ABU DHABI MARINE OPERATING COMPANY (ADMA-OPCO} EPC WORKS FOR EZ16E: FACIIITIES FOR 4 NEW GAS INJECTORS AND 3 BARREN TOWERS IN ZAKUM FIETD
EZ24E.ZADCO UZ 75OK WP.3A PROJECT
MDR PROJECT NO:
ADMA-OPCO CONTRACT NO: 167188
D6221,
PROJECT
WP3A
FACILITY
ZKGIP
DISCIPLINE
MATERIALS AND CORROSION ENGINEERING
DOCUMENTTYPE
Report
DOCUMENT CTASS
t
ADMA DOCUMENT
NUMBER :
AD156-447-G-OL227
Materials Selection and Corrosion Control Report
DOCUMENTTITLE
I
27-O4-t4
REV.
DATE
PURPOSE
/
DESCRTPTION OF
REVISION
PREPARED
WP3A
\ /^'
$[r
t{rr
ISSUED FOR REVIEW
-
BI
REVIEWED 8Y
'.1\v NV
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QA/QC
PEM
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PROJECT DOCUMENT ARE CONTROLTED DOCUMENTS REV]SIONS ARE DENOTED
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IN THE RIGH HAND MARGIN OF EACH PAGE
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ABU DHAB| MARTNE OPERATTNG COMPANY (ADMA-OPCO) EPC WORKS FOR EZ16E: FACILITIES FOR 4 NEW cAS INJECTORS AND 3 BARREN TOWERS IN ZAKUM FIELD EZ24E= ZADCO UZTSOKWP-3A PROJECT
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a
CHANGE RECORD REVISION
REVISION NO.
DATE
REVTSED SECilON(S)
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REVISION DESCRIPTION
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ABU DHAB| MARTNE OPERATTNG COMPANY (ADMA-OPCO) EPC WORKS FOR EZ16E= FACILITIES FOR 4 NEW GAS INJECTORS AND 3 BARREN TOWERS IN ZAKUM FIELD EZ24E= ZADCO VZ750KWP-3A PROJECT
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HOLDS REGISTER
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ABU DHABI MARINE OPERATING COMPANY (ADMA-OPCO) EPC WORKS FOR EZ16E: FACILITIES FOR 4 NEW GAS INJECTORS AND 3 BARREN TOWERS IN ZAKUM FIELD EZ24E: ZADCO UZ750K WP-3A PROJECT
TABLE OF CONTENTS 4
TABLE OF CONTENTS 1
INTRODUCTION
7
2
PURPOSE
7
3
EXECUTIVE SUMMARY
8
4
SCOPE
10
5
TERMINOLOGY / DEFINITIONS / ABBREVATIONS
11
6
REFERENCED DOCUMENTS
11
6.1
Order of Precedence
11
6.2
Company Standards and Guidelines
12
6.3
lnternational Codes and Standards
12
6.4
Project Documents
12
DESIGN CRITERIA
12
7.1
Design Life
12
7.2
Corrosion conditions
13
7.3
Software
13
7.4
Environ mental Conditions
14
7.5
Fluid Profiles and Compositions
14
CORROSION RISK ASSESSMENTS
14
8.1
General
14
8.2
lnternal Corrosion Prediction
14
8.3
Comparative Effects of COz and HzS
15
8.4
COz Corrosion
17
8.5
HzS Corrosion and Cracking
18
8.6
Under Deposit Corrosion
21
8.7
Condensing Gas Phase Corrosion
21
8.8
Corrosion of CRA Materials
22
8.8.1
Crevice and Pitting Corrosion
22
8.8.2
Resistance to CISCC
23
7
I
8.9
AD156-447-G-OLZ2L
Document No Document Title Revision
23
Oxygen Corrosion
:1
MATERIAL SELECTION AND CORROSION CONTROL REPORT
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ABU DHAB| MARINE OPERATING COMPANY (ADIUIA-OPCO) EPC WORKS FOR EZ16E= FACILITIES FOR 4 NEW GAS INJECTORS AND 3 BARREN TOWERS IN ZAKUM FIELD EZ24E: ZADCO UzTSOKWP-3A PROJECT
8.10
External Corrosion
23
8.11
Other Corrosion Considerations
24
8.12
Sour Service Considerations for Non-Metallic Materials
25
8.13
Liquid Metal Embrittlement - Zinc
26
8.14
Low Temperature Considerations
27
9
MATERIALS SELECTION CRITERIA
27
10
CANDIDATE MATERIALS
29
10.1
Carbon Steel
29
10.2
Ferritic Nickel Steels
30
10.3
Austen itic Stainless Steels
30
10.4
Super Austenitic Stainless Steels
31
10.5
Duplex Stainless Steels
32
10.6
Nickel Based Alloys
32
10.7
CRA Lining / Cladding and Internal coating
34
10.8
Bolting Materials
35
10.9
GRE/FRP
35
MATERIALS SELECTION
36
11.1
Carbon Steel with Corrosion Allowance
36
11.2
Corrosion Rate Predictions
36
11.2.1 Injection Gas
36
11.3
Pig Launcher / Receiver
37
11.4
Corrosion Inhibitor Injection Pump
37
11.5
Material Selection Summary Table
37
11.6
Hydrotest
37
CORROSION INHIBITOR PHILOSOPHY
38
12.1.1 General
38
12.1.2 Inhibitor Effectiveness and Availability
40
12.1.3 Operation and Reliability
41
12.1.4 Chemical Performance
41
12.1.5 Delivery System Design
42
12.1.6 Injection Locations and Equipment
43
12.1.7 Inhibitor Type and Indicative Injection Rates
43
11
12
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ABU DHABT MARTNE OPERATTNG COMPANY (ADMA-OPCO) EPC WORKS FOR EZ16E: FACILITIES FOR 4 NEW GAS INJECTORS AND 3 BARREN TOWERS IN ZAKUM FIELD EZ24E: ZADCO UZTSOKWP-3A PROJECT
12.2
13
External Corrosion
44
CORROSION MANAGEMENT AND PHILOSOPHY
44
13.1 Corrosion Management
Philosophy and Monitoring
44
13.2 Corrosion Monitoring Techniques and Equipment
14
45
13.2.1 Access Fittings for Corrosion Monitoring Equipment
45
13.2.2 Hydrogen Probes
46
13.2.3 Wall Thickness Monitoring
47
13.2.4 Field Signature Methods
47
13.2.5 Summary of Corrosion Monitoring Options
48
INSPECTION AND MAI NTENANCE
48
14.1 Selection of inspection grades for equipment and piping
14.2
48
14.1.1 Inspection Grade 0
48
14.1.2 Inspection Grade
1
49
14.1.3 lnspection Grade 2
49
14.1.4 Inspection Grade
49
3
Data Collection and Inspection Frequency
49
14.3 Key Performance Indicators (kpi)
50
14.4
Data Assessment and Corrosion Reporting
50
14.5
Maintenance Philosophy
51
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ABU DHAB| MARTNE OPERAT|NG COMpANy (ADIJ|A-OPCO) EPC WORKS FOR EZ16E= FACILITIES FOR 4 NEW GAS INJECTORS AND 3 BARREN TOWERS IN ZAKUM FIELD EZ24E= ZADCO UZ750KWP-3A PROJECT
INTRODUCTION
ADMA OPCO intends to achieve additional 100 MBPD Oil productions from Lower Zakum field (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 4 water injector wells. ADMA has awarded, under a single contract, an EPCI scope of work comprising 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-3 compressor discharge header located at ZK-GIP. The injection gas will flow through a 15 km long 12" sub-sea pipeline to the ZK-300 platform via ZK-182 platform designed with through pigging capability launching from ZK-GIP to a receiver located at ZK-300. At ZK-300, the gas received will be injected into the two new gas injector wells drilled from ZK-300 (30 - 80 MMSCFD each well). The gas received at ZK-182 will be injected to the two new gas injectors drilled from this tower (20 - 80 MMSCFD each well). In addition to the above, the 4Gl scope also includes provision of new equipment and piping to be installed on ZK-300 associated with the replacement of an oil transmission subsea pipeline (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 ZKGIP to ZADCO Central lsland is required to export HP treated gas from ZK-GIP which shall be selectively used for gas injection and gas lift in ZADCO artificial islands. Modifications are required at existing ADMA-OPCO GIP platform which includes installation of top side facilities related to new gas injection pipeline (by others) and hook up to existing systems at GIP.
