permanent repair can be carriedout. lf a temporary repair is carried out, it shall be documented that the piping integrity andsafety level is maintained, either by the temporary repair itself and/or in combination withother precautions.

Defects that affect the safety or reliability of the piping system shall either be removed bycutting out the damaged section of the pipe as a cylinder, or alternatively, the system mayhave to be re-qualified to a lower design pressure.

As specified above, all maintenance shall be carried out by qualified personnel, inaccordance with agreed specifications and procedures. No planned maintenance is foreseenfor the ZKCGIP topside piping system. Maintenance is only necessary if the assets cannotfulfil their intended purpose without detriment to the piping system integrity.

Maintenance should be minimized during detailed design phase by the selection ofappropriate equipment and materials based on ADMA-OPCO engineering standards andproject specifications. Where maintenance of piping and equipment components is required,procedures on such maintenance activities should be based on the manufacturer'srecommendation and previous history and performance.

Maintenance activities related to topside piping and equipment as outlined in STR-001 aredistributed to several categories such as:

. Planned maintenance: The maintenance organized and carried out with forethought,control and the use of records to a pre-determined plan. An example of a plannedmaintenance for the topside piping system could be in the form of provision ofcorrosion inhibitor injection quills at ZKGIP for the associated pipeline and topsidepiping systems, which may require intermittent injection of inhibitor during upsets asplanned by the design process during SELECT phase.

r Predictive/Proactive maintenance: This is the maintenance completed as theapplicable type of condition monitoring where data is collected from a functioningmachine from which decisions are made. The output of these decisions could be toraise a corrective work order. This is a non-intrusive type of maintenance, i.e.maintenance that can be completed with the equipment remaining in service. Anexample of proactive maintenance is the frequency of checking/monitoring ofcorrosion coupons and ER probes on the status of corrosion within the gas injectionpipelines coupled with checking/monitoring of hydrogen probes and wall thickness byUT methods for the topside piping. The respective systems are still in service duringsuch checking activities.

. Preventive maintenance: The maintenance carried out at predetermined intervals oraccording to prescribed criteria and intended to reduce the probability of failure or thedegradation of the functioning of an item. This would be the planned Maintenance

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Programs that are used by CMMS. This is an intrusive type of maintenance that wouldnecessitate the removal from service of the equipment. An example of preventivemaintenance could be in the form of sending cleaning pigs or if necessary gaugingpigs to find out the root of problems that have been obtained from proactivemaintenance data received.

Corrective maintenance: The maintenance carried out after fault recognition andintended to put an item into a state in which it can perform a required function.Corrective maintenance is the vehicle by which the effectiveness of the plannedmaintenance is monitored. A better understanding of this type of maintenance can besought in STR-001. An example of a corrective maintenance could be in the form ofincreasing chemical dosage rate for when inhibition for pipeline and topside pipingwhich are found to require higher dosage rates to reduce internal corrosion fromescalating due to upsets.

Reliability Centered Maintenance (RCM): A systematic approach for identifyingeffective and efficient preventive and condition maintenance tasks for equipment anditems in accordance with a specific set of procedures and for establishing the intervalsbetween maintenance tasks.

It should be noted that all maintenance shall be managed by a CMMS as stated in STR-001and POL-001. The applicability of the above maintenance activities is evident throughout theentire topside piping and equipment systems in scope. A combination of planned, proactive,preventive and corrective maintenance is required for ZKCGIP.

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Calcn

NoStream

NoDescription

Pipe OD

(mm)

WallThick(mm)

Inlet OperatingTemp

(oc)

Inlet OperatingPress(psia)

Coz

mol%

(gas)

HzS

mol%

(sas)

H/C Liq

Flow(std

BOPD)

oAPr

Gravity(oil phase)

Vapour Flow(MMscfd)

Water Flow(std BoPD)

Bcn(mm/yd

Lcn(mm/yr)

Tc*(mm/yr)

CASE 1: GGI EXISTING, SUMMER

1 1 GIP COMPRESSOR DISCHARGE 273 39.0 65 5695 2.39 0.1 0.00 150 3.00 o.o2 o.47 0.00

2 2 TO RISER 299 38.5 65 5675 2.39 0.1 0.00 150 3.00 0.02 n27 0.00

CASE 2: GGI EXISTING, WINTER

3 1 GIP COMPRESSOR DISCHARGE 273 39.0 65 5695 2.75 0.15 0.00 150 3.00 o.o2 0.54 0.00

4 2 TO RISER 299 38.s 65 5675 2.75 0.15 0.00 150 3.00 0.02 0.43 0.00

s ll 1 ll GtP COMPRESSOR DTSCHARGE 273 | 39.0 65

CASE 3: 2010 MIXED GAS

150 0.00 10.01 lo.24 lo.oo6 2 TO RISER 299 38.5 65 5675 2.97 0.1 0.00 150 0.00 0.01 0.19 0.00


7 L GIP COMPRESSOR DISCHARGE 273 39.0 65 5695 2.95 0.1 0.00 150 0.00 0.01 o.24 0.00

8 2 TO RISER 299 38.5 65 5675 2.95 0.1 0.00 150 0.00 0.01 0.19 o.oo


9 7 GIP COMPRESSOR DISCHARGE 273 39.0 65 s695 3.04 o.2 0.00 150 0.00 0.01 o.25 0.00

10 2 TO RISER 299 38.s 65 5675 3.04 0.2 0.00 150 0.00 0.01 o.20 0.00

CASE 6:2020 DRY GAS

11 1 GIP COMPRESSOR DISCHARGE 273 39.0 65 5695 3.04 o.2 0.00 150 0.00 0.01 0.2s 0.00

t2 z TO RISER 299 38.s 65 5675 3.04 o.2 0.00 150 0.00 0.01 0.20 0.00

APPENDIX 1: WP3A CORROSION PREDICTION DATA

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