Petroleum Development Oman LLC
Revision: 0
Effective: September-2014
Petroleum Development Oman L.L.C.
Materials Selection & Corrosion Control for Surface Operating
Process Facilities
Document ID SP-2161
Document Type Specification
Security Restricted
Discipline Materials & Corrosion
Owner UEOC
Issue Date September 2014
Version 0
Keywords: This document is the property of Petroleum Development Oman, LLC. Neither the whole
nor any part of this document may be disclosed to others or reproduced, stored in a retrieval system,
or transmitted in any form by any means (electronic, mechanical, reprographic recording or
otherwise) without prior written consent of the owner.
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Approval and Issue Record
Date
Description
(see Revision Record for
details)
Author
(name)
Approved
(name)
September-14
Original issue under PDO
SP-2161
Pedro Rincon
Steve Jones
Janardhan Saithala
Cheng Ai Khoo
Nasser Behlani
Issu
e No
1
Revision Record
Issue No
0
Description of Revision
Original Issue under PDO SP-2161
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Table of Contents
1
INTRODUCTION...................................................................................................................................... 6
1.1
1.2
1.3
1.4
1.5
1.6
PURPOSE .............................................................................................................................. 6
SCOPE................................................................................................................................... 6
SPECIFICATION OWNERS RESPONSIBILITY............................................................................. 7
REVISION AND CHANGES TO THE DOCUMENT ....................................................................... 7
DEFINITION OF TERMS.......................................................................................................... 7
ABBREVIATIONS & ACRONYMS ........................................................................................... 8
2
HIERARCHY OF STANDARDS ........................................................................................................... 10
3
MATERIALS SELECTION PROCESS ................................................................................................ 11
3.1
3.2
3.2.1
3.2.2
3.2.3
4
MATERIALS SELECTION METHODOLOGY ................................................................................. 14
4.1
4.2
4.3
4.3.1
4.4
4.5
4.6
4.7
5
GENERAL ........................................................................................................................... 11
TECHNICAL INTEGRITY ASPECTS ........................................................................................ 11
Health safety and environment .......................................................................................... 11
Sustainable development ................................................................................................... 11
Philosophy ......................................................................................................................... 11
INFORMATION REQUIREMENTS FOR MATERIALS SELECTION STUDY.................................. 15
DELIVERABLES OF MATERIALS SELECTION IN VARIOUS PROJECT PHASES ........................... 17
FACTORS AFFECTING MATERIALS SELECTION .................................................................... 25
Information required and review of factors affecting materials selection ......................... 25
APPLICATION OF CARBON STEELS....................................................................................... 25
DEGRADATION MECHANISMS ............................................................................................. 25
ECONOMIC ASPECTS OF MATERIALS SELECTION ................................................................. 30
NON- OPERATIONAL CONSIDERATIONS ............................................................................... 30
GENERAL MATERIALS DESCRIPTION AND SPECIFIC REQUIREMENTS ........................... 31
5.1
GENERAL REQUIREMENTS FOR SPECIFIC MATERIALS GROUP ............................................ 31
5.1.1
Sour service ....................................................................................................................... 31
Alloy UNS N0625 ....................................................................................................................................... 33
5.2
SPECIFIC REQUIREMENTS.................................................................................................... 34
5.2.1
Metallurgically bonded clad plates ................................................................................... 34
5.2.2
Welding including clad and overlay equipment ................................................................ 34
5.3
PROTECTION AGAINST CATASTROPHIC FAILURE MECHANISMS ........................................... 34
5.3.1
Chloride stress corrosion cracking ................................................................................... 35
5.4
PROTECTION OF STAINLESS STEELS FOR CORROSION UNDER INSULATION (CUI) WITH
35
ALUMINIUM.
5.5
SEALING MATERIALS .......................................................................................................... 35
5.6
AMENDMENTS TO ISO 15156 ............................................................................................. 35
6
MATERIALS SELECTION BY EQUIPMENT SYSTEMS................................................................ 37
6.1
6.1.1
6.2
6.3
6.4
6.5
6.5.1
6.5.2
6.5.3
6.5.4
6.6
6.7
6.8
INTRODUCTION ............................................................................................................. 37
General .............................................................................................................................. 37
VESSELS AND PIPING .......................................................................................................... 37
PIPING, FITTINGS VALVES AND OTHER COMPONENTS.......................................................... 40
SMALL BORE INSTRUMENT, HYDRAULIC AND CHEMICAL INJECTION TUBING ...................... 40
HEAT EXCHANGERS ............................................................................................................ 40
Shell-and-tube heat exchangers......................................................................................... 40
Plate coolers ...................................................................................................................... 42
Air cooled heat exchangers ............................................................................................... 43
Compact coolers (printed circuit heat exchangers)........................................................... 44
GLYCOL DEHYDRATION SYSTEM ........................................................................................ 44
FLARE & RELIEF SYSTEMS .................................................................................................. 44
ROTATING EQUIPMENT ....................................................................................................... 44
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A)
6.9
6.10
6.11
6.12
6.13
6.14
6.15
6.16
6.17
6.18
6.19
6.20
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COMPRESSORS FOR PDO SHALL BE DESIGNED FOR SOUR SERVICE. .................................... 44
PUMPS ................................................................................................................................ 44
BOLTING ............................................................................................................................ 45
ELASTOMER SEAL SELECTION ............................................................................................ 45
PIPELINES ........................................................................................................................... 45
DRY HYDROCARBON FLOW LINES: ..................................................................................... 47
FLOWLINES ........................................................................................................................ 47
WATER INJECTION FLOW LINES .......................................................................................... 49
FLEXIBLES .......................................................................................................................... 49
MULTI SELECTIVE VALVES (MSV’S) ................................................................................ 49
UTILITIES ........................................................................................................................... 50
STEAM INJECTION SYSTEMS ............................................................................................... 50
ENHANCED OIL RECOVERY (EOR) ............................................................................ 50
7
MATERIALS SELECTION STUDY ROLES & RESPONSIBILITIES ............................................ 51
8
CONTENT OF MATERIALS SELECTION REPORTS .................................................................... 51
8.1
8.2
8.3
9
SELECT PHASE ................................................................................................................. 51
DEFINE PHASE ................................................................................................................. 51
EXECUTE PHASE ............................................................................................................. 52
CORROSION MANAGEMENT FRAMEWORK ............................................................................... 52
APPENDIX A: BASIC INFORMATION REQUIRED AND FACTORS EFFECTING MATERIALS
SELECTION .................................................................................................................... 53
APPENDIX B: RISK ASSESSMENT ............................................................................................................. 56
APPENDIX C: CMF TEMPLATE .................................................................................................................. 58
APPENDIX D: FEED AND DETAILED DESIGN MSR MINIMUM STANDARD REQUIREMENTS
TEMPLATE..................................................................................................................... 59
APPENDIX E: TEMPLATE FOR REQUIRED PROCESS INFORMATION IN MATERIALS
SELECTION REPORT. ................................................................................................. 62
APPENDIX F: MATERIALS SELECTION DIAGRAMS (MSD) ............................................................... 63
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Introduction
1.1
Purpose
The document provides the requirements on the process of materials selection and corrosion control
for surface equipment that shall be used during project life cycle to ensure technically proven and
economically acceptable materials selection for PDO projects. This specification also addresses
some of the roles and responsibilities of projects, function, designers, contractors and vendors to
ensure materials are designed, manufactured, procured and constructed to meet Company specified
technical requirements within agreed delivery timeframe.
The objective of this document is to achieve designs where materials are selected to maximise the
likelihood of no loss of containment for the design life at lowest life cycle cost by:
1.
2.
3.
4.
Ensuring acceptable corrosion rate at lowest life cycle costs
Minimise corrosion by using resistant materials as the primary barrier
Design not to use chemical treatment as a barrier for on plot facilities
Design to ensure at least one primary barrier or two secondary barriers (e.g. CRA or
corrosion inhibitor and corrosion allowance)
Materials selection and corrosion control are elements of corrosion management, and this guideline
develops further clarification and interpretation of CP-208 Corrosion Management Code of Practice
and DCAF requirements.
This Specification is intended for use by Petroleum Development Oman LLC (PDO), its
Contactors/Subcontractors and Design Consultants and vendors for all PDO equipment and facilities.
This specification covers all surface equipment from the connecting flanges to the Christmas tree.
“If you are reading a hard copy of this standard, you should consider it uncontrolled and refer
instead to the version currently on the PDO intranet live link or appropriate search database.”
1.2
Scope
The scope of this specification is to cover the surface facility materials selection for different phases
of the project from identify to operate phase.
This specification shall be read in conjunction with other Company, Shell and International standards
such as DEP 39.01.10.11-Gen, 39.01.10.12-Gen and DEP.30.10.02.15 . This document provides
further requirements on other company specifications (SPs), Shell DEPs and MESC SPEs and
International Standards for materials selection process and requirements.
In case of any conflict between this specification and other standards, this specification shall take
precedence.
This standard defined the minimum Company requirements for selecting materials of construction
and corrosion control measures to support the corrosion management strategy for a facility within the
company. It addresses requirement for identifying and evaluating all applicable corrosion threats,
materials deterioration mechanisms, selecting optimum materials of construction, corrosion control
measures and appropriate corrosion monitoring measures and the data necessary to ensure the
requirements of this standard are effectively implemented.
This standard does not cover downhole materials selection requirements. For downhole materials
selection, refer to DEP 39.01.10.02-Gen, DEP 30.10.02.15-Gen and WS 38.80.31.31-Gen.
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1.3
Specification owners responsibility
The owner of this specification, UEOC, as CFDH Materials and Corrosion, is responsible for
authorising all proposed deviations or amendments to the specification and for the instigation of
periodic reviews and updates in accordance with Clauses 1.2 and 1.5.
The requirements of this specification shall remain in force indefinitely unless superseded by an
authorized revision.
The range of business areas and various life cycle stages of projects to which this standard applies
as below:
All PDO Development/Projects
Business Segment
Stage
1.4
Upstream
Identify
Assess
Select
Define
Execute
Operate
√
√
√
√
√
√
Revision and changes to the document
This specification will be reviewed and updated as and when required. The review authority will be
UEOC, (CFDH Materials and Corrosion).
1.5
Definition of Terms
Company
The term Company shall refer to Petroleum Development Oman L.L.C.
Contractor
The party which carries out all or part of the design, engineering,
procurement, construction, commissioning or management of a project, or
operation or maintenance of a facility.
Shall
The word 'shall' used throughout this specification indicates a Contract
requirement.
Should
UEOC
Sour Service
The word 'should' used throughout this specification indicates a
recommendation.
Technical Authority Level 1 (TA-1) for Materials, corrosion and integrity
discipline appointed by the Technical Director (TA0).