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 Towers 2K114.5174.5, 2K153/61 and Z,K158176. These 3 towers are currently barren and non operational. 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 and finalised during detailed design for WP3A GIP Modifications Project. Under the Contract, CONTRACTOR is required to update the FEED materials and corrosion reports by preparing a Project Specific Material Selection & Corrosion Control Report. However, no FEED document covering WP3A scope is available and the basis and Document
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ABU DHAB| MARTNE OPERATTNG COMPANY (ADMA-OPCO) EPC WORKS FOR EZ16E: FACILITIES FOR 4 NEW GAS INJECTORS AND 3 BARREN TOWERS IN ZAKUM FIELD EZ24E: ZADCO UZ750KWP-3A PROJECT
nnw
philosophies presented in this report have been drawn from FEED documents issued for 4Gl Project
3
EXECUTIVE SUMMARY
The objective of this study is to define materials selection basis and corrosion control philosophies 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 operating life of a facility. The monitoring may also be used to:
.
Verify that the operating parameters are within the design envelope for the topside facilities.
.
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 the project 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 the corrosivity of the environment towards carbon steel, either with or without corrosion inhibitors.
.
The outcome of corrosion monitoring can lead to timely re-assessment and adjustment of the system of corrosion management and optimization of inhibitor dosing.
Document Document
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ABU DHABT MARTNE OPERATTNG COMPANY (ADMA-OPCO) EPC WORKS FOR EZ16E= FACILITIES FOR 4 NEW GAS INJECTORS AND 3 BARREN TOWERS IN ZAKUM FIELD EZ24E= ZADCO UZ750KWP-3A PROJECT
The functional requirement of the corrosion monitoring system is that it should be able to detect 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 for the 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 the field. 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 ADMAOPCO'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 EZ16E: FACILITIES FOR 4 NEW GAS INJECTORS AND 3 BARREN TOWERS IN ZAKUM FIELD EZ24E: ZADCO UZ75OK WP-3A PROJECT
#*ffift
Topsides CRA piping sections do not require any internal corrosion monitoring except for external coating checks for solid SS316L piping which would be subjected to CISCC due to the environmental conditions (>60"C) envisaged for the project. Primary mechanism for corrosion control for topsides carbon steel piping and equipment will be via corrosion inhibitors (during upsets only) and external painting, along with hydrogen probes and regular ultrasonic 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 for monitoring 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 document AD156-447-G-01255.
Table 1 - Summarv of Tooside Material Selected iloc Remarks $ystemsAnalysed Selected
CS+
Topsides Process
3mm (NACE)
Piping
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 for CS (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.
CS+
Pig Launcher / Receiver
3mm CA (NACE)
Cl Pump
SS316L
Recommended to remove process fluid after each use and inert under nitrogen. Piping between pump and injection point is Alloy 625, in accordance with COMPANY reouirement
SCOPE
The objective of this study is to define the philosophy for internal and external corrosion mitigation 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 mechanical equipment along with corrosion management, monitoring, maintenance and inspection methods are also discussed accordingly.
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ABU DHABI MARINE OPERATING COMPANY (ADMA-OPCO) EPC WORKS FOR EZ16E= FACILITIES FOR 4 NEW GAS INJECTORS AND 3 BARREN TOWERS IN ZAKUM FIELD EZ2AEI. ZADCO UZTSOKWP-3A PROJECT
5
TERMTNOLOGY / DEFINITIONS / ABBREVATIONS :
Abu DhabiMarine Operatinq Company American Petroleum I nstitute Bulk Corrosion Rate Bcn Bulk lnhibited Corrosion Rate Brcn Bottom-of-Line BOL Corrosion Allowance CA Corrosion Inhibitor cl Corrosion Monitoring Point CMP Abu Dhabi Marine Operatino Companv (ADMA-OPCO) COMPANY Cathodic Protection CP Corrosion Resistant Allov CRA Carbon Steel CS Chloride Stress Corrosion Cracking cscc Double Block & Bleed DBB McDermott Middle East Inc., - Appointed by the COMPANY to carry out Engineering, Procurement, Fabrication and lnstallation of the EPC CONTMCTOR project. Front End Engineering Design FEED Gas Gatherinq Platform GG II Gas Iniection Platform (ZWSC) GIP Gas Processinq Facilities GPF Hiqh Pressure HP Local Corrosion Rate Lcn Materials of Construction MOC National Association of Corrosion Enqineers NACE Engineering, construction, installation and commissioning works relating to 4 new gas injectors and topsides oil replacement works PROJECT on ZKGIP, ZK-182 and ZK-300 platforms Top-of-Line Corrosion Rate Tcp Upper Zakum UZ Well Head Tower WHT Zakum Central Super Complex ZCSC Zakum ZK REFERENGED DOCUMENTS ADMA or ADMA OPCO API
6 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 EZ16E: FACILITIES FOR 4 NEW GAS INJECTORS AND 3 BARREN TOWERS IN ZAKUM FIELD EZ24E: ZADCO UZ 7 sOR WP-3A PROJECT
L-€J$'
IDFfi
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 TITLE
DOCUMENT GDL-012 MNL-01
sP-1000 STR-OO2
BP GP 36-10
ADMA OPCO Guideline for Matertal Selection ADMA OPCO Paintinq Manual ADMA OPCO Specification for Materialfor Sour Services ADMA OPCO Corrosion Manaqement Manual Guidance of Practice of Metallic Material Selection
INTERNATIONAL CODES AND STANDARDS
6.3
TITLE
DOCUMENT NACE MR0175/tSO15156 NORSOK
M-OO1
Materials for Use in HzS Containing Environments in Oil and Gas Production Materials Selection
PROJECT DOCUMENTS
6.4
DOCUMENT AD156-447-G-01224 AD156-447-D-12001
AD156-447-D-12002 AD156-447-D-12026 AD156-447-G-01255
TITLE Process Desiqn Basis PFD - ZKGIP WP3A MSD - ZKGIP WP3A Heat and Material Balance - WP3A 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
7.1
MOC selected shall be such that they minimize the life cycle cost while maintaining the appropriate level of integrity required.
No : AD156-447-G-OL221 Document Title : MATERIAL SELECTION Revision : 1 Document
AND CORROSION CONTROL REPORT
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ABU DHABI MARTNE OPERATTNG COMPANY (ADMA-OPCO) EPC WORKS FOR EZ'|6E= FACILITIES FOR 4 NEW GAS INJECTORS AND 3 BARREN TOWERS IN ZAKUM FIELD EZ24E= ZADCO UZ750KWP-3A PROJECT
For the carbon steel piping and equipment, a minimum service life of 30 years has been considered. Increased design life may be required for individual items as provided in ITT Job Specifications, refer Section 11.
coRRosroN coNDriloNs
7.2
.
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 and H & MB tables will be used.
Injection of corrosion inhibitor, if necessary, will be considered to be able to achieve an 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 pipeline causing corrosion in the associated topside receiving facilities. Under these circumstances, the topside piping and equipment corrosion assessment philosophy will be conservatively based on normal operating and upset conditions with free water present 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 to predict 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 the 1970s which have been improved and modified with best fit analysis to a large number of flow loop data carried out under controlled conditions. ECE-S recognizes two reactions, one controlled by electrochemical processes at the liquid/metal interface and the other controlled by 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 dependent upon the accuracy and validity of the input data. As such, the ECE-S corrosion software is not a standalone expert system but a tool intended to support expert analysis by the corrosion engineer taking into account all information available, including operational history and maintenance records of similar existing facilities which may be provided by the Operator.
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ABU DHABT MARTNE OPERAT|NG COMPANY (ADMA-OPCO) EPC WORKS FOR EZ16E= FACILITIES FOR 4 NEW GAS INJECTORS AND 3 BARREN TOWERS IN ZAKUM FIELD EZ24E= ZADCO UZ7$OK WP-3A PROJECT
7.4
ENVIRONMENTAL CONDITIONS
The environmentaltemperatures used in the simulation are given below:Ambient air temperature
Min:9"C (48.2"F)
Max:45'C (113'F)
Ambient seawater temperature (at
Min: 17'C (62.6'F)
Max: 36'C (96.8'F)
Am bient seawater tem perature:
Min: 16'C (60.8'F)
Max:36'C (96.8"F)
Mean average summer temperature:
34'C (93.2"F)
Mean average winter temperature:
20"c (68'F)
Maximum temp. of metal exposed to sun:
85'C (185'F)
seabed):
FLUID PROFILES AND COMPOSITIONS
7.5
Fluid profiles and compositions used to generate corrosion rate data are provided Appendices 8
in
1.
CORROSION RISK ASSESSMENTS GENERAL
8.1
Topsides piping and equipment may be subjected to long or short term corrosive attack by either the line product and/or external corrosive media. External corrosion protection is invariably achieved by the application of an external painting system for carbon steels and only necessary for CRAs when operating/environmental temperatures leave them susceptible to chloride induced stress corrosion cracking (CISCC).
Various methods are available to mitigate internal corrosion, depending on the type and severity of anticipated corrosion.
8.2
INTERNAL CORROSION PREDICTION
Internal corrosion may take many forms depending on the fluid composition and process operating conditions. For CS piping and equipment handling process fluids, the most likely form 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 conditions in the sour service region can require precautions against sulphide stress corrosion cracking (SSCC) and hydrogen induced cracking (HlC). Such requirements will generally necessitate specific controls over pipe/plate chemical composition and heat treatment condition and maximum allowable hardness of base material and weldments. Corrosion inhibitor availability of g5% has been considered for lines when/where Cl is present. This is a high value of availability and will require a high standard of inhibitor supply and corrosion monitoring to adjust the flow of inhibitor in the upstream pipeline when applicable. Document Document
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ABU DHABT MARTNE OPERAT|NG COMpANy (ADMA-OPGO) EPC WORKS FOR EZ16E: FACILITIES FOR 4 NEW GAS INJECTORS AND 3 BARREN TOWERS IN ZAKUM FIELD EZ24E: ZADCO UZ750KWP-3A PROJECT
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 construction when specified, is catered to take into account corrosion occurring from both surfaces, external atmospheric (via suitable coatings) and internal process fluids (via corrosion allowance).
To provide an economic solution, vessels made from carbon steel can be metallurgically claded with CRA or internally coated with inorganic coatings supplemented by cathodic protection and internal corrosion allowance, as appropriate. Note that H2S induced cracking of carbon steel piping and/or weldments can take place over a relatively short time at areas where the hardness exceeds the maximum allowed per NACE MR 0175 i.e. Rockwell C22. Considering the presence of HzS in the gas (minimum of 0.1mol% or 1000ppm), coupled with high operating pressure resulting in high partial pressure of HzS in the process streams, NACE MR0175 requirements shall apply accordingly. Therefore, despite the gas injection process streams handling an essentially dry gas, in order to avoid worst case process scenario during process upset conditions, the selected MOC shall 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 of the gases and their respective dissociation constants. The effect of the HzS on the overall corrosion 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 of corrosion, risk of failure and life cycle cost. lgnoring the environmental sensitive cracking aspects of corrosion problems associated with sour 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 through sulphide adsorption and affecting the pH or decrease sweet corrosion through the formation of a protective sulphide scale. The exact interaction of H2S on the anodic dissolution reactions in the presence of COz is not fully understood. For similar conditions, oil and gas installations could experience lower corrosion rates in sour conditions compared to completely sweet systems. This is due to the fact that the acid created by the dissolution of hydrogen sulphide is about 3 times weaker than that of carbonic acids, but HzS gas is about 3 times more soluble in hydrocarbon phase than COz gas. As a result, the effect of both CO2 and H2S gases on lowering the solution pH and potentially increasing corrosion rate are fundamentally the same. ln addition, hydrogen sulphide may play a significant role on the type and properties of the corrosion films, improving or undermining them.
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Literature data on the interaction of H2S and CO2 is still limited since the nature of the interaction is highly complex. The majority of open literature indicates that COz corrosion rate is reduced in the presence of HzS at ambient temperatures. Nevertheless, it must be emphasized that H2S may also form a non-protective layer and that it may catalyse the anodic 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 proved inconclusive, indicating that there is a need to carry out further studies in order to clarify the mechanism. ln spite of the work on H2S corrosion of steels, no equations or models are available to accurately and reliably predict its effect on corrosion, as is the case for CO2 corrosion 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 general metal loss or localized rate expected from CO2 corrosion, or
o
preferentially forming an FeS corrosion product protective than an iron carbonate corrosion product
that is
Decrease the corrosion risk by promoting the formation
less
of an FeS
corrosion product film through either
o
replacing a less protective iron carbonate film, or
o
forming
a
combined protective layer
of iron sulphide and
iron
carbonate
In the presence of both acidic gases, the corrosion process is governed by the dominant acidic gas. The presence of HzS in COz containing producing environments has led to the introduction of COzlH2S ratio which considers three different corrosion domains based on the dominance of corrosion mechanism as affected by the dominating acid gas.
1. CO2/H2S < 20
2.
o
Corrosion dominated by HzS
o
FeS as the main corrosion product.
20 < CO2|H2S < 500
o No : Document Title : Document
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o
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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 sulphide films will be present and the general corrosion rates are therefore driven by the partial pressure of the HzS and for all practical purposes, the COz effect is considered minimal in terms of general corrosion rates since the formation of FeS would reduce CO2 corrosion significantly. The FeS scale, although quite tenacious, is relatively brittle and can spall of at high fluid velocity. The steel areas exposed after spalling will then become anodic to the residual FeS scale and pitting attacks may occur at these bare areas. Accumulation of the scale can accelerate corrosion if water is present.
Where the COz/HzS ratio slightly exceeds 20, corrosion regime can be dominated by either H2S and CO2, r€sulting in mixed corrosion pattern in which the highest localised corrosion rate 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 period
of time it is time dependent and may occur in high velocity or turbulent areas where water is present. The gas composition, as observed from Appendix 1, contains levels of COz ranging from 2.39 mole% to 3.04 mole% for the injection gas under the various cases to be analysed. The system is assumed to be oxygen free (< Sppb oxygen). ECE-S corrosion rate data presented in Appendices 1 take into account COz presence in the fluids 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 results in q9.fe-carbAqlc.gcid,in the,gqyggus phase and reduces the pH, thereby increasing the corrosion rate.
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o
Temperature - Higher temperatures increase reaction kinetics up to the point where a protective scale is formed.
e
Pressure - lf free gas is present, higher pressures increase the partial pressure of CO2, which reduces the pH of the aqueous phase and thereby increases the corrosion rate. lf there is no free gas present, no more CO2 can go into solution as the pressure is increased and therefore pumping a liquid to higher pressure has no effect on the corrosivity of the fluid. MEG / TEG content - The presence of glycol affects the solubility of iron corrosion products in the water phase and can have a significant inhibiting effect on the corrosion rate depending on the weight percent of glycol. Water composition - Produced formation water containing bicarbonate (HCO -; fons can buffer the pH and make the produced water phase less corrosive. Organic acids - The presence of organic acids such as acetate can result in corrosion rates higher than those predicted by traditional COz models.
Flow regime - The flow regime can affect the distribution of the aqueous phase (and corrosion inhibitor), the time of water wetting over which corrosion occurs and the hydrodynamic shear stress at the pipe wall. Flow velocity affects mass transfer of corrosive species to the pipe wall and corrosion products from the pipe wall, and can therefore result in flow-enhanced corrosion or film stripping of corrosion products and corrosion inhibitor.
8.5
H2S CORROSTON AND CRACKTNG
The HzS present in the gas usually helps in reducing the corrosion by formation of iron sulphide film. However, if the film is not perfect and gets damaged, a corrosion cell is formed between 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 valves and areas of lower flow velocities. As such, accumulation of the scale would ultimately accelerate corrosion if water is present during process upsets. The debris would also decrease Cl efficiency because it represents a very large surface area onto which the Cl adsorbs.
The other main problem with the presence of HzS in the gas is the formation of atomic hydrogen due to corrosion reaction causing hydrogen embrittlement that can lead to cracking of ferritic carbon steel materials. Apart from this problem, there are two other problems which
can 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 gas systems. However, cracking in the form of SSCC and hydrogen embrittlement will be a Document DOCument
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problem if the hardness of the material is high, especially the weld areas with wet gas present. The environment conditions under which HIC and SSCC can occur have been defined in NACE MR0175/1SO15156.
The NACE-ISO standard MR0175/1SO15156 provides guidelines for the usage of various materials under conditions that can be described as "sour". Sour service is defined using MR0175 option
1:
.
HzS partial pressure (pHzS) required.
.
H2S partial pressure (pH2S) > 0.3 kPa_a (0.05 psia), SSCC / HIC resistant materials are required.
< 0.3 kPa_a (0.05 psia), no special precautions
are
Considering minimum 1000ppm HzS is expected, service is considered as "severe sour" for service pressures above 1461.4 psia with pH ranging between 3.5 and 4.5 as shown in Figure 1. Since pressures are not expected to be lower than 5000psig, carbon and low alloy steel shall follow NACE MR0175 / 1SO15156 Appendix 2 requirements including limitations on hardness, heat treatment and chemical compositions.