As stipulated in SP-2041
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1.6
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Abbreviations & Acronyms
Term
Definition
AC
Atmospheric Corrosion
ALARP
As Low As Reasonably Practicable
BfD
Basis for Design
CAPEX
Capital Expenditure
CE
Carbon Equivalent
CFDH
Corporate Function Discipline Head
CMF
Corrosion Management Framework
CORRAT
Shell proprietary corrosion modelling computer program for corrosion
rate: for calculating single point calculation corrosion rates (the most
basic option in HYDROCOR)
CP
Cathodic Protection
CRA
Corrosion Resistant Alloy
CS
Carbon Steel
CSCC
Chloride Stress Corrosion Cracking
CUI
Corrosion Under Insulation
DEP
Design Engineering practice
EFC
European Federation of Corrosion
FEED
Front End Engineering Design
FMEA
Failure Modes and Effects Analysis
GRP
Glass Reinforced Plastic (fibreglass). Also known as Fibre Reinforced
Plastic (FRP) (fibre reinforced plastic) or Glass Reinforced Epoxy
(GRE) (glass reinforced epoxy)
HE
Hydrogen Embrittlement
HEMP
Hazards and Effect Management Process
HIC
Hydrogen Induced Cracking. Also known as SWC
HRC
Rockwell Hardness
HSE
Health Safety Environments
HV
Vickers Hardness
HYDROCOR
Shell proprietary corrosion modelling Shell computer program for
calculating corrosion rates
HRC
Rockwell Hardness
MatHelp
Shell proprietary system for accessing materials and corrosion
information
MCI
Materials, Corrosion and Inspection
MDMT
Minimum Design Metal Temperature
NACE
National Association of Corrosion Engineers
OCTG
Oil Country Tubular Goods
OPEX
Operating Expenditure
OPMG
Opportunity and Project Management Guide
OR&A
Operations, Readiness & Assurance
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Term
Definition
PDO
Petroleum Development Oman
PFP
Passive Fire Protection
PTE
Principal Technical Expert
PWC
Preferential Weld Corrosion
RAM
Risk Assessment Matrix
S-RBI
Shell Risk Based Inspection (methodology)
SCC
Stress Corrosion Cracking
SLC
Service Life Corrosion - (total estimated wall thickness reduction of
carbon steel over the life of a project the equipment)
SME
Subject Matter Expert
SOHIC
Stress Oriented Hydrogen Induced Cracking
SSC
Sulphide Stress Cracking
SWC
Step Wise Cracking. Also known as HIC
TOL
Top Of Line
WPS
Welding Procedure Specification
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2
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HIERARCHY OF STANDARDS
1.
2.
3.
PDO Standards
•
SP-2161 (2014): Materials Selection and Corrosion Control for Surface Operating
Process
•
SP-2041(2014): Selection of Cracking Resistant Materials for H2S-Containing
Environment
•
SP-1246: Specification for Painting and Coating of Oil and Gas Production Facilities
•
SP-2156 - Specification for use of non metallic materials in PDO
DEPs
•
DEP 39.01.10.11-Gen: Selection Of Materials for Life Cycle Performance
(Upstream Facilities) - Materials Selection Process
•
DEP 39.01.10.12-Gen: Selection of Materials for Life Cycle Performance (Upstream
Facilities) - Equipment
•
DEP 30.10.02.14-Gen: Carbon Steel Corrosion Engineering Manual for Upstream
Facilities
•
DEP 30.10.02.15-Gen: Materials for Use in H2S Containing Environment in Oil and
Gas Production (Amendments/Supplements to ISO 15156:2009)
International Standards
•
ISO 15156-1: Petroleum and natural gas industries-Materials for use in H2Scontaining environments in oil and gas production-Part 1: General principles for
selection of cracking-resistant materials
•
ISO 15156-2: Petroleum and natural gas industries-Materials for use in H2Scontaining environments in oil and gas production-Part 2: Cracking-resistant carbon
and low alloy steels, and the use of cast irons
•
ISO 15156-3: Petroleum and natural gas industries-Materials for use in H2Scontaining environments in oil and gas production-Part 3: Cracking-resistant CRA’s
(corrosion-resistant alloys) and other alloys
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3
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MATERIALS SELECTION PROCESS
3.1
General
Materials selection is primarily a process of short-listing technically acceptable materials for an
application and then selecting the technically viable option with lowest life cycle cost for the required
operational life, bearing in mind Health, Safety and Environmental aspects, Sustainable
Development, Technical Integrity and operational constraints. This is a multi-variable process, which
might require several iterations before an optimal solution can be obtained. Part of this process
should also be to assess which systems require materials optimisation and which can use standard
materials selection guidelines.
The materials selection process shall follow the Corrosion Management Framework (CMF) as
described in DEP. 39.01.10.11-Gen section 2.2.3.
3.2
3.2.1
Technical Integrity aspects
Health safety and environment
Materials selection shall be in accordance with the HSE Hazards and Effect Management Process
(HEMP). This process identifies and assesses HSE hazards, implements control and recovery
measures, and maintains a documented demonstration that major HSE risks have been reduced to a
level that is As Low as Reasonably Practicable (ALARP). This shall be done for the full lifecycle of
assets and operations and uses the Risk Assessment Matrix (RAM). For High Risk and/or Severity
hazards bow tie diagrams with links to relevant details should be used to demonstrate tolerability and
ALARP.
3.2.2
Sustainable development
Sustainable development principles shall be applied as part of the materials selection process.
During the past decade it has become clear that the availability of materials and the manufacturing
capacity for materials and products is rapidly becoming a major constraint on construction
capabilities and hence, on energy production and development. Therefore, it is important to use
materials that are readily available and in ways that facilitate standardisation. Thus, one of the
considerations should be to avoid mixing materials in such a way that they cannot be separated
easily as this downgrades their value and limits their availability in the longer term.
3.2.3
Philosophy
Materials selection shall be based on the project life cycle and Basis for Design (BfD) document as
defined in Section 4.1 of this standard.
Materials of construction shall be selected to achieve a balance of minimum CAPEX with reduced
operating costs (OPEX) to maximise project value and minimise risks. The CAPEX shall be the raw
material and fabrication/construction costs. The OPEX shall be the corrosion protection and
inspection/maintenance cost.
The materials selection process shall reflect the overall philosophy regarding design and operating
conditions, design life time, cost profile (CAPEX/OPEX), inspection and maintenance philosophy,
safety and environmental profile, failure risk evaluations, remnant life assessments of existing similar
equipment, lessons learnt via integrity studies, compliance with local and international regulations
and other specific project requirements.
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General Principles
A high level materials selection, aimed at identifying unusually high cost materials is carried out
during the project Select phase and feeds into the Level 1 (CAPEX and OPEX) cost estimate (+40
%/–25 %). For main process stream items, initial materials selection is carried out in the Select phase
of a project. Materials selection for secondary process streams is usually carried out in the project
Define phase as part of the Front End Engineering Design (FEED). During the FEED, materials
selection may be optimised, with the approval of the Materials and corrosion Function, as more
information becomes available in order to reduce costs to a minimum in line with specific project
parameters and risk philosophy. At this stage, more refined judgements on corrosion rates, life
predictions and risk assessments shall be carried out to ensure that the proposed materials selection
will be fit for purpose. For long-lead and/or bulk items (e.g. Line pipe), key materials decisions should
be made as early as possible in the project, preferably during the Select phase, i.e., ahead of FEED.
If the new project will make use of and tie into existing installations, the materials in place and their
current condition should be ascertained in the Select phase. Operations personnel shall be included
in the project team or consulted for these types of developments.
Materials selection is a risk based decision making process with the aim of selecting materials that
give rise to major accident hazard risks that are tolerable and ALARP. The tools of materials
selection decision making and the means of assuring (calibrating) the decision are summarised in the
diagram from SP-2062. - HSE Specification: Specifications for HSE Cases:
Figure 1: Risk based decision making process
The materials selection philosophy should be one that will not require PDO values to be called upon,
i.e. acceptance can be achieved by no more than internal (including Shell) peer review. In practice,
the majority of materials selection decisions will be driven by reference to the GU-611 PDO codes of
practice, specifications, procedures and guidelines; that is to say, the ‘standard materials selection’
option described in this document.
The selection process is structured based on:
a) Standard materials selection
Guidance on the selection of technically proven and economically acceptable materials
selection for most equipment is given in Section 6 of this standard. Selection is based upon
the stated information on the environmental conditions for each system. Standard materials
selection is used to fill in the details for the systems that do not require materials optimisation.
Some optimisation may be required on some process systems, if conditions are encountered
that are not adequately covered in this standard, or if it is required to consider other materials
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choices, in the interest of potential cost savings. This will generally require justification based
on a life cycle cost analysis and a technical integrity verification.
For carbon steel applications, the process of corrosion control option selection, corrosion
control system availability and corrosion allowance selection shall follow the requirements of
DEP 30.10.02.14-Gen.
b) Experimental evaluation (specialist consultation)
Experimental work might be necessary to evaluate materials for specific applications. It shall
be carried out in accordance with the material testing methodology selected for the failure
modes anticipated. Where this is required to assess the suitability of the lowest cost option, it
should be carried out ahead of the Field Development Plan (FDP, in the project select phase).
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MATERIALS SELECTION METHODOLOGY
The standard materials selection process includes the following steps:a) Define the requirements and the environment
The intended design life of the proposed equipment shall be stated.
The internal and external environments for the equipment shall be defined, including any non routine or non-operational conditions that might be encountered. The variables characterising of
the corrosive environment shall be quantified for normal operating conditions and to some extent,
for unusual or upset conditions.
At this point, the operation has to be characterised, e.g., in terms of manning levels, access by
operators, capabilities of operators, in-house or contract operated, access to supplies, spare
parts availability, etc.
b) Assess the applicability of carbon steel and define possible corrosion control options
As an initial step in the materials selection process, the suitability of the potentially low cost
option involving the use of carbon steel should be thoroughly investigated and evaluated to serve
as a baseline against which to compare more corrosion resistant, and possibly more costly,
alternatives. Part of this process will involve the calculation of the Service Life Corrosion (SLC)
for the proposed operating conditions.