I
i
r-5
E
Fioure 1: Sour Service Limits
It should be noted that material compliance with NACE
/
MRO17S ISO 15156 does not necessarily provide protection against HlC. This sensitivity is related to carbon steel and row alloy steel containing non-metallic sulphide inclusions. The cracking damage in these steels
is very often time dependant and is re-produced by controlled rolling related to the flux of atomic hydrogen generated by the corrosion reactions at the metallic surfaces. Combining of atomic hydrogen into hydrogen gas is a cumulative process and builds up hydrogen gas pressure which eventually leads to HlC. SSCC can be avoided by ensuring the equipment and piping components are fabricated from materials conforming to NACE MR0175/lSO 15156. Conformance would require appropriate
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heat treatment of the steel to lower the material yield strength to less than 620MPa and the hardness to below RC22. The microstructures produced by quenching and tempering of steels have also been found to increase resistance to general corrosion as well as resistance to SSCC.
The susceptibility of carbon steel to HIC can be mitigated by controlling chemical composition, in particular reducing the concentration of MnS inclusions in steel. A reduction in inclusions is usually achieved by lowering the sulphur content of the steel to below 0.003%. Addition of trace elements, such as calcium, to the steel to give residual CalS ratio in the range 2-4 provides shape control of MnS inclusions. Shape control reduces the propensity to HIC because calcium reacts with the MnS to form an inter-metallic sulphide that is not deformed during the forming of vessels. Therefore the spherical shape of the inclusions is retained and they are not rolled into platelets where atomic hydrogen can accumulate forming 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 require HIC testing (subject to Company relaxation by bidder clarification) in accordance with NACE TMO284 ensuring that Crack Length Ratio (CLR), Crack Thickness Ratio (CTR) and Crack Sensitivity 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 the material is very low sulphur and it has been calcium treated for inclusion shaping. HIC testing though is particularly of importance for carbon steel pressure vessels when used for sour service ensuring hardness is kept below 248HV10. Seamless carbon steel piping shall be HIC resistant with similar hardness requirements in place.
When not otherwise qualified by laboratory tests and field experience, corrosion resistant alloys shall follow the requirements and environment limitations given in NACE MR0175 / 1SO15156-3:2009. NACE provides environmental limitations for CRA materials. A typical limitation applicable to NACE compliant austenitic stainless steel for general equipment is:
.
60oC maximum temperature, 1 barg maximum H2S partial pressure, no specific limitation on chloride content and pH.
The compliant austenitic stainless steel shall meet the heat treatment cold work and hardness 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, and no 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 and pitting.
The compliant Duplex Stainless Steel shall meet the heat treatment cold work and hardness requirement 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 sand from the reservoir or corrosion products, settle out in low flow or stagnant areas. The solids themselves can cause preferential corrosion under the deposit (due to the differences in the chemical environment and electrochemical potential under the deposit versus the bulk flow),
can prevent corrosion inhibitor reaching the steel beneath the deposit, can disrupt the formation of protective corrosion product films, or provide a breeding ground for corrosive bacteria.
Under deposit corrosion is most common in carbon steel or lower grade stainless steel systems (such as 304 and 316). Higher grade corrosion resistant alloys such as Alloy 625 are not completely immune, but the instances are rare and of low corrosion rate so CRA systems do not have to follow such rigorous prevention as carbon steel / stainless steel systems.
In all systems, solids should be eliminated from the system where possible, either in upstream separators / slug catchers, or filters. Since the injection gas is treated gas, it is considered that under deposit corrosion is not a credible risk. Where solids are expected to settle and cannot be removed upstream, carbon and stainless steel pipelines should be provided with pigging facilities and be subject to regular cleaning pig 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 top of the pipe (i.e. top-of{he-line corrosion).
Under moisture condensing conditions
in moisture-saturated vapour lines in gas
plants due to temperature gradients across the pipe wall.
The rate of corrosion in wet gas process streams is dependent on the rate of moisture condensation across the pipe wall and the COz partial pressure in the gas. The process gas temperature 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 rate of moisture condensation on the pipe wall. Also, since the liquid has been knocked out from
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ffi
the gas prior to delivery from ZKGIP and the gas behaves as a supercritical fluid at the operating pressure envelope.
8.8 8.8.1
CORROSION OF GRA MATERIALS Grevice and Pitting Corrosion
Stainless steels can be susceptible to pitting corrosion, crevice corrosion and chloride induced 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 the stability of the passive layer. The elements commonly attributed to the stability of the passive layer are chromium (Cr), and molybdenum (Mo). Dissolved nitrogen (atomic) also has an important effect on the resistance to localized corrosion. lt is common to express this resistance 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 with the general aggressiveness of the environment and the temperature. For any given environment, there is a maximum temperature above which pitting corrosion will occur. This temperature is defined as the critical pitting temperature (CPT). Similarly there is a temperature above which crevice corrosion will occur for any given environment called the critical crevice temperature (CCT). The higher the PRE number, the greater the indicated resistance to crevice and pitting corrosion for example 31655 may typically have a minimum specified PRE number of 25, Duplex SS PRE number is 35 while Super Duplex SS has a PRE number of 40.
A comparison of pitting and crevice corrosion resistance for a number of stainless steels
in
the solution annealed condition as measured by ASTM G48 procedures (1oo/o ferric chloride) is given as follows:
Document No Document Title Revision
Type
ccr fc)
cPT fC)
SS316L
-10
10
SS9O4L
12
42
6Mo
38
72
22Cr DSS
13
33
25Cr SDSS
38
78
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Critical temperatures for materials in the as-welded condition would be expected to be slightly lower. Higher critical pitting or crevice corrosion temperatures indicate greater resistance to the initiation of these forms of corrosion. The CPT and CCT of 22o/oCr Duplex Stainless 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 and temperature. lt is fairly commonly accepted that the threshold stress required to produce the phenomenon is quite low and that stresses produced from welding are more than sufficient to cause cracking. Given the difficulty associated with removing the stress from the system, the only way of preventing the phenomenon is to apply the material at service temperatures below the threshold temperature. This threshold temperature is a function of material property, which varies for different types of stainless steel. Corrosion resistant materials like SS 316L and 22o/oCr Duplex SS when required to be used above the threshold temperature, shall be externally protected with suitable coating systems to prevent CISCC at operating temperatures in excess of 60oC for SS 316L and 100oC for 22o/oCr Duplex SS.
8.9
oXYGEN CORROSTON
Hydrocarbon systems are generally oxygen free, but small amounts (parts per billion) of oxygen ingress into a system can have a dramatic effect on corrosion rates and the performance of corrosion inhibitors, particularly in carbon steel systems. This is particularly true of sour systems where oxygen ingress can result in the formation of elemental sulphur resulting in severe pitting.
All systems, irrespective of material, should be designed to minimise oxygen ingress into the system, both directly (from feed streams), but more importantly from secondary streams such as injected production chemicals and even oxygen in the nitrogen purge gas on compressor seals. Chemical handling areas should minimise the exposure of chemicals to air, and pumps should 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 be subject to atmospheric corrosion. Since atmospheric corrosion is an electrolytic process, the presence of water is required. Apart from splashing by sea spray, and wetting by deluge incidents and rainstorms, surfaces can have an adsorbed layer of water if the relative humidity of the surrounding atmosphere is sufficiently high. lt is generally accepted that relative 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 general surface corrosion and possible pitting corrosion External corrosion of offshore facilities arises due to hot humid marine conditions. For the offshore facilities, the corrosion is mainly due to hot humid marine conditions and to rain water exposure. The external corrosion is assumed to be zero on the basis that all exposed coatings will be maintained as required with the recommended painting system as per ADMA-OPCO Technical Standard MNL-01. Insulated systems can be prone to corrosion under insulation (CUl). The susceptibility to CUI is dependent on the temperature range of operation, the age of the coating and the condition of 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 cold burns). Metal mesh cages installed around the system provide the same function, have no risk of CUI and allow access for inspection. GUI can be averted by good insulation practices and proper coating. Properly installed and maintained insulation simply prevents the ingress of large quantities of water. Sometimes, small quantities of water will get through the insulation. Therefore, a high quality immersion grade coating shall be used (underneath the insulation) for equipment operating in the temperature range at which CUI occurs. The details on type of insulation to be used and the coating systems for each material category shall be detailed out in the respective specifications.
For equipment and piping fabricated from Austenitic stainless steel, whenever insulation is used, all insulation materials shall be chloride free (Cl- <10ppm), with similar requirements to be specified in the project insulation specification, as and when applicable.
All corrosion resistant materials under insulation shall be coated with an immersion grade phenolic coating. External corrosion protection of structures, equipment, piping and instruments will be accomplished by the application of protective coatings in accordance with ADMA-OPCO Technical Standard, MNL-01 while external corrosion protection of immersed structures, piping, equipment, etc., shall be achieved by Cathodic Protection complemented by suitable coating in accordance with ADMA-OPCO Technical Standard, MNL-O1.
Following equipment / piping installation, the bare carbon steel vessels / piping shall be internally protected with a temporary corrosion protection treatment which may be nitrogen filling, vapour corrosion inhibitor treatment or desiccant bag installation.
8.11
OTHERCORROSIONCONSIDERATIONS
Apart from above corrosion problems, various other corrosion considerations encountered in the 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 electrically conductive 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 the anodic area, then an accelerated localized corrosion rate can occur.
At dissimilar material connection interface, i.e. at connections between material of different corrosion 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 combination flanges 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. External galvanic corrosion at a dissimilar metal junction requires continuous monitoring to ensure external coating, insulation gaskets, sleeves and washer. Periodic soundness maintenance should be performed to restore any damaged external coating or insulating material.
of
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, a sacrificial spool. Also, the more noble material can be internally coated close to the connection. 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 a precautionary 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 equipment suppliers and the non-metallic materials suppliers endeavour to select the most appropriate non-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 and temperature but since H2S levels greater than 1000ppm are envisaged, Nitrile rubbers are therefore not deemed suitable for this project. For HzS levels up to 57o mole, FKM "Viton" type fluoroelastomers or Tetrafluoroethylene- propylene copolymer (TFEP) "Aflas" shall be used. Above 5% mole H2S level, EFKM perfluoroelastomers (Chemrez or Kalrez) shall be required. PTFE has excellent H2S resistance. Elastomeric seals shall be tested for resistance to 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 been receiving less of an emphasis due to increasing concerns on hydrogen embrittlement by HIC and SSCC. In cases where LME has occurred, it has been mainly due to zinc embrittlement of austenitic stainless steels. lsolated failures have been attributed to welding in the presence of residues of zinc-rich paint or to the heat treating of welded pipe components that carried splatter of zinc-rich paint. However, most of the reported failures due to zinc embrittlement have involved welding or fire exposure of austenitic stainless steel in contact with galvanized steel components.
In many cases, through-wall cracks cause leaks during hydrostatic testing. Typically, zinc embrittlement cracks contain zinc-rich precipitates on fracture surfaces and at the very end of the crack tip. Cracking is therefore intergranular in nature. Zinc embrittlement is a relatively slow process that is controlled by the rate of zinc diffusion along the austenitic grain boundaries. Zinc combines with nickel and this result in nickel depleted zones adjacent to the grain boundaries. The resulting transformation of face centred cubic (FCC) austenite to body centred cubic (BCC) ferrite in this region is thought to produce not only a suitable diffusion path for zinc but also the necessary stresses for initiating intergranular cracking. Externally applied stresses accelerate cracking by opening prior cracks to liquid metal. Although the melting point of zinc is 42OoC (788oF), no zinc embrittlement has been observed at temperatures below 570oC (1380oF), probably because of phase transformation and diffusion limitations. There is also no evidence that an upper limit exists. In the case of zinc rich paints, only those having metallic zinc powder as a principal component can cause zinc embrittlement of austenitic stainless steels. Paints containing zinc oxides or zinc chromates are not known to have caused zinc embrittlement. Therefore paint formulations used should not contain metallic zinc, because of the possibility of inducing liquid metal embrittlement.
The best approach to the prevention of zinc embrittlement is to avoid or mtntmtze zrnc contamination of austenitic stainless steel components in the first place. ln practice, this means using no galvanized structural steel, such as railings, ladders, walkways, or
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!
corrugated 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 dipped galvanised. Uninsulated austenitic piping placed over galvanised structure should be separated by providing polyethylene sheets to prevent overspray and splatter. Where zinc rich primers are used, care shall be taken to avoid the contamination of austenitic stainless 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, fine grained 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 specified temperature in their material specification, e.g. -45oC for ASTM 4333 Grade 6.
In general, the following material selection guidelines may be used for low temperature components:-
. . o o
9
MDMT > 29oC:
CS
-45oC < MDMT < -29oC:
LTCS
-101oC < MDMT < -45oC:
3.5 Ni
-196oC < MDMT < 101oC:
9Ni
MATERIALS SELECTION CRITERIA
The materials selection criteria are primarily focused on preventing both internal and external corrosion to withstand the process design conditions and to ensure non-contamination of product. 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. Corrosion predictions (both internal and external) are made to estimate the carbon steel corrosion rate for the given process conditions and a corrosion allowance is calculated for the design life. lf this corrosion allowance is small enough to be economically and practically acceptable (for
- 6.0mm), carbon steel is usually adopted. Otherwise, carbon steel with corrosion inhibitor injection will be the next best option to be considered. Depending on life cycle cost analysis, corrosion inhibitor injection is planned for the project pipeline based on the pitting expected due to the high H2S content within the dry gas being delivered. This added on effect of inhibition can be considered to be effective for the topside piping up to the choke valve at the respective WHT. example 1.5
lf the inhibited corrosion allowance required is found to be excessive (> 6mm), alternative corrosion resistant materials will be considered and recommended for use with cost optimization being the governing factor based on technical requirements fulfilled by the selected 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 various corrosion 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. The advantages and disadvantages of each material are considered such that recommendations for 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 materials selection report is to specify carbon steel wherever it is found to be acceptable for the process conditions studied. The dominant position of carbon steel as a material of construction (MOC) is due to an un-matched combination of low material cost and excellent material properties, such as a (relatively) high tensile strength, high modulus, excellent impact resistance and high toughness, its largely isotropic material properties, the absence, in general, of any degradation ("ageing") of material properties over time, cost effective production routes and a reliable way to connect pipes (by welding). Compared to its advantages, there are few drawbacks of carbon-steel that can limit its lifetime. The main integrity problem is internal corrosion as a result of the corrosive condition of the process fluid handled. Other integrity problems are due to external corrosion, where the external coating and cathodic protection have failed to give sufficient external corrosion protection. However, all the above problems can be controlled if a proper Corrosion Management and Maintenance Strategy (CMMS) is adopted and followed. Considering the above, 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 Corrosion Management and Maintenance Strategy.
A corrosion allowance of
1.Smm will generally be selected for all non-corrosive process media 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 unless it 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 a case-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 as per ANSI/ASME B31.3. For temperatures down to -45oC, LTCS (ASTM A333 Grade 6) with impact testing is specified.
10.2
FERRITIC NICKEL STEELS
For low temperature operations below -45oC, ferritic nickel steels are recommended, due to
its 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 minimum corrosion allowance of 1mm.
However, the main problem with these ferritic steels is the fabrication and problem of hardness in the as welded condition, leading to cold cracking and failure. To avoid this problem, post weld heat treatment would be required. Hence, considering the problem of fabrication, welding and cracking, Ferritic-Nickels steels are 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 substantial quantities 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 of other alloying elements. Type 304 and 316 are widely used in the process industry. The Type 300 series alloys are more susceptible to attack from the marine environment (offshore and coastal areas), in the form of chloride induced stress corrosion cracking (CISCC) and external pitting. The same problems can occur with internal process fluids if they contain sufficient amounts of chloride and oxygen.
In comparison between SS304 / SS304L and SS316 / SS316L, the latter has got better resistance 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 stainless steel 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 may not be an acceptable solution to prevent CISCC in high-risk piping systems subject to ADMAOPCO 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 free environments, 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 external CISCC.
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 only be necessary if blowdown requirements deem that the associated piping and equipment would 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 high Molybdenum content makes these steels more resistant to pitting and crevice corrosion than normal stainless steel (300 series). Furthermore, due to its relatively high Nickel content in combination with high levels of Chromium and Molybdenum (6%) and high content of Nitrogen (0.2o/o), these steels have high mechanical strength, high ductility and impact strength as well as good weldability.
These steels also satisfy the NACE requirements by passing both the Sulphide Stress Corrosion 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:
UNS
Gommercial
No.
Grade
c
Mn
Si
Cr
Ni
Avesta 254 SMO
1.0
1.0
19.5-
17.5-
s31254
0.020
(max)
(max)
20.5
18.5
19.0-
23.0-
N08904
SS 9O4L
0.020
(max)
23.0
28.0
2.0 1.0
Mo
0.1
6.0-6.5
Others
N
8-
0.22
Cu
0.1
4.0-5.0 (max)
Cu
Hence, Super Austenitic Stainless can be considered as an alternative MOC; however, its cost 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 of 50 - 50 blend, of both Austenitic and Ferritic structure. The combination of these two phases results in capturing the best mechanical and corrosion resistance properties for each phase. Duplex Stainless Steel has significantly better chloride (CISCC) resistance than normal 300 series 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 good formability and are being used for highly corrosive lines. Examples of the Duplex Stainless Steels are as follows:
Commercial
UNS No.
c
Grade SANDVIK SAF 2205
s31803
0.020
Mn
Si
1.0
1.0
(max)
(max)
Cr 22.5
Ni
5-6.07
Mo
N
3.5
0.05
Others
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 should be specified. Even though most of the design codes permit use of DSS materials up to 250'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 suitable epoxy 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 solid soluble 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 harsh environments at high temperatures. Nickel-chromium alloys or alloys that contain more than about 1So/oCr are used to provide both oxidation and carburization resistance at temperatures exceeding 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. The corrosive 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 Inconel 625 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 low temperature applications as identified in Section 8.14. In mild environments such as the atmosphere, fresh and sea water, neutral salts and alkaline media, there is almost no corrosion attack. In more severe environments, the combination of nickel and chromium provides resistance to oxidizing chemicals, whereas the high nickel and molybdenum contents supply resistance to non-oxidizing environments.