For the carbon steel option, possible corrosion control options to protect the steel from premature
failure should be investigated. These could include chemical corrosion control, coatings, cathodic
protection and control of process fluids, e.g., pH stabilization and dehydration. The results of
these studies could lead to a lower value of SLC being appropriate. This will often result in more
than one corrosion control option being taken forward for further consideration (e.g., carbon steel
with a corrosion allowance and inhibition system versus carbon steel with a (different) corrosion
allowance and a dehydration system). The availability of these solutions should be taken into
account. For example, it is notoriously difficult to achieve a consistently high availability of
corrosion inhibitors, so if this is considered, the training and organizational responsibilities should
be realized.
c) Make materials choices
Typical materials shall be selected with the aid of the guide tables for each type of equipment
(see Section 6 of this standard). While a material included is technically acceptable, it will not
necessarily be the most cost-effective choice. This will often lead to more than one technically
acceptable materials being taken forward for further consideration (e.g., carbon steel with a
corrosion allowance versus one or more alternative corrosion-resistant materials).
d) Develop corrosion management framework
See Section 9 of this standard.
e) Assess economics of choices
In the final analysis, selection of the corrosion control option (which includes materials selection)
is often an economic decision, assessing the total cost of each alternative over the total life of the
system, including quantification of the risks and uncertainties (life cycle cost). These include the
risk of failure of corrosion control, the economic impact of corrosion control, RBI, sand
management, inhibition and the possibility of market changes, whereby certain materials could
become more or less economic. Where the risk of failure of corrosion control is high, the
consequences should be taken into account, e.g., enhanced corrosion control measures, and
enhanced inspection and repair. These will be reflected in the economic consequence of failure,
as assessed in S-RBI. Operations personnel should be involved in the life cycle cost assessment
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to ensure all operating costs are considered. This work shall be completed as part of the
corrosion control options selection report and the materials selection report. It is the responsibility
of the project engineer to complete the life cycle costing. The Life cycle cost shall be completed
as per DEP.82.00.10.12-Gen Life cycle costing.
f) Maintain live documents
The Corrosion Management Manual, RBI Plan and Maintenance Reference Plan are live
documents for the lifetime of the facility. These shall be updated whenever there are (approved)
materials substitutions (e.g., during procurement and fabrication), changes to the corrosion
control system and changes to the operation and process, and as monitoring, inspection and
maintenance data are collected during the lifetime of the facility. Service company personnel
often carry out this type of data collection. Personnel involved shall be made aware of the
importance of this work.
The activities associated with the materials selection process can be represented by the flow chart
shown in Figure 2.
Figure 2: Standard materials selection process
Activity 1
Activity 2
Activity 3
Activity 4
Activity 5
Activity 6
4.1
Information Requirements for Materials Selection Study
SELECT Phase
It is expected that the initial inputs will come from the defined DCAF deliverables of the Assess phase
as per the PDO DCAF Description. The process may be initiated with this information and constantly
revisited as the inputs are further refined and the Select phase deliverables are matured ready for
Define. Materials, corrosion and Inspection (MCI) TA2 will define the required deliverables for each
project.
Activity 1: Define
requirements and environment
•
•
Production Profile – possibly Hydrocarbon Production Forecast (DCAF
24 → DCAF 1482)
Water Management Assessment (DCAF 18, GU-672 Assess and
Select)
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•
•
•
Activity 2: Determine threats
and barriers for carbon steel
and other materials (FMEA)
for all materials
•
•
•
•
•
•
•
Activity 3: Assess feasibility of
corrosion allowance and
corrosion control
•
•
•
•
Activity 4: Assess CRA and
non metallic options and rerun
threats and barriers
•
•
•
Activity 5: Identify gaps and
opportunities for qualification
testing
Activity 6: Make materials
choices and develop corrosion
management framework
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Operations & Maintenance Philosophy (DCAF 216 and 218)
Risk Management Plan & Risk Register (DCAF 84 → DCAF 201)
Pipelines Flow & Flow Assurance Study (focus on scale and sand
management) – Preliminary (DCAF 33 → DCAF 110 Pipelines Flow &
Flow Assurance Strategy Reports)
Pipeline & Flowline System Conceptual Design Report (DCAF 117)
Heat & Materials Balance Report (DCAF 108)
Process Flow Schemes (DCAF 112)
Chemicals Requirement Report – Preliminary (DCAF 1272)
Utility Flow Schemes (DCAF 1360)
Equipment Listing (DCAF 1496)
Section 4.5
SP-2041
DEP Specification 30.10.02.14-Gen
DEP Specification 30.10.02.31-Gen
If the operating conditions are beyond currently qualified corrosion
inhibitors, the likelihood of successfully qualifying an inhibitor may be
assessed using the NACE paper by A Crossland, et al.
Section 4.5 of this standard
SP-2041
DEP Specification 39.01.10.12-Gen (as amended by this document)
DEP Specification 30.10.02.15-Gen
•
Project Schedule – Level 2 (DCAF 186)
•
•
•
Concept Selection Report (DCAF 99)
Equipment specifications (PDO and DEP)
Facility Status Reports/Current Status Reports (for brownfield projects
– see CP 114)
DEP 31.38.01.84-Gen
DEP 30.10.02.11-Gen
•
•
DEFINE Phase
Activity 1 to 6
•
•
•
•
•
•
•
•
•
•
Basic design package (DCAF 235)
Chemical requirements Report (DCAF 250)
Operations and maintenance philosophy (DECAF 363)
Process flow scheme (PFS) (DCAF 242)
Process engineering flow scheme (DCAF 243)
Utilities flow scheme (UFS) (DCAF 1390)
Utilities engineering flow scheme (DCAF 1391)
Equipment listing (DCAF 1497)
Pipelines flow and flow assurance design and operability report.
(DCAF 248)
Operations and maintenance philosophy (DCAF 363)
Rotating equipment type selection report (DCAF 273)
Pipeline design report (DCAF 315)
Reliability, availability and maintainability report (DCAF 332)
Performance standards & assurance tasks for safety critical
elements/equipment (DCAF 384)
Maintenance and integrity strategy (DCAF 409)
•
•
•
•
Operations and maintenance philosophy (DCAF 49)
Chemical requirement reports (updated) DCAF 1224)
Heat and materials balance report final (DCAF 420)
Pipelines flow and flow assurance report final (DCAF 679)
•
•
•
•
•
EXECUTE Phase
Activity 6
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•
•
•
•
•
•
•
•
•
•
•
•
Process flow scheme (DCAF 1213)
Process engineering flow schemes (PEFS & P&IDs), (DCAF 1214)
Utility flow schemes (UFS) (DCAF 1435)
Utilities engineering flow schemes (UEFS/P&IDs), (DCAF 1449)
Equipment listing (DCAF 1498)
Vibration assessment report (DCAF 487)
Detailed HAZOP report (DCAF 449)
Asset Reference plan (DCAF 438)
Reliability, availability and maintainability report (DCAF 486)
Process control (DCAF 46)
Process control narrative (DCAF 683)
Line List
•
Assurance process (design conditions vs actual and future
operating conditions. Including IOW
Assessed corrosion rate
OPERATE Phase
Assurance
•
4.2
Deliverables of materials selection in various project phases
The following MCI deliverables and requirements shall be implemented for any project regardless of
the scope and value. These are as per PDO version of DCAF.
Table 1: Mandatory deliverables and requirements for Select phase from Materials Corrosion and
Inspection discipline
ORP
Phase
ID
Name
Accountable
Discipline
Description
•
•
•
•
•
Select
47
Erosion Management
Philosophy (DG3a)
Materials
Corrosion
Inspection
and
•
•
Select
60
Corrosion
Management
Philosophy (DG3a)
Materials
Corrosion
Inspection
and
•
•
SP-2161
DEP 39.01.10.11-Gen
DEP 39.01.10.12-Gen (MC CFDH)
Materials and Corrosion Engineer specifies
the acceptable velocity ranges for materials
of construction with respect to corrosion. The
Erosive velocity calculation is done by the
process engineers.
At this stage the overall philosophy should be
defined together with the integrity impact and
need to interface with other disciplines. The
detailed materials selection and details of
inspection techniques will be covered later in
the Preliminary Corrosion and Erosion
Management Manual in the define phase
(ID300).
Provide input on the materials limitation with
respect to erosion velocity. And input into
Preliminary
Corrosion
and
Erosion
Management Manual in the define phase
(ID300).
CP 208 - Corrosion Management Code of
Practice
Mandatory for all projects.
Recommendation
made
in
Corrosion
Management Strategy shall be embedded in
the Corrosion Management Philosophy
including inspection requirements.
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•
•
•
•
•
•
•
Select
210
Initial
Materials
Selection
Report
(including Corrosion
Management
Strategy) (DG3a)
Materials
Corrosion
Inspection
and
•
•
Revision: 0
Effective: September-2014
SP-2161
DEP 39.01.10.11-Gen
DEP 39.01.10.12-Gen (MC CFDH)
DEP 30.10.02.14-Gen
CP 208 - Corrosion Management Code of
Practice
Mandatory for all projects.
The
corrosion
management
strategy
including initial failure mode effect analysis
and the preliminary (high level) materials
selection reports are based on are based
information provided by the project that shall
include
the
required
minimum
information/deliverables as per DCAF for this
phase of the project (e.g. H&MB, etc.).This
should normally consist of referring to the
applicable standards and mention any
important choices that are made, e.g. carbon
steel + corrosion inhibition versus corrosion
resistant alloy. This also includes the
deliverable of materials threats analysis and
the erosion management philosophy.
Materials selection reports shall be prepared
by function (UEOC) for any project. The
report shall be peer reviewed and signed off
by at least two Materials and Corrosion
Engineer TA2s from the Function other than
the author of the report.
External peer review shall be completed for
projects above 1 bln
Table 2: Mandatory deliverables and requirements during the Define phase for Materials Corrosion
and Inspection discipline
ORP
Phase
ID
Name
Accountable
Discipline
Description
•
•
•
•
Define
64
MCI Failure Modes
and Effects Analysis
Report
Materials
Corrosion
Inspection
and
•
•
•
•
•
•
Define
297
Materials Selection
Report - updated
Materials
Corrosion
Inspection
and
•
SP-2161
DEP 39.01.10.11-Gen
DEP 39.01.10.12-Gen (MC CFDH)
Mandatory for all projects to be made part of
the materials selection report. The report
shall be endorsed and approved by Materials
and Corrosion Engineer TA2 from Function.
This is an FMEA of the corrosion control
systems; for each mode of operation and
corrosion risks, analysis looks at the barriers
and monitoring that need to be in place.
SP-2161
DEP 39.01.10.11-Gen
DEP 39.01.10.12-Gen (MC CFDH)
Mandatory for all projects
Based on the preliminary report (ID 210), this
report shall include detailed assessment to
ensure the agreed materials selection for all
aspects of the projects is properly
documented independently from the Select
phase report based on the updated design
basis.
The updated Materials selection shall be peer
reviewed by PDO Materials and Corrosion
Engineer TA2 other than the author of the
report and Materials and Corrosion Engineer
TA2 from Function. The final endorsement
and approval shall be by Materials and
Corrosion Engineer TA2 from Function.
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•
•
•
•
•
•
•
•
•
•
Define
298
Corrosion Inhibition
System Design &
Test Proposal
Materials
Corrosion
Inspection
and
•
Revision: 0
Effective: September-2014
For projects more than 100 mln USD or for
new field development including EOR/severe
sour environments, the Materials selection
reports shall be endorsed and approved by
Materials and Corrosion Engineer TA1.
For projects 1 billion and above, materials
selection shall be endorsed by DRB1.
This is one of Materials, Corrosion &
Inspection key deliverables which requires
interaction
with
many
disciplines.
Presentations to key disciplines are
recommended to ensure everyone is aware
of the choices and implications. The
consequence of materials selection must be
understood / agreed by the Operator.
Philosophy
should
be presented to
Operations representative and if necessary to
the Operator’s Management to ensure all
consequences are understood / agreed. The
control also includes deliverable of pipeline
preservation / transportation / storage and
etc.
Long lead items finalized at FEED stage shall
be endorsed and approved by Materials and
Corrosion Engineer TA2 from Function.
Materials selection report shall be aligned
and verified with the HAZOP, and ALARP.
MCI TA shall participate in HAZOP and
ALARP assessment.
DEP 30.10.02.14-Gen
DEP 31.01.10.10-Gen
PR 1103 - Chemical Injection
Mandatory for all projects where applicable
Materials selection report identifies the
requirement of corrosion inhibitor. Unless a
corrosion inhibitor (CI) application duplicates
an existing application, tests are required to
qualify the CI. Corrosion inhibition testing
protocol and the test results shall be
evaluated by Materials and Corrosion TA2.
This document defines the use of availability
requirements for corrosion inhibitors, test
program and an update of ID 301 the
Preliminary Chemical Compatibilities Matrix.
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•
•
Define
300
Corrosion
Management
Framework
Preliminary
-
Materials
Corrosion
Inspection
and
•
•
•
Define
302
Welding & Weld
Inspection
Specifications
Materials
Corrosion
Inspection
and
•
Revision: 0
Effective: September-2014
Mandatory for all projects.
Corrosion Management Framework (CMF)
covers corrosion risks, means of mitigation,
monitoring and demonstrating integrity. There
is synergy with the CMF, Safety Critical
Elements / Technical Integrity Framework
and RBI. Incorporates data from Performance
Standards for Safety Critical Elements (ID
384), the Materials Selection report (ID 297)
and the CI System Design (ID 298). It
includes deliverables of critical flow velocity
report, erosion mgt manual, integrity mgt
philosophy, CP designs and for sour systems
sulphur depositions evaluation, oxygen
ingress into the pipeline, potential corrosion
implications such as:a) Execute Failure Mode and Effects
Analysis
b) Produce
preliminary
Corrosion
Management Framework
c) Pipeline
Integrity
Management
Philosophy
d) Include erosion and sand handling
e) Corrosion and inspection integrity
management philosophy
f) Inspection
strategy
shall
be
included.
This report shall be reviewed by PDO
Materials and Corrosion Engineer TA2 other
than the author of the report and Materials
and Corrosion Engineer TA2 from Function.
The final endorsement and approval shall be
by Materials and Corrosion Engineer TA2
from Function.
Shall refer to PDO welding and NDT
specifications
Generate welding and weld inspection
specifications (or instruct contractor to do
such).
For CRAs materials grades not listed in SP1173, the specifications shall be developed
and approved by Materials and Corrosion
Engineer TA2 from Function.
Table 3: Mandatory Deliverables and requirements during the Execute phase for Materials corrosion
and inspection discipline
ORP
Phase
ID
Name
Accountable
Discipline
Description
•
•
Execute
Local
Rule
Updated
Materials
Selection Report
Materials
Corrosion
Inspection
and
•
•
Mandatory for all projects.
Materials selection peer review sessions shall
be organized by the Materials and Corrosion
Engineers from the projects or the author of
the report and ensuring participation from
Process, Mechanical, Rotating and Pipeline
engineering. This report shall be approved by
Materials and Corrosion Engineer TA2 from
Function.
For projects more than 100 mln USA or for
new field development including EOR/severe
sour environments, the Materials selection
reports shall be endorsed by TA1.
A final Materials selection report shall be
generated during Execute phase to ensure
the outcome of the FEED and DD
assessment is included in the final
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•
•
•
•
Execute
51
Set-up
and
Optimisation of
Corrosion
Control System
Materials
Corrosion
Inspection
and
•
•
•
Execute
77
Corrosion
Inspection
Management
System Selection
and Population
Materials
Corrosion
Inspection
and
•
•
•
Execute
79
Corrosion
Inhibitor
Selection Report
Materials
Corrosion
Inspection
and
•
Execute
82
Execute
87
Execute
88
Execute
168
Execute
170
Approval
by
Function
Inspectors
&
Jointers for Non
metallic
for
contractor staff
Approval
by
function:Calculation of PE
Liner thickness
Approval
by
function:- use of
external
MCI
consultancies,
test laboratories
and
test
requirements
Approval
by
Function
operators
for
specialized NDT
processes
Approval
by
Function
Contractors
welding
Engineers & NDT
level III
Materials
Corrosion
Inspection
and
Materials
Corrosion
Inspection
and
Materials
Corrosion
Inspection
and
Materials
Corrosion
Inspection
and
Materials
Corrosion
Inspection
and
Revision: 0
Effective: September-2014
deliverable. This report shall be approved as
indicated in Section 8.
This report should be completed and peer
reviewed before material is procured.
Long lead items finalized at FEED stage shall
be endorsed and approved by Materials and
Corrosion Engineer TA2 from Function.
Mandatory for all projects.
Prove that all corrosion control equipment is
working and operators understand the
procedures; demonstrate that corrosion is
under control. This first requires the corrosion
and erosion monitoring systems to be tested
and accepted.
To be signed off by Corrosion Control TA2
from Function.
Mandatory for all projects.
There are many different CIMS used in the
Shell Group, e.g. Pacer, IMSA, etc (see
toolbox). The correct system has to be
selected for the operating region, the system
has to be set up and populated with
equipment and a baseline generated.
Communicate with business unit to determine
who has ultimate responsibility and what the
requirements and expectations are.
To be signed off by Materials Corrosion &
Inspection TA2 from Function.
Mandatory for all projects and new
equipment.
Developed from the philosophy document
(ID60), and the Corrosion Management
Framework (1194) and linked to Performance
Standard for Safety Critical Elements (ID
452).
To be signed off by Corrosion Control TA2
from Function.
•
Mandatory for all projects if the material is
applicable for the project.
•
Mandatory for all projects if the material is
applicable for the project.
•
Mandatory for all projects if the material is
applicable for the project.
•
Mandatory for all projects if the material is
applicable for the project.
•
Mandatory for all projects if the material is
applicable for the project.
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Execute
171
Execute
173
Execute
174
Execute
175
Execute
176
Execute
177
Execute
178
Execute
182
Execute
183
Execute
217
Execute
484
Approval
by
Function:- GRE
1000 hrs test
pressure,
material and type
of joints type
Approval
by
function:New
coating
applicators
or
coating products
Approval
by
function:New
coating
testing
program
Approval
by
function:New
shrink sleeves
All
specialized
material
and
weld qualification
testing
Approval
by
function:CP
design for buried
pipelines, tanks
and submarine
loading liners
Approval
by
function:Approval of Well
casing corrosion
protection
strategy
Review
and
approval of the
corrosion
monitoring plans
for
corrosion
inhibitors,
CP,
DCVG, CIPS
Approval
of
pipeline
and
equipment
integrity
report
including
RBA
and RBI reports
Approve
Assessed
corrosion rate
Field Inspection
Plan / RBI Plan /
Baseline
Inspection
/
CIMS
(for
Operate)
Materials
Corrosion
Inspection
and
Materials
Corrosion
Inspection
and
Materials
Corrosion
Inspection
and
Materials
Corrosion
Inspection
and
Materials
Corrosion
Inspection
and
Materials
Corrosion
Inspection
and
Materials
Corrosion
Inspection
and
Materials
Corrosion
Inspection
and
Materials
Corrosion
Inspection
and
Materials
Corrosion
Inspection
and
Materials
Corrosion
Inspection
Revision: 0
Effective: September-2014
•
Mandatory for all projects if the material is
applicable for the project.
•
Mandatory for all projects if the material is
applicable for the project.
•
Mandatory for all projects if the material is
applicable for the project.
•
Mandatory for all projects if the material is
applicable for the project.
•
Mandatory for all projects if the material is
applicable for the project.
•
Mandatory for all projects if the material is
applicable for the project.
•
Mandatory for all projects if the material is
applicable for the project.
•
Mandatory for all projects if the material is
applicable for the project.
•
Mandatory for all projects if the material is
applicable for the project.
•
Mandatory for all projects if the material is
applicable for the project.
•
•
Mandatory for all projects.
Developed from the Corrosion Management
Framework (ID300, Define Phase and
ID1194, Execute Phase) and linked to
Performance Standard for Safety Critical
Elements (ID 452 - Execute Phase. This
includes the selection and population of
CIMS (Corrosion Inspection Management
System and the Field Inspection Plan / RBI
Plan.
Inspection plan shall be included.
To be signed off by Material Corrosion &
Inspection TA2 from Function.
and
•
•
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•
•
Execute
488
Welding,
Fabrication
Inspection
Procedures
and
Materials
Corrosion
Inspection
and
•
•
Execute
1194
Execute
Corrosion
Management
Framework
Materials
Corrosion
Inspection
Final
Material
selection Report
Materials
Corrosion
Inspection
•
•
and
and
•
•
•
Revision: 0
Effective: September-2014
PQR, WPS, NDT procedures, heat treatment
procedures shall be authorised at project
levels except for below mentioned areas. To
be signed off by Welding and NDT.
TA-2.
PQR, WPS, heat treatment procedures
involving for CRAs (25% Cr and above), low
temperature applications, >X65 steels (within
the standards) shall be approved by the
material and corrosion function (UEOC). To
be signed off by Specialized Welding & NDT
TA-2.
Advanced NDT technique procedures such
as AUT, Phased Arrays, TOFD, and
radioscopy. To approved and signed off by
Specialized Welding & NDT TA-2.
Non-metallic, bonding procedures, PE lined
fusion bonding procedures shall be approved
by and signed Materials and Corrosion TA2
in Non-metallic from Function.
Mandatory for all projects.
Update of the preliminary document,
developed in the Select phase (ID 300) and
Performance Standards for Safety Critical
Elements (ID 384).
Mandatory for all projects.
Update of the preliminary document.
To be approved by Materials and Corrosion
TA2 from function.
Table 4: Mandatory Deliverables and requirements during the operate phase for Materials corrosion
and inspection discipline
ORP
Phase
ID
Name
Accountable
Discipline
Description
•
•
Operate
25
Risk
Based
Inspection
Materials
Corrosion
Inspection
and
•
Mandatory for all operations.