The high molybdenum content also makes this alloy very resistant to pitting and crevice corrosion, as mentioned in Section 8.8.1. The columbium within the alloy acts to stabilize it against sensitization during welding, thereby preventing subsequent intergranular cracking and the high nickel content provides freedom from CISCC.
It is in the resistance of Inconel 625 to intergranular corrosion due to sensitization that the alloy shows outstanding performance. In general, nickel-chromium and nickel-iron-chromium alloys are subject to severe intergranular corrosion in some very aggressive environments if they are heat-treated to produce sensitization. lnconel 625 however shows unusual stability after being welded or when subjected to heat treatments that result in serious sensitization of other nickel-chromium and nickel- iron-chromium alloys. lnconel filler metal 625 is a nickel-chromium-molybdenum product designed for welding lnconel 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 effective materials available to serve the intended purpose of application. Due to the properties mentioned above, such as corrosion resistance, excellent ductility at low temperatures, good weldability with itself and other dissimilar metals and its resistance to low temperature creep effects, lnconel 625 could be selected as an effective transition spool between SS316L piping and CS piping or between adjacent CS piping for venting or purging sections which may be subjected to rapid transition from high to low temperatures. However, electrical isolation should be ensured at such dissimilar metal junctions using insulating flange kits complete with bolt protection such as denso tape and grease for the corresponding carbon steel 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 continuously monitored and maintenance of external coating and insulating material performed when required. UNS
Comrnercial
No.
Grade
N06625
Inconel625
Document No Document Title Revision
c
Mn, Si
s,P
Cr
Fe
Mo
0.01
0.5
20.0-
5.0
(max)
(max)
0.015 (max)
23.0
(max)
8.010.0
Nb+ Ta 3.1
5-
4.15
Otherc
Ti, 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 fluids contained within a thin corrosion resistant barrier while the strength of the vessel is provided by 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 and higher 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 not considered for this offshore facility. lf necessary, only CRA cladded CS will be an acceptable option subject to ADMA-OPCO approval of its use. Therefore, CRA cladded CS shall be metallurgically 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 80oC when carbon steel corrosion allowance is not acceptable (i.e. > 6mm), metallurgically bonded CRA cladding shall be used with SS316L or Inconel 8251625 being the preferred overlaid material instead of considering a solid CRA option. It should however be noted that the price difference between solid CRA and CRA-clad steel vessels or piping decreases with decreasing wall thickness. For vessels and piping with wall thickness less than 10mm-1Smm, solid CRA option should be considered, ensuring the temperature limits specified in the above sections for the particular CRA of choice are adhered to. Amongst the above three materials mentioned, considering the process fluid is more or less oxygen free and service is essentially dry gas except for process upsets, SS316L would be sufficient and economically attractive when compared to the costlier higher Nickel Alloys of Inconel 825 and 625.
Hence, SS316L metallurgically clad pipes are deemed feasible for use in this project if necessary and can be considered as an option for the piping and equipment if inhibited corrosion rates are deemed to be in excess of 6mm for the carbon steel substrate. The use of cladding would also lead to a maintenance-free solution in terms of corrosion mitigation and monitoring. Due to manufacturing limits, piping with diameters less than 4" shall apply solid CRA when carbon steel corrosion allowance is not acceptable (i.e. > 6mm) and CRA clad requirements are only usually considered for piping with diameters > 6" taking into account the price difference 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 wet service where temperature and process conditions are milder thus reducing the requirement of metallic cladding.
/
linings are not possible due to the unwanted maintenance necessary after 3-5 years or due to limitations posed by temperature and pressure, superior
Where organic coatings
quality 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 or low-alloy steel and other selected material shall be in accordance with ADMA-OPCO Technical standard STD-1 26. Bolts screwed into component bodies shall be of a material that is compatible with the body with respect to galling and shall allow disassembly of the component for maintenance, if required. The risk for galvanic corrosion and leakage due to differences in the thermal expansion coefficient shall be considered. Carbon steel and/or low-alloy bolting material shall be hot-dip galvanized or have similar corrosion protection. Hot dip galvanizing of bolting shall be performed in accordance with SP1015. Cadmium plating shall not be used.
10.9
GRE/FRP
Glass Fibre Reinforced Epoxy (GRE) and/or Fibre Reinforced Plastics (FRP) are commonly used for seawater (firewater) service and water lines because of their chemical resistance. However, GRE has limitations in terms of operation and maintenance, due to limited strength, ductility and the need for more elaborate supports. The allowable design temperature range for GRE is -40oC to 95oC and up to 80oC for vinyl ester-based FRP. They should 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 as for handling potable water or firewater systems. Dry GRE/FRP piping should be delivered fireproofed 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, 90/10 CuNi can be recommended as it has good corrosion resistance in stagnant seawater because the copper content gives good antifouling properties. The maximum velocity should be 3.5 m/sec in continuous service.
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11 MATERIALS
11.1
ffi
SELECTION
CARBON STEEL WITH CORROSION ALLOWANCE
CS plus corrosion allowance shall be the default material unless alternatives are fully justified by life cycle analysis, taking into account theoretical corrosion predictions and other key factors.
Corrosion allowance is defined as being extra wall thickness added during design to compensate for any reduction in wall thickness by corrosion (internally/externally) during design 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.);
.
11.2
Expected sensitivity and damage sizing capability of relevant tools monitoring, time to first inspection and planned frequency of inspection;
for
o
Conseguences of sudden leakage, requirements to safety and reliability; and
r
Potential for down-rating (or up-rating) of operating pressure
integrity
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 all cases modeled. The basis for this is there is no or insufficient liquid water to drive wet carbonic acid corrosion, coupled with protection benefit from iron sulphide films which form in the presence of H2S.
For a design life of 30 years, a minimum corrosion allowance of 1 mm would be deemed sufficient for the ZKGIP topside injection gas piping in WG3A scope. However, as identified in SELECT phase and STR-002, a CA of 3mm shall be adopted. This is considered to be more 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 a result 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 requirements to mitigate pitting.
1{.3
PIG LAUNCHER / RECEIVER
The permanent pig launcher to be installed on ZKGIP under WP3A scope is recommended to have 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 safely accommodated 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 inhibitor pump, 447-P-2417, shall be SS316 or SS316L.
11.5
steel. On this basis. corrosion
MATERIAL SELECTION SUMMARY TABLE
String / Piping / Equipment
Materials Selected
Corrosion Control
Remarks
Injection gas piping/headers/manifolds
CS-SOUR + 3mm CA Trim: Alloy 625
Dehydration
protective iron sulphide films
-
all platforms
Cl lniection Pumo
SS316 or SS316L
Pig Launcher / Receivers
CS-SOUR + 3mm CA
Cl Piping
U/S pump: SS316L D/S pump: Alloy 625
,|1.6
corrosion,
assumed CRA Draining/drying/inerting
after use CRA
HYDROTEST
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During hydrostatic testing of the topside facility using seawater, the appropriate chemical inhibition should be added to the test water e.g. bactericide, oxygen scavenger and film forming 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 to ensure that the piping is dry before the gas is allowed to flow. For SS316L piping, seawater shall be avoided and fresh water with chloride concentration less than 30ppm shall be used. lf unavoidable, only potable water with chloride level less than 100ppm shall be used afterwhich the piping system shall be flushed with chloride free water 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, various methods 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 pipe wall and prevent corrosion;
internal coating; non-metallic materials can theoretically be applied to the internal surface of the pipe to prevent the carbonic acid coming into contact with the steel but practical use of internal coating from corrosion prevention point of view is not recommended; use of corrosion resistant alloys either as solid pipes or as cladding layers on carbon steel substrates;
removal of COz gas; processing plants are available which can remove COz and hence prevent the formation of carbonic acid;
.
dehydrate the gas; reduce the water dew point below the minimum operating temperature in the piping such that no free water will be available to initiate carbonic acid corrosion.