Risk Based Inspection (RBI) covers the
verification of the integrity of the assets. It
includes analysis (using S-RBI see toolbox),
inspection
planning
and
work
pack
development for internal and external
corrosion, non-intrusive inspection (NII)
analysis, inspection execution, storing the
data in CIMS (see toolbox), inspection data
analysis, fitness for purpose assessment,
external corrosion analysis and modelling
(using ECM/EXCOR see toolbox), corrosion
modelling. Local legislation requirements for
inspection (review and reporting), reporting to
asset custodian and feedback of data into the
CMF (ID NEW above).
RBI shall be approved by Materials Corrosion
and
Inspection
TA2
from
Function.
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•
•
Operate
1197
Corrosion
Management
Framework
Materials
Corrosion
Inspection
and
•
•
•
•
Operate
1206
Materials Failure
Investigation
Report
Materials
Corrosion
Inspection
and
•
Revision: 0
Effective: September-2014
Mandatory for all operations.
The CMF was set up in the Execute phase
(ID 1194) and is an "evergreen" document for
the life of the facilities. This assessment
looks at how well the corrosion control
systems are working, and feeds into the
integrity management of the different assets
(the integrity management manuals are
covered under ID 484). If availability targets
are not met this may also require shutdown
of the assets to prevent (further) corrosion.
To be approved by Corrosion Control
Engineer TA2.
Conduct periodic review of CMF and identify
break down of barriers. Continue of operation
with one or more broken barrier can only be
authorized by MCI TA1.
Mandatory for all material failures.
Failure investigation related to material failure
such as corrosion, cracking and ruptures, or
failure during manufacturing such as weld
failures shall be investigated by a Material
and Corrosion Engineer and corrosion control
Engineer along with Integrity Engineer from
function.
The final report to be signed off by relevant
Material and Corrosion TA2 from Function.
Certificate of statement of fitness related to process containment/materials shall be completed as per
SP-2062 before initial operation and shall include Materials, Corrosion and Inspection TA2 signatures
for items related to process containment integrity assurance.
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4.3
4.3.1
Revision: 0
Effective: September-2014
Factors affecting Materials selection
Information required and review of factors affecting materials selection
Shall be as per DEP.39.01.10.11-Gen, Section 2.3.3 with the following amendments:a) Section 2.3.3.2. Replace Table 1 with the Table A.1 in Appendix A of this document.
b) Remove reference to EFC 17 as worst case for chloride when not other information is
available.
c) Add the following:
Chlorides carry over evaluation:
For gas production environments (produced gas or without produced water) and downstream
of separator. Salt accumulation scenarios shall be evaluated as part of materials selection
process.. Presence of formation water shall be included in the evaluation. Assumptions of
lower Chloride levels can only be determined with a proper salt materials balance studies
approved by the respective technical discipline authority (process) and supported by
operation and maintenance philosophy.
d) Section 2.3.3.4 and Appendix E Table E.1 for low temperature requirements shall be
replaced by DEP.30.10.02.31-Gen.
4.4
Application of carbon steels
Shall be as per DEP 39.01.10.11-Gen, Section 2.4. and DEP 30.10.02.14-Gen
4.5
Degradation mechanisms
A standardised checklist of corrosion threats is compiled by reference to DEP 39.01.10.11, API RP
571 and the Energy Institute (EI) Guidance for Corrosion Management. Materials and Corrosion
Engineer shall be consulted to ensure all the degradation mechanisms are evaluated including all the
normal and upset operating scenarios.
The following table contain the possible damage mechanisms that shall be evaluated during
materials selection process and the mandatory requirements associated to each damage
mechanism.
Damage
Mechanism
Description
CO2 corrosion is one of the most common forms corrosion resulting in wall
thickness loss in carbon steel oil / gas preproduction systems. CO2 corrosion is
caused by electrochemical reactions between the steel and carbonic acid.
CO2 Corrosion
The Hydrocor model has been developed for predicting the likely ‘worst case’
corrosion rate of carbon steel. Hydrocor is a model for quantifying the
corrosivity of the operating environments associated with the production and
transportation of water-wet hydrocarbons in carbon steel facilities. The
predicted corrosion rate is used to identify Service Life Cycle (SLC) and to
determine the appropriate corrosion allowance for a carbon steel system or
whether Corrosion Resistant Alloy (CRA), non-metallic materials or other
corrosion mitigation method is required. The HYDROCOR model (Appendix F)
or an alternative model approved by TA1 shall be used for corrosion modelling
in systems containing CO2. The aim of calculating the CO2 corrosion rate is to
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Revision: 0
Effective: September-2014
establish the SLC and thereby decide what corrosion allowance might be
needed or whether a CRA is required.
Welds and their surrounding heat-affected zones may have lower resistance to
CO2 corrosion than the parent metal. This phenomenon is known as
Preferential Weld Corrosion (PWC). This may arise for a number of reasons,
partly geometrical, partly chemical and partly metallurgical. Corrosion control by
means of inhibition has been shown to prevent PWC, provided that a suitable
corrosion inhibitor is selected and injected to provide a sufficiently high
concentration. See also DEP.39.01.10.11 (Appendix B). It should be assumed,
for sweet production systems, that the corrosion rate of the weld and heat
affected zone is three times that of the surrounding parent steel.
For more details information, refer to:
• DEP 39.01.10.11-Gen Informative, Section 2.4.3
• EI Guidance, Annex B1
• API RP 571, Section 4.3.6
• NORSOK M-601
Compared to CO2 corrosion of steel, H2S may not cause severe metal weight
loss corrosion because the corrosion product, iron sulfide (FeS) usually forms a
protective film on the steel surface. However, whenever the film is imperfect or
damaged, a corrosion cell is set up between FeS covered surface and the bare
metal, resulting in very localised, accelerated corrosion (e.g., pitting corrosion).
Therefore, the corrosion failure mode in sour systems is pinhole leaks, which
are extremely dangerous, considering the health risks associated with H2S.
H2S Corrosion
For carbon steel, the Hydrocor model can be used for corrosion rate prediction
in H2S containing systems. The empirical correlation included in Hydrocor for
o
sour conditions is only verified up to 50 C and 15 bar ppH2S. Above these
values/levels, the corrosion prediction is not considered reliable. Sour corrosion
modelling typically gives over prediction as Hydrocor model provides a worst
case pitting scenario, depending on factors like whether sulphur is present or
not. Testing shall be carried out to optimise the corrosion assessment with
laboratory testing and reviewing operating field analogues.
For more details information, refer to:• DEP 39.01.10.11-Gen Informative, Section 2.4.4.2
• API RP 571, Section 5.1.1.10
The presence of elemental sulphur increases the corrosivity of the environment
for pitting corrosion, stress corrosion cracking and particularly weight loss
corrosion thus assessment for elemental sulphur deposition shall be carried out
for high H2S content reservoir (>2Mol%). The presence of chloride ions greatly
enhances sulphur corrosion.
Elemental
sulphur
Top-of-Line
Corrosion
Amine Corrosion
Where elemental sulphur is likely to form in carbon steel systems, sulphur
solvents shall be used to prevent the sulphur depositing. Hydrocarbon liquids
are generally good sulphur solvents. The volume of liquid hydrocarbon present
and its capacity to dissolve sulphur should be assessed to determine whether
any additional sulphur solvent is required. In sour systems that contain oxygen,
sulphur can form in situ. All potential sources of oxygen in sour systems should
be reviewed and where required eliminated or minimized.
CRA materials are not immune to elemental sulphur (pitting/cracking). The
application limits in SP/DEP/ISO 15156 for CRA do not include any presence of
Elemental sulphur.
Top of line corrosion is due to condensation rate
DEP 39.01.10.11-Gen Specification, Table 2
• API RP 571, 5.1.1.1,
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ErosionCorrosion
Oxygen
Corrosion
Revision: 0
Effective: September-2014
• EFC 46
• DEP 39.01.10.11-Gen Informative, Appendix D;
• EI Guidance, Annex B12;
• API RP 571, 4.2.14
In aqueous corrosion, oxygen is a more corrosive gas than CO2 and H2S. For
bare carbon steel system, pitting corrosion will occur when exposed to
seawater even with only traces amount of oxygen, but the rate of corrosion is
proportional to the mass transfer rate of dissolved oxygen to steel surface. If
oxygen is continually maintained at < 10ppb, a bare carbon steel or lower grade
CRA should be acceptable with minimum expected corrosion downstream of
the oxygen removal point. However, during upset conditions, which are
unavoidable in almost all cases, the dissolved oxygen concentration can reach
fully aerated levels. For carbon steel systems the corrosion rate is proportional
to the rate at which oxygen reached the steel. For hydrocarbon production
systems oxygen is deemed an operationally avoidable corrodent. Where it may
have an impact is in utility water systems for example. Aqueous oxygen
corrosion rates can be predicted with HYDROCOR.
CRA oxygen corrosion is a form of galvanic attack where the normal protective
passive surface oxide film fails at one small point and becomes a small anode
to the surrounding intact surface, resulting in very rapid localised pitting attack.
Oxygen pitting attack on a CRA is often more rapid than on CS, with
penetration rates as much as 6 times higher.
Materials selection for hydrocarbon application does not consider presence of
oxygen in the system. The facilities shall be designed to avoid any potential
ingress of oxygen.
Crevice
Corrosion
Pitting Corrosion
Under Deposit
Corrosion
(UCD)/dead leg
Galvanic
Corrosion
The application limits of CRAs defined in company standards are based on
oxygen free conditions.
Crevice corrosion tends to occur within a tight gap, or underneath deposits (see
also UDC) where an occluded environment can develop, e.g. a tube to tube
sheet joint. It can also be considered under flange face corrosion as described
in EI Guidance, Annex B8.
Likelihood of crevice corrosion shall be minimized by materials selection and
design considerations.
Considered separately to pitting caused by other corrosion threats, in this
context it is applied to CRAs with passive films in production and utility
environments. In production environments the key parameters are temperature
and chloride content, whilst in utility environments it will generally be oxygen
(oxidiser) content, flow rate, temperature and chloride content.
Likelihood of pitting shall be minimized by materials selection and design
considerations.
The deposition of solids creates a shielded environment that provides
conditions for other degradation mechanisms, such as MIC, to occur. Solids in
straight piping runs are considered to settle out when film velocities are less
-1
than 1 ms . Loosely adherent scale can also creates a shielded environment in
the same way as settled deposits.
Dead leg corrosion, detailed in EI Guidance, Annex B4, Shall be assessed
during all phases of the project.
Galvanic corrosion occurs when two dissimilar alloys are coupled in the
presence of a corrosive aqueous solution. The more active materials will be the
anode and will be preferentially corroded, while the other, more noble materials
will be the cathode and is protected from corrosion. A large ratio of cathode to
anode surface area must be avoided because the galvanic attack is
concentrated in the small areas of the anode.
For more details information, refer to
• EI Guidance, Annex B5
•
API RP 571, Section 4.3.1
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Microbial
Induced
Corrosion (MIC)
Revision: 0
Effective: September-2014
Microbiologically Induced Corrosion (MIC) is a corrosion resulting from the
presence of active biological microorganisms from contaminated well operating
fluids, a contaminated reservoir, contamination during construction, surface
commissioning fluids, seawater injection, the design or practice of disposing
surface water in oilfiled pipelines, open drain systems, etc. Microorganisms
tend to attach themselves to solid surfaces, colonise, proliferate and form
biofilms, which can create a corrosive environment at the biofilm / metal
interface radically different from the bulk medium in terms of pH, salts and
dissolved gas. As a consequence, either a galvanic corrosion cell and / or
acidic action may develop causing metal attack. Instead of causing general
corrosion, MIC is a localised attack and may take the forms of pitting corrosion,
crevice corrosion, under deposit corrosion, selective dealloying and galvanic
corrosion.
Once bacteria are present in the system it is almost impossible to eliminate
them. Bacterial surveillance program shall be performed during field
commissioning and after any significant new activity. Methods to mitigate
bacteria presence is chemical treatment (commonly with biocide), operational
pigging and robust surveillance program in place. The likelihood of MIC can
also be assessed using HYDROCOR.
Preferential Weld
Corrosion
Intergranular
Corrosion
Strong Acid (Well
Workover)
Corrosion
For more details information, refer to:• EI Guidance, Annex B4
API RP 571, Section 4.3.8
Welds and their surrounding heat-affected zones may have lower resistance to
CO2 corrosion than the parent metal. This phenomenon is known as
Preferential Weld Corrosion (PWC). This may arise for a number of reasons,
partly geometrical, partly chemical and partly metallurgical. Corrosion control by
means of inhibition has been shown to prevent PWC, provided that a suitable
corrosion inhibitor is selected and injected to provide a sufficiently high
concentration.
For more details information, refer to:• DEP 39.01.10.11-Gen Informative, Appendix B
• EI Guidance, Annex B6
Principally occurring in austenitic stainless steels it is characterised by attack
along grain boundaries where precipitation of chromium carbides, nitrides or
intermetallics has reduced the corrosion resistance of adjacent materials. This
effect is known as ‘sensitisation.’
See DEP 39.01.10.11-Gen Specification, 3.3 for mandatory requirements. Post
stimulation mitigation and management approach are given in RMP
31.40.00.50 (for sour service).
Internal Cracking
SP-2041; DEP 39.01.10.11-Gen Specification, 2.4.4.3; EI Guidance, Annex B2;
API RP 571, 5.1.2.3, ISO 15156.
Sulphide Stress
Cracking
SSC is a rapid form of cracking that can cause catastrophic failure. Control of
this form of cracking SHALL [PS] be through selection of materials not
susceptible to cracking under all expected modes of operation (including start
up and shutdown). Materials selection shall be carried out using DEP
30.10.02.15 AND SECTION 5 of this SP.
Many of the requirements of DEP 30.10.02.15-Gen. are related to hardness
restrictions, and it uses both Rockwell C (for non-welded materials) and Vickers
10 kg (22 lb) (for welded materials). Approximate hardness conversion tables
are given in ASTM A370. Note that the conversion factors do not apply to all
types of materials. For hardness conversions of martensitic and
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Hydrogen
Induced Cracking
Stress Oriented
Hydrogen
Induced Cracking
Amine Stress
Corrosion
Cracking
Hydrogen
Embrittlement
Chloride Stress
Corrosion
Cracking
Revision: 0
Effective: September-2014
austenitic/ferritic materials the Principal shall be consulted.
SP-2041; DEP 39.01.10.11-Gen Informative, 2.4.4.4; EI Guidance, Annex B2;
API RP 571, 5.1.2.3 Where no HIC testing for certain product forms is required
by Table 4 the need for such testing should be evaluated based on the criticality
of the components in question.
HIC requirements SHALL be as per SP-2041. SP-2041 replaces HIC
requirements in section 2.4.4.4 of DEP.39.01.10.11. The test method has been
shown to be very sensitive to small variations; therefore a control sample of
known HIC sensitivity shall be included in HIC tests to make sure that the
results are calibrated against a standard.
EI Guidance, Annex B2; API RP 571, 5.1.2.3
API RP 571, 5.1.2.2; EFC 46
DEP 39.01.10.11-Gen Specification, 2.4.4.6; API RP 571, 4.5.6
EI Guidance, Annex B11; API RP 571, 4.5.1
Liquid Metal
API RP 571, 4.5.5
Embrittlement
Corrosion
API RP 571, 4.5.2
Fatigue
External corrosion
Atmospheric
Corrosion
Corrosion Under
Insulation
Crevice and
Pitting Corrosion
Galvanic
Corrosion
High temperature
oxidation
Sulphidation
Soil Corrosion
EI Guidance, Annex B9; API RP 571, 4.3.2
EI Guidance, Annex B10; API RP 571, 4.3.3
EI Guidance, Annexes B9 and B11
EI Guidance, Annex B5; API RP 571, 4.3.1
API RP 571, 4.4.1
API RP 571, 4.4.2
Applicable to such items as flare tips operating with H2S
API RP 571, 4.3.9. Including MIC corrosion.
External Cracking
Chloride Stress
Corrosion
Cracking
Hydrogen
Embrittlement
Liquid Metal
Embrittlement
Corrosion
Fatigue
EI Guidance, Annex B11; API RP 571, 4.5.1
DEP Specification 39.01.10.11-Gen, 2.4.4.6; API RP 571, 4.5.
API RP 571, 4.5.5
API RP 571, 4.5.2
Mechanical Degradation
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Effective: September-2014
Erosion by Solids
and Liquids
DEP Informative 39.01.10.11-Gen, D.2.1, D.2.2; EI Guidance, Annex B12; API
RP 571, 4.2.14
External
Abrasion & Wear
DEP Specification 31.38.01.29-Gen
Issues that may fall under this categorisation are: piping clashes, fretting and
wear at pipe supports.
Fatigue Cracking
API RP 571, 4.2.16 and 4.2.17; Energy Institute Process Pipework Fatigue
Guidelines
High Temperature Creep and Stress Rupture
High
Temperature
Creep and Stress
Rupture
Thermal Fatigue
Low Temperature
Embrittlement
Long Running
Ductile Fracture
API RP 571, 4.2.8
Galling
Non-Metallic Seal
Degradation
4.6
API RP 571, 4.2.9
DEP Specification 30.10.02.31-Gen; API RP 571, 4.2.7
DEP 31.40.00.10-Gen Specification, 8.1.6
Applicable to gas and multiphase pipelines where fluid decompression
characteristics can drive initiated cracks for substantial distances
Galling is a form of adhesive wear and occurs by dynamic metal-to-metal
contact between two surfaces sliding relative to one another when there is poor,
or non-existent, lubrication. It can occur at flange/gasket interfaces and lead to
poor sealing.
DEP 39.01.10.12-Gen Specification, Appendix C
Rapid gas decompression is a major cause of elastomeric seal failure in high
pressure gas service. Seals can also fail by ageing where the service
environment induces chemical or physical changes. Supporting information for
study is given in UK HSE Research Reports 320 and 485.
Refer to DEP30.10.02.13 for non metallic testing requirements.
Economic aspects of materials selection
Shall be as per section 2.5, DEP 39.01.10.11 –Gen.
4.7
Non- operational considerations
Materials selection shall consider all the operating modes including non operational considerations as
per section 3 of DEP 39.01.10.11-Gen.
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5
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Effective: September-2014
GENERAL MATERIALS DESCRIPTION AND SPECIFIC REQUIREMENTS
5.1
General Requirements for Specific Materials Group
5.1.1 Sour service
If hydrogen sulfide concentration (H2S) is present in the equipment over the lifecycle in any phase
the service shall be considered as sour service and the requirements of SP-2041 and
DEP.30.10.02.15 shall applied. Concentration of H2S shall be determined in accordance with DEP
25.80.10.18-Gen.
When assessing materials suitability, the pH and H2S partial pressure shall represent not only normal
life cycle exposures but also exposures as can reasonably be expected to occur during an upset or in
a stratified flow condition (e.g., normal packer fluid pH versus condensing water pH after tubing to
annulus leak, or pH of flowline fluid versus condensing water pH during stratified flow.
For vessels, internal protective coatings are acceptable to protect carbon and low alloy steels against
Hydrogen Induced Cracking (HIC) or stepwise cracking, provided that the coating integrity is ensured
by means of a suitable coating maintenance program and that a program to detect and monitor HIC
formation and growth is in place. (Informative: For practical purposes, this shall only apply to
vessels).
Stainless steels
The production stream phase behaviour SHALL [PS] be reviewed to identify if flashing conditions or
salt deposition from carryover fluids are present, which conditions concentrate fluid salinity. In the
event flashing conditions are present, either a salinity of 250 g/l (expressed as NaCl) or the greater
value equivalent to salt saturation in water at operating conditions shall be assumed when selecting
and testing the materials. Any testing shall be done in representative water chemistry.
The temperatures given in Table 5.1 shall be used to assess the risk of pitting corrosion, crevice
corrosion and chloride stress corrosion cracking of the most common stainless steel type used in
Upstream in offshore and onshore salt laden environments (e.g. desert environment). The risk for
other stainless steel types shall be referred to the MCI TA2 from Function.
Table 5.1: Typical stainless steel temperature limits.
Stainless
steel type(1)
Threshold
for pitting
corrosion
Threshold
for crevice
corrosion
Negligible
risk of
CSCC
Significant
risk of
CSCC
316L(2)
6Mo
22Cr
Duplex(3)
25Cr SuperDuplex(4)
5oC
50oC
40oC
<0oC
30oC
15oC
<50oC
<100oC
<80oC
>60oC
>120oC
>100oC
60oC
30oC
<100oC
>110oC
(1) Table gives requirements for generic stainless steel types. Specific materials and conditions may influence
the acceptable temperature
(2) Assumes minimum Molybdenum content of 2%. Higher temperatures may be possible at higher Mo
content.
(3) Assumes PREN > 35
(4) Assumes PREN > 40
Contact of zinc with stainless steel items SHALL[PS] be prevented, including zinc coating
contamination and contamination by zinc in fire scenarios from other equipment.
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Ferritic and Martensitic stainless steels such as those of the 13Cr family are susceptible to both
sulphide stress cracking (SSC) and stress corrosion Cracking (SCC) and therefore their application
shall be in accordance to DEP.30.10.01.15.
Austenitic stainless steels containing less chromium, nickel and molybdenum than AISI 316, such
as AISI 304, shall not be used / applied in PDO production facilities as defined in DEP 39.01.10.12Gen, Appendix A.
All the austenitic stainless steels wrought, forge and cast products shall be subjected to intergranular
corrosion testing in accordance with ASTM A262 Practice E. The materials shall pass required
criteria stated in ASTM A262 specification. The intergranular corrosion test shall be performed for
each heat in the purchase order.