Often the most effective techniques are dehydration, cooling and/or continuous/intermittent inhibition (batch inhibition is operationally very onerous). Appropriately, ADMA-OPCO have employed dehydration and cooling at ZKGIP prior to delivery of the sour injection gas to limit corrosion effects. However, it is also advised that intermittent inhibition be recommended as another technique to be applied in ZKCGIP to limit H2S pitting and at the same time reduce mesa corrosion if any during upsets. Internal coating is problematic (see below), alloy
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materials such as Duplex SS can expensive and CO2 removal plants are considered to offer no advantage over the drying facilities already installed at ZKGIP. Hence, for ZKCGIP, intermittent injection of corrosion inhibitor, which is the most practical solution, should be adopted for corrosion control during process upsets when the dehydration system at ZKGIP is not operating at its intended capability. Dew point meters should be installed 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 of water or wet products is detected by the dew point meters installed. The following factors shall be considered during the selection of a corrosion inhibitor:
.
The inhibitor should be subjected to a test programme, which evaluates all relevant factors and ensures that the inhibitor will meet the specified inhibited corrosion rate requirements. The appropriate inhibitor solvent package shall be used (preferably hydrocarbon-based) to minimize the risk of gunking in the system. This generally requires an inhibitor that has been specially formulated to avoid solvent evaporation, gunking in dry gas streams. Relevant factors include simulation of the fluid corrosivity with respect to:
1. CO2 and H2S partial pressures 2.
Temperature
3. Aqueous
o . o
phase compostion
4.
Hydrocrabon/condensate composition
5.
Hydrodynamic shear stress at pipe wall
Chemicalcompatibility with other injection chemicals that will be injected. Review of the effects of the inhibitor on the entire process stream from injection to point of sale or disposal. Provision of initial pipeline filming and determination of long{erm injection rates under various 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 other inhibitors if process conditions change.
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Review of system performance if inhibitor supply fails, including persistency, time for corrosion to start, corrosion rates expected if not inhibited and any areas of high risk.
Effects of major operational changes (new reservoirs, compression, increased flow rates/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 that the concentration of inhibitor is consistent with allowable discharge levels (both current and expected future levels) or sales specifications (e.9. acceptable level in the condensate), 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 in intermittently or predominantly wet process streams to allow the use of carbon steel with an acceptable corrosion allowance, provided the chemicals used and the method of injection can effectively and reliably control the corrosion rate.
The inhibitor effectiveness comprises of the efficiency of the chemical in the process (how much it reduces the native uninhibited corrosion rate when dosed properly), and the reliability of the injection process (how often inhibitor is actually injected and available to inhibit corrosion in the process). For ZKCGIP, the values for the inhibited corrosion rate and inhibitor availability (95% for single injection point) used has been specified.
A list of possible uninhibited
events that could occur
to limit the inhibitor availability is
provided in AD156-447-G-01255 which should be considered in design criteria to achieve the inhibitor availability of 95o/o. The inhibitor availability for ZKCGIP topside facilities is 95% for single point injection, but the corrosion allowance determination shall be based on: Ensuring that the inhibitor chemical selected is able to achieve the specified inhibited corrosion rate irrespective of the corrosivity of the environment.
Ensuring that the dose of chemical is sufficient to be able to achieve this level of protection throughout the system to be protected, and that facilities to check this effectiveness (corrosion monitoring and sample points) are provided at appropriate positions in the process.
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Ensuring that the inhibitor is injected in a manner that the full performance efficiency of the chemical can be achieved throughout the system, by the appropriate location of injection points, and the specification of the proper injection apparatus (i.e. quills / atomizer). Ensuring that the chemical injection system is sufficiently reliable to provide chemical injection for a defined percentage of the design life.
Ensuring that the onsite facilities are equipped with sufficient chemical storage capacity 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 the system, 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 the inhibitor treatment and therefore to the reliability of carbon steel systems. Factors include the quality 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 single injection 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 water phase, 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 to deployment. 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 injection atomizers, design of chemical supply systems, availability of pumps, potential for blockages, provision of alarms, quality of equipment purchased) will dictate the base mechanical reliability of the system, and so have a strong effect on the overall effectiveness of the inhibitor treatment over the life of the field.
Table 2: Griteria for Inhibitor Svstem Desiqn to Meet Specified Svstem Availabilitv nhibitor Availability tem Description
)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 ker performance indicators) to responsible corrosion engineer
Weekly
Quarterly manual check on pump injection rate No flow alarm (zero differential pressure across a critical component, or in line flow meters)
Liquid samples for analysis of residual inhibitor levels and water chemistry
Monthly Response time such that total number of events
Corrosion monitoring system response time
x time to responde is < 4 days/yr
Typical choices for corrosion monitoring equipment and system response times
On-line ER probes, response time t hr to 1 day and 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 a defined period of time
Possibly (for high corrosivity systems)
ldentify Operations Technician with responsibility for
the
inhibition injection system Corrosion Engineering nvolvement I
Weekly review for compliance
Key Performance Indicators set for Operations Technicians and Corrosion Engineers
The determination of the piping corrosion allowance for topsides facilities have been based on the essentially dry nature of the sour gas supplied from ZKGIP. lf for any reason this essentially dry gas becomes wet due to intermittent upsets, the corrosion management system should be designed and operated in service on the basis of an inhibitor availability of 95% due to the concerns of H2S pitting on the CS pipe wall when wet conditions arise. Document No Document Title Revision
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12.1.6 Injection Locations and Equipment Intermittent corrosion inhibitor should be injected into the upstream gas as one of the corrosion control measures. Corrosion inhibitor injection point should be provided at the following 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 chemical injection access fitting (available from Rohrbach Cossasco, Corrocean, Caproco, Cormon or CorTest) such that the inhibitor is injected into the mid-point of the pipe. The chemical injection 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 ensure that the inhibitor will be adequately mixed into the stream. Preferably, the chemical injection points should be installed on the top of the line wherever possible. Only access fittings with welded 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 such connections when inappropriately installed. Further guidelines on chemical injection access fittings are elaborated in SP-1033 with flare weld access fittings being the recommended choice for ADMA-OPCO. Chemical Compatibilitv of lniection Locations
The issue of chemical compatibility needs to be addressed. The separation between the injection 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, but may 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 or 1m, 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 CRA section 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 be dependent on:
.
The corrosivity of the fluids.
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The inhibited corrosion rate that is required to achieve a specified corrosion allowance and design life.
The inhibitor formulation and the concentration of active ingredients in a particular vendor's product.
COMPANY in responsible for chemical selection and usage profile under the contract. For injection gas, COMPANY will inject Cl according to existing ZKGIP practices. It is recommended that the chemical vendor should undertake laboratory testing to select the corrosion inhibitor, initial dosing rate and compatibility with other chemicals to be used on this project.
The modern trend for gas system inhibitors is to use a water soluble
/
hydrocarbon dispersible inhibitor, with high persistence, since the inhibitor is more likely to go with the aqueous phase where it is needed to provide corrosion protection. Typically, the corrosion inhibitor product would be injected into the fluids via an injection atomizer. Dilution of the inhibitor 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 particular temperature. lt is advised that forthe l0" pipeline (by others), the most appropriate corrosion mitigation 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 based on the use of suitable panting systems as specified by ADMA-OPCO Painting Manual, MNL01 whereas the issue of CISCC for SS316L solid piping and equipment at temperatures above 60oC shall be overcome similarly with appropriate painting systems described within MNL-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 adopted that corrosion monitoring and internal inspection are applied. A carefully administrated and detailed corrosion monitoring programme is recommended for the topside facilities is provided in AD1 56-447-c-01255. Corrosion monitoring and management requirement shall comply with ADMA-OPCO STR002 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 management plan by apportioning the monitoring effort based on threat level to the various assets. The corrosion monitoring programme should establish interfaces, key performance indicators (KPl's), and appropriate reporting system and, most importantly, the review period(s). The above objective can be achieved by installing proper monitoring equipment at proper locations and collecting / receiving the data at regular intervals. Corrosion monitoring is required for detecting and evaluating corrosion activity within the topside piping and subsea gas injection pipeline (by others). lt has the following objectives:
.
Optimizing application rate of chemicals used for corrosion control and inspection intervals 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 unscheduled plant shutdown.
13.2
CORROSION MONITORING TECHNIQUES AND EQUIPMENT
Corrosion monitoring is concerned with the combined use of several different techniques for the gathering of corrosion data. When only a single technique is used, the data will not generally provide sufficient information about the corrosion processes to allow reliable decisions concerning future corrosion control actions. Taken together, the data from several techniques will enable corrosion to be assessed concurrently, both for the current level of corrosion activity and for accumulated metal losses over specific time periods. Corrosion monitoring techniques would comprise those used during commissioning, such as ROV CP measurements, with the addition of visual and NDT inspections at accessible representative points, corrosion monitoring ER probes / corrosion weight loss coupons (WLC) and inline inspection by intelligent pigging for the pipeline system and wall thickness monitoring for the topside facilities.