Austenitic/ferritic stainless steels (duplex stainless steels) can suffer both SCC and SSC, hence
hardness requirements from DEP 30.10.01.15 shall apply and strict H2S partial pressure limits shall
be followed as given in Part 6 and DEP 30.10.01.15. Both 22 Cr duplex and 25 Cr super-duplex
stainless steels are susceptible to CSCC at 80 °C (176 °F) under drop evaporation conditions, and
their use at points of salt accumulation shall be avoided.
Applications of duplex stainless steels at Lower Design Temperatures (LDT), for which the design
code asks for proof of toughness by impact testing, require an additional specification of the steel
being ordered and confirmation of proven toughness on the steel certificate. Welding procedures
shall be qualified or re-qualified with impact testing included, when required by the design code for
the given LDT. The minimum design temperature of duplex stainless steels is -50°C (-58°F) with
maximum thickness of 40 mm (1.6 in) unless otherwise qualified in accordance with
DEP 30.10.02.31-Gen section 5.4. Duplex stainless steel shall have PREN > 34, with a nitrogen >
0.14%. The super duplex stainless steel shall contain at least 25%Cr and PREN > 40 and nitrogen >
0.2%. Duplex stainless steel and super duplex stainless steel shall comply with DEP 30.10.02.35Gen requirements.
All the DSS and SDSS wrought, forge and cast products shall meet following requirements in
addition to requirements stated in respective MESC SPEs and relevant DEPs.
Transverse tensile test:
Transverse tensile testing is not required for the pipe nominal diameter ≤ 6”. Diameters 8” and above
shall be subjected to transverse tensile test.
Pitting Corrosion testing:
The materials shall be capable of passing the ferric chloride test in accordance with ASTM G 48,
Method A, with the following amendments. This corrosion test shall be performed for product
qualification only.
The exposure time shall be 24 hours. The test temperature for “22Cr” duplex (ferritic-austenitic)
stainless steel shall be 25 °C for parent metal and 22 °C for welds.
The test temperature for “25Cr” superduplex (ferritic-austenitic) stainless steel shall be 40 °C for
parent metal and 35 °C for welds.
•
•
•
The temperature variation shall not exceed ± 0.5 °C.
The surface finish of the test face shall be ‘as-produced’. Cut faces shall be ground to 1200
grit.
The evaluation of results shall be via weight loss measurement and macroscopic
investigation of the surface. Macrographs obtained by low magnification microscopy shall be
provided.
The acceptance criteria shall be a weight loss < 4.0 g/m2 and no initiation of localized corrosion >
0.025 mm (1 mil) at the test face. Note that only corrosion (e.g. pitting) at the test face counts. If the
weight loss is > 4.0 g/m2 and it can be positively identified that this is only due to corrosion at the cut
faces, the test will be invalid. In this case re-testing shall be carried out on replacement specimens.
Frequency of testing shall be each heat in the purchase order.
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Super austenitic stainless steels (>6 % Mo) to ensure corrosion resistance of welds, a nickel alloy
filler with increased Mo, such as alloy 625, shall be used. 6Mo materials shall comply with DEP
30.10.02.35-Gen requirements.
All the UNS S31254 wrought, forge and cast products shall be subjected to ferric chloride test in
accordance with ASTM G48, Method A. The test temperature shall be 50 °C and the exposure time
shall be 24 hours. The test specimens shall be in the as-delivered condition. The test shall expose
the external and internal surfaces. No pitting is acceptable at internal or external surfaces at 20 times
magnification. The weight loss shall be < 4.0 g/m².
Frequency of testing shall be each heat in the purchase order.
Precipitation hardening stainless steels in Appendix A of DEP 39.01.10.12 Gen, such as
UNS S17400 (17-4 PH) and UNS S15500 (15-5PH) shall be prohibited for pressure containment
parts in sour environments. Alloy 17-4 shall be limited to a maximum stress of 50% for compressor
internal components.
Nickel alloys such as UNS N07718 (Alloy 718) shall meet the requirements of
DEP 39.01.10.32-Gen. UNS N07725 (Alloy 725) and UNS N07716 (Alloy 625+ ) shall be specified in
accordance with DEP 39.01.10.30-Gen. These materials may suffer from similar issues to those that
have been observed with Alloy 718, and, as such, care shall be taken during manufacturing and heat
treatment, particularly for critical or highly loaded components.
Alloy N08825 (Alloy 825) shall be supplied with Ni content greater than 39% and a PREN greater
than 30. Quality assurance in supply chain should be closely monitored.
Intergranular corrosion test in accordance with A262 Practice C. Acceptance criteria shall be weight
loss < 0.9mm/year and intergranular penetration shall not exceed 30 microns average, with minimum
individual maximum 50 microns into the surface that will be exposed to the corrosive environment in
the specific application when measures by micrography shall be performed at an appropriate
magnification in a minimum of eight separate viewing fields average. The intergranular corrosion test
shall be performed for each heat in the purchase order.
For materials cladded with Alloy 825 exposed to post weld heat treatment or other stress relieve
treatment during fabrication shall be subject to corrosion test at simulated worst case process
conditions to evaluate effect on the materials. Test shall include pitting and crevice assessment.
Alloy UNS N0625
All alloy 625 materials wrought, forge and cast products shall be subjected to integranular corrosion
test in accordance with ASTM G28, Method A. The maximum allowed corrosion rate is
0.075mm/month and intergranular penetration shall not exceed 30 microns average, with minimum
individual maximum 50 microns into the surface that will be exposed to the corrosive environment in
the specific application when measures by micrography at an appropriate magnification in a minimum
of eight separate viewing fields average.
Frequency of testing shall be each heat in the purchase order.
Where galling resistance is required, anti-galling compounds, electroplating, or use of different
materials should be used for the two parts that come into contact, e.g., N06625 and N07725.
Molybdenum Disulfide SHALL [PS] not be used. An alternative anti-galling approach that may be
used is to specify and assure a minimum difference in hardness of 25 HRB of the components.
Glass reinforced plastics. The choice of fibre and resin should be selected after full consideration
of the service requirements in accordance with SP-2092 and DEP 30.10.02.13-Gen. GRP pipelines
and piping shall be in accordance with SP- 2092, SP-2156 and DEP 31.40.10.19-Gen.
Note: Proprietary materials might be considered upon successful qualification and approval from MCI
Corporate Function Discipline Head (CFDH).
All the corrosion tests shall be carried out at PDO and ILAC approved laboratory.
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5.2
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Effective: September-2014
Specific requirements
5.2.1 Metallurgically bonded clad plates
The plate materials used as clad plates (for explosive and roll bonding) shall be subjected to
corrosion testing as indicated for the base materials in section 5.1. If PWHT is applied the corrosion
test shall be conducted with the simulated actual PWHT cycles.
5.2.2 Welding including clad and overlay equipment
All the weld overlay materials (316L and 625) shall be subjected to integranular corrosion testing as
stated in the section 5.1.
Minimum undiluted weld overlay thickness after machining shall be 1mm for the piping components
and minimum clad thickness shall be 3 mm and two pass.
Alloy 825 weld overlay shall not be used for equipments and piping components.
Base material: For the sour service the base Carbon Steel materials shall meet sour service
requirements. Materials composition shall meet the HIC requirement. However, testing can be
exempted. Hardness values at the clad/weldoverlay interface shall not exceed 248 HV10. Apart from
the PQR qualification hardness testing (including PWHT cycles) shall be carried out.
Welding procedures for ferritic/martensitic materials with austenitic consumables require close
scrutiny, because a hard, brittle zone of relatively high carbon can form in the austenitic material
immediately adjacent to the fusion boundary. This brittle zone is very sensitive to hydrogen
embrittlement (hydrogen-induced stress cracking, sulphide stress cracking) and even brittle fracture
due to stress alone if the critical flaw size (as determined by means of CTOD tests) is exceeded.
Direct exposure of such hard zones to sour conditions and cathodic protection shall be avoided.
Hardness requirements defined in ISO 15156, such as 250 HV 10 is not sufficient, because the brittle
zone is so thin that it cannot be detected with the Vickers method of hardness testing.
A minimum of two layers of weld overlay shall be used. For Alloy 625, the maximum allowed iron
content due to dilution of deposited Alloy 625 by the underlying carbon or low alloy steel at 2.5 to 3
mm from the Alloy 625 surface, shall be 10%. On surface, chemical composition shall meet the
original materials specification, including 5% max Iron. Optical electron spectroscopy (OES) shall be
the only method to determine weld dilution. A cross section shall be taken during weld procedure
qualification and OES shall be done at 1 mm increments from the weld metal through the heat
affected zone, to a distance no less than 3 mm from the fusion line.
When carrying out buttering, the closure weld shall be made with UNS N06625 (Alloy 625). Maximum
hardness of 325 HV 10 in the base metal and HAZ are accepted for non-sour and sour service,
provided that the bore is fully clad (Refer to ISO 15156-3, Clause A13.1).
Single layer welding techniques, e.g., electro-slag, shall only be used with prior approval from the
MCI TA2 from Function.
5.3
Protection against catastrophic failure mechanisms
Sudden failure mechanisms such as stress corrosion cracking, Hydrogen embrittement (corrosion)
fatigue, and low temperature embrittlement shall be prevented by means of proper materials
selection and design. Coatings or corrosion inhibition shall not be used as the primary barrier for
environmental assisted cracking or corrosion-fatigue during design.
Performance tested/qualified Coatings or aluminium foils may be considered for mitigation of Cl-SCC
if the risk is assessed as negligible or manageable, approval from MCI TA2 from Function is required.
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5.3.1
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Chloride stress corrosion cracking
Austenitic and duplex stainless steels may suffer from external chloride induced stress corrosion
cracking (CSCC) when exposed to a combination of tensile stresses, chlorides, water, oxygen, and a
temperature threshold. This failure mode, typically caused by exposure to humid marine atmosphere,
may represent a higher risk than the internal service and is generally manifested by a sudden
fracture of pipe or equipment. PDO is operating in desert environment characterised by frequent
sandstorms and deposition of salt laden sand. Therefore the risk of Cl-SCC shall be evaluated and
documented.
Application of stainless steels with significant risk of CSCC above the given temperature shall be
subject to mitigation to an acceptable level (ALARP). Application of stainless steels with risk of CSCC
at high chloride concentration shall be subject to a risk assessment and mitigation if deemed
necessary.
The threshold temperatures which the material has an acceptable risk of external CSCC are shown
in Table 5.1. Above these temperature thresholds (significant risk of CSCC in Table 5.1) austenitic,
duplex stainless steel, super stainless steels and super austenitic stainless steel shall be externally
coated with Thermal Sprayed Aluminium coating (TSA) in accordance to DEP 30.48.40.31-Gen. If
welding is involved, TSA shall be done post welding.