Only corrosion monitoring techniques not discussed in AD156-447-G-01255 such as hydrogen probes and wall thickness monitoring via UT-Mats for topside facilities are elaborated 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 access fittings in accordance with SP-1033 and located on an easily accessible area, allowing the use of extractors for corrosion monitoring of the high pressure pipeline system.
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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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13.2.3 Wall Thickness Monitoring The use of UT compression wave probes to measure wall thickness is most commonly used for inspection purposes to detect and characterize metal loss. Manual methods on topside piping are the most common, but automatic systems are also available. The accuracy of the measurement 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 nonpiggable 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 intrusive monitoring systems is difficult due to limited accessibility or high pressures. Since temperature limitations placed on UT-Mats is approximately 90oC, it would be applicable and recommended for this project. UT-Mats are permanently installed in position and measures the 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 of contact 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 applied electric field within a pipe spool or a vessel wall caused by the loss of material from the inner wall 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, but the detection limit is dependent on pin number and density. This method provides a three dimensional corrosion map with quantitative estimates of the loss in wall thickness across the area 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 in refineries. For applications where the maximum surface operating temperature is less than 70'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 a vessel 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 be subjected to a maximum upset of 14 days/yr. Furthermore, software interpretation can be difficult and software reliability has been problematic at times. As such, FSM is not deemed to be necessary for this essentially dry gas project.
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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
Topsides piping and manifold
14
CS + 3mm
CA
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.
(NACE)
CS + 3mm
Pig Launcher
Corrosion Monitoring Option
MOC Selected
CA
(NACE)
Recommended each use.
to keep the facility free of process fluid after
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 for piping 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.
14.1.1
Inspection Grade 0
This is the Grade in which all graded equipment should normally be assigned following the pre- commissioning inspection and until the initial thorough inspection is carried out. A subsequent Grade is then determined thereafter.
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The recommended maximum interval for Grade 0 may be extended when, in the opinion of the inspection function, the maturity of the design, the operation conditions and the extent of quality 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 mean rate which restricts service life. or
.
There is little evidence or knowledge of operational effects on which to predict behaviour in service.
The inspection interval must be based on a thorough assessment of all relevant factors.
14.1.3 Inspection Grade
2
This Grade should be applied when the conditions of service are such that:
.
Deterioration in whole or part has been shown to be at a reasonable and predictable rate, justifying an increased interval, and
.
Knowledge of facts or actual behaviour in service is sufficiently reliable to justify an increased inspection level.
14.1.4 Inspection Grade 3 This Grade should be applied when the conditions of service are such that:
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
. 14.2
Facts and knowledge of actual service conditions are sufficiently accurate and reliable to justify an increased interval between inspections.
DATA GOLLECTION AND INSPECTION FREQUENCY
As a start, the data collection frequency can be as recommended in Table 4. However, the final 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-commissioning inspection before entering service for the first time and be initially allocated aS Inspection
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Grade 0. They shall then be subjected to a first thorough inspection, as per CP-107, after following 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 to f 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 if they 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 the requisite 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 Inspection
Equipment
-ocation
Activity
UTW.T. measurement
Manifold and Header & all other CS Topsides Piping
Data Gollected
Interval
Remaining Wall Thickness
Half-yearly for first year and as per CP-107 Inspection Grade requirement
External
Visual Inspection
Coating Condition
Hydrogen Probe Reading
Every 5 years Half-yearly for first year and as per CP-107 Inspection Grade requirement
thereafter
14.5
Without any defects
Minimal hydrogen diffusion through the piping
Without any
S53l6UAlloy Drain Drum & Vent Piping
< 0.1 mm/yr
thereafter
HIC likelihood
625 Cold Vent /
Targeted KPI
External
Visual inspection
Coating Condition
Every 5 years
defects and absence of CISCC
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 DocumentNo ;-=1ai55447:G-OL2.zLDocument
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level is maintained, which may include reduced operational conditions and/or temporary precautions. A temporary repair may be accepted until the permanent repair can be carried out. lf a temporary repair is carried out, it shall be documented that the piping integrity and safety level is maintained, either by the temporary repair itself and/or in combination with other precautions.
Defects that affect the safety or reliability of the piping system shall either be removed by cutting out the damaged section of the pipe as a cylinder, or alternatively, the system may have to be re-qualified to a lower design pressure.
As specified above, all maintenance shall be carried out by qualified personnel,
in
accordance with agreed specifications and procedures. No planned maintenance is foreseen for the ZKCGIP topside piping system. Maintenance is only necessary if the assets cannot fulfil their intended purpose without detriment to the piping system integrity.
Maintenance should be minimized during detailed design phase by the selection of appropriate equipment and materials based on ADMA-OPCO engineering standards and project specifications. Where maintenance of piping and equipment components is required, procedures on such maintenance activities should be based on the manufacturer's recommendation and previous history and performance.
Maintenance activities related to topside piping and equipment as outlined in STR-001 are distributed to several categories such as:
.
r
.
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 planned maintenance for the topside piping system could be in the form of provision of corrosion inhibitor injection quills at ZKGIP for the associated pipeline and topside piping systems, which may require intermittent injection of inhibitor during upsets as planned by the design process during SELECT phase.
Predictive/Proactive maintenance: This is the maintenance completed as the applicable type of condition monitoring where data is collected from a functioning machine from which decisions are made. The output of these decisions could be to raise 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. An example of proactive maintenance is the frequency of checking/monitoring of corrosion coupons and ER probes on the status of corrosion within the gas injection pipelines coupled with checking/monitoring of hydrogen probes and wall thickness by UT methods for the topside piping. The respective systems are still in service during such checking activities. Preventive maintenance: The maintenance carried out at predetermined intervals or according to prescribed criteria and intended to reduce the probability of failure or the degradation of the functioning of an item. This would be the planned Maintenance
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ABU DHABT MARTNE OPERATTNG COMpANy (ADMA-OPCO) EPC WORKS FOR EZ16E= FACILITIES FOR 4 NEW GAS INJECTORS AND 3 BARREN TOWERS IN ZAKUM FIELD EZ24E: ZADCO UZTSOKWP-3A PROJECT
Programs that are used by CMMS. This is an intrusive type of maintenance that would necessitate the removal from service of the equipment. An example of preventive maintenance could be in the form of sending cleaning pigs or if necessary gauging pigs to find out the root of problems that have been obtained from proactive maintenance data received.
Corrective maintenance: The maintenance carried out after fault recognition and intended 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 planned maintenance is monitored. A better understanding of this type of maintenance can be sought in STR-001. An example of a corrective maintenance could be in the form of increasing chemical dosage rate for when inhibition for pipeline and topside piping which are found to require higher dosage rates to reduce internal corrosion from escalating due to upsets. Reliability Centered Maintenance (RCM): A systematic approach for identifying effective and efficient preventive and condition maintenance tasks for equipment and items in accordance with a specific set of procedures and for establishing the intervals between maintenance tasks.
It should be noted that all maintenance shall be managed by a CMMS as stated in STR-001 and POL-001. The applicability of the above maintenance activities is evident throughout the entire topside piping and equipment systems in scope. A combination of planned, proactive, preventive and corrective maintenance is required for ZKCGIP.
Document No Document Title Revision
ADr56-447-G-O122L MATERIAL SELECTION AND CORROSION CONTROL REPORT
1
- WP3A
Page 53 of54
APPENDIX 1: WP3A CORROSION PREDICTION DATA
Calcn
Stream
No
No
Description
Pipe OD
(mm)
Wall
Inlet Operating
Inlet Operating
Thick
Temp
Press
(mm)
(oc)
(psia)
Coz
HzS
mol
mol
%
%
H/C Liq Flow (std
(gas)
(sas)
BOPD)
oAPr
Gravity (oil phase)
Vapour Flow (MMscfd)
Water Flow (std BoPD)
Bcn
Lcn
Tc*
(mm/yd
(mm/yr)
(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
150
0.00
CASE 3: 2010 MIXED GAS
s
ll
1
ll
GtP COMPRESSOR DTSCHARGE
273
|
39.0
65
38.5
65
6
2
TO RISER
299
7
L
GIP COMPRESSOR DISCHARGE
273
39.0
65
5695
8
2
TO RISER
299
38.5
65
5675
5675
2.97
10.01
lo.24
lo.oo
0.1
0.00
150
0.00
0.01
0.19
0.00
2.95
0.1
0.00
150
0.00
0.01
o.24
0.00
2.95
0.1
0.00
150
0.00
0.01
0.19
o.oo
CASE 4: 2015 MIXED GAS
CASE 5: 2020 MIXED GAS
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
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
CASE
Page
3t
of 54
6:2020
DRY GAS