Organic coating qualified for the service life can be applied if ALARP is demonstrated by risk
assessment.
TSA shall not be used for protection of small-bore (<DN 50) (<NPS 2)) components so selecting a
resistant material is the preferred option.
5.4
Protection of stainless steels for Corrosion Under Insulation (CUI)
with aluminium.
Stainless steels may be protected against external pitting and crevice corrosion under insulation by
means of coating with Thermally Sprayed Aluminium (TSA). Joints and ends shall be taped with selfadhesive aluminium tape. This aluminium foil acts as both a barrier coat and inhibitor. The applicable
temperature range for the use of aluminium foil under insulation is 50°C to 200°C (122 °F to 392 °F)
for continuous service and 50°C to 480°C (122 °F to 896 °F) for cyclic conditions.
Only the arc spray application process shall be used for CRA materials and all systems shall be
sealed using a silicone system. TSA shall be applied in accordance with DEP 30.48.40.31-Gen.
5.5
Sealing materials
Where metal-to-metal seals are used, there is a potential risk of galvanic corrosion. To prevent this,
the seal surface materials shall be at least as noble as the surrounding surfaces. Elastomer seals are
addressed in DEP 39.01.10.12, Section 3.2.13.
5.6
Amendments to ISO 15156
DEP. 30.10.02.15-Gen is written as amendments and supplements to the following ISO Standards:
•
•
•
ISO 15156-1:2009
ISO 15156-2:2009
ISO 15156-3:2009
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Wherever reference is made to the above ISO Standards, it shall be understood to mean the
ISO 15156-1:2009, ISO 15156-2:2009 and ISO 15156-3:2009 as amended/ supplemented by DEP.
30.10.02.15-Gen
Materials limits for sour service shall be in accordance with this SP, DEP 30.10.02.15-Gen, and ISO
15156. Remarks made in ISO 15156-3 tables indicating “ ANY” combination of parameters (pH,
ppH2s, temperature and chloride, etc.) shall not be used for materials selections.
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6
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MATERIALS SELECTION BY EQUIPMENT SYSTEMS
6.1
INTRODUCTION
6.1.1 General
This Section includes materials for process and utility equipment used in onshore operations for
surface facilities.
The materials selected shall meet minimum toughness requirements at the minimum design
temperature during low temperature events such as blowdown. The low temperature requirements of
materials are covered in detail by DEP 30.10.02.31-Gen. and DEP 31.38.01.15-Gen., which refers to
ASME B31.3.
6.2
Vessels and piping
Shall be in accordance with DEP 39.01.10.12-Gen, Section 3.2.5 with the following amendments.
a) Replace Table 3, with the following Table 6.1 below.
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Table 6.1: Vessels and piping
Internal Environmental conditions
Materials
selection
for
(10)
piping
Piping
(1)
class
Any*
CS with 1
mm (1/32
in) CA
1410,
1450, or
1470
As for piping
Any*
CS with 3
mm (1/8
in) CA
1430 or
1490
As for piping
Any*
CS with 3
mm (1/8
(2)
in) CA .
CS with
glassflake
lining if
only
limited life
is
(3)
required
1430 or
1490
As for piping + glass
(4)
flake
lining .
Temperature limit is
for the glass flake
lining.
Any*
SSC and
HICresistant
steel with
1 mm
(1/32 in)
CA
1420 or
1460
As for piping
Any*
SSC and
HICresistant
steel with
3 mm
(1/8 in) CA
1440
As for piping
Any*
SSC and
HICresistant
steel with
3 mm
(1/8 in) CA
(2) 3)
.
1440
As for piping + glass
(4)
flake
lining .
Temperature limit is
for the glass flake
lining.
3430
CS clad with AISI
316L or solid AISI
(5)
316L
or
22Cr
(5)
Duplex
SLC
mm
(in)
Temp
°C
(°F)
pH2S
mbar
(psi)
Cl
ppm
<1
(<1/32)
<200
(<392)
<3.5
(<0.05)
<3
(<1/8)
<200
(<392)
<3.5
(<0.05)
3 to 6
(1/8 to 1/4)
<1
(<1/32)
<3
(<1/8)
<80
(<176)
<200
(<392)
<200
(<392)
<3.5
(<0.05)
<100
(<1.45)
<100
(<1.45)
Vessel material
Comments
SLC
can
be
reviewed
based
on
inspection
frequency.
3 to 6
(1/8 to 1/4)
<80
(<176)
<100
(<1.45)
≥6
(≥1/4)
<120
(<248)
<3.5
(0.05)
≥6
(≥1/4)
<60
(<140)
<15
(<0.22)
60660
AISI 316L
3430
CS clad with AISI
316L or solid AISI
(5)
316L
or
22Cr
(5)
Duplex
≥6
(≥1/4)
<155
(<311)
<15
(<0.22)
<37000
AIS 316L
3430
CS clad with AISI
316L or solid AISI
316L or 22 Cr Duplex
Limit valid for pH
>3.8
≥6
(≥1/4
90
<2.0
165000
22Cr
Duplex
3832
Clad AISI 316L
pp CO2 < 1.5 bar
120
<2.0
170000
22Cr
Duplex
3832
Clad AISI 316L
pp CO2 < 0.43 bar
≥6
(≥1/4
120000
AISI 316L
Page 38 of 63
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≥6
(≥1/4)
<200
(<392)
<10
(<0.15)
160000
≥6
(≥1/4
<120
(<248)
<350
(<5.08)
<1 g/l
(1000
ppm)
22Cr
Duplex
22Cr
Duplex
Revision: 0
Effective: September-2014
3832
CS clad with AISI
(13)
904L
or solid 22Cr
(5)
Duplex
3832
CS clad with AISI
316L or solid 22Cr
(5),
Duplex
≥6
(≥1/4)
<200
(<392)
<20
(<0.30)
<160000
Super
Duplex
CS clad with AISI
(13)
904L
or solid 22Cr
(5)
Duplex
≥6
(≥1/4
<200
(<392)
<80
(<1.16)
<30330
Super
Duplex
CS clad with AISI
(13)
904L
or solid 22Cr
(5)
Duplex
≥6
(≥1/4)
<200
(<392)
<1,000
(<14.5)
<1
(640 ppm)
Super
Duplex
≥6
(≥1/4)
≥6
(≥1/4)
≥6
(≥1/4)
≥6
(≥1/4)
<200
(<392)
< 60
<200
(<392)
<200
(<392)
<20
(<0.30)
< 4000
<14,000
(<203)
<36,000
(<522)
<160,000
< 200
(120)
Super
Duplex
6Mo
<160,000
Alloy 825
<160,000
Alloy 28
(pCO2<25
bar (363
psi))
PDO has previous
issues with the
application
of
904L
grade,
CFDH approval is
required to select
904L as a material
of construction
PDO has previous
issues with the
application
of
904L
grade,
CFDH approval is
required to select
904L as a material
of construction
CS clad with AISI
316L or solid 22Cr
Duplex (5)
CS clad with AISI
904L or Alloy 825
Clad.
CS clad with Alloy
825 or solid 6Mo
PDO has previous
issues with the
application
of
904L
grade,
CFDH approval is
required to select
904L as a material
of construction
Laboratory
qualification tests
have shown 6 Mo
might
be
susceptible
to
pitting under high
chloride (>50,000
ppm)
in
sour
service.
Weld overlay of
alloy 825 shall not
be considered as
material
for
vessels and piping
CS clad with Alloy
825 or Alloy 625 or
solid Alloy 825
Weld overlay of
alloy 825 shall not
be considered as
material
for
vessels and piping
CS clad with Alloy
825 or Alloy 625 or
solid Alloy 825
Weld overlay of
alloy 825 shall not
be considered as
material
for
vessels and piping
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≥6
(≥1/4)
<240
(<464)
<30,000
(<435)
<160,000
Alloy
(8)
625
CS clad with Alloy
625 or solid Alloy 625
≥6
(≥1/4)
<100
(9)
(<212)
Any*
Any*
GRP
GRP
Weld overlay of
alloy 825 shall not
be considered as
material
for
vessels and piping
Note: Cladding and weld overlay are two different processes.
6.3
Piping, fittings valves and other components
Shall be in accordance with DEP 39.01.10.11-Gen, DEP 39.01.10.12-Gen, Section 3.2.6 and DEP
30.01.10.15-Gen. All the applicable MESC SPEs shall be followed for piping, fittings, valves and
other components.
6.4
Small bore instrument, hydraulic and chemical injection tubing
Shall be in accordance with DEP 39.01.10.12-Gen, Section 3.2.7, Table 4.
6.5
Heat exchangers
If carbon steel plus inhibition is used in upstream piping, the vessel exchanger shall be made of a
suitable CRA.
6.5.1 Shell-and-tube heat exchangers
The selection of materials for direct water coolers shall be derived from the materials selected for the
adjacent process piping and the coolant (Table 6.2).
Oxygen contamination of closed circuit cooling systems has been a problem in many cases, and
carbon steel shall only be used if oxygen can be successfully kept out of the system, or where a
sufficient corrosion allowance, based on a good estimate of corrosion rate, can be used. Where Ti is
selected, it SHALL [PS] not be coupled directly to carbon steel.
Glycol reboilers are addressed in DEP 39.01.10.12-Gen, Section 3.2.9, Table 8.
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Table 6.2: Shell-and-tube heat exchangers
Cooling water
Incoming pipe
material
(Table 3)
Tubes
Tubesheet and
Channels
Shell, baffles
and
tie-rods
Non-corrosive coolant on
tube side.
On shell side closed circuit
(no 02, inhibited,
(6)
monitored)
Carbon steel
SLC<1
Carbon steel
Carbon steel
Carbon steel
Carbon steel
SLC>1
Upgrade to
appropriate
stainless steel
(not martensitic).
Carbon steel with
corrosion
allowance, or
corresponding
stainless steel,
solid or clad.
Carbon steel
22Cr Duplex
22Cr Duplex
22Cr Duplex
Carbon steel
Super Duplex
Super Duplex
Super Duplex
Carbon steel
316L
316L
316L solid or clad
Carbon steel
6Mo
6Mo
6Mo solid or Alloy
825 solid or clad
Carbon steel
Alloy 625
Alloy 28
(5)
Alloy 825 solid or
clad
Carbon steel
Alloy 825
Alloy 825
Alloy 825 solid or
clad
Carbon steel
Alloy 625
Alloy 625
Alloy 625 clad
Carbon steel
Carbon steel
Super Duplex
Super Duplex
Carbon steel
22Cr Duplex
Super Duplex
Super Duplex
22Cr Duplex
Super Duplex
Super Duplex
Super Duplex
Super Duplex
6Mo
6Mo
6Mo
6Mo or 825 clad
Alloy 28
Alloy 625
Alloy 625 solid or
(3)
clad
Alloy 825 clad
Alloy 825
Alloy 625
625 solid or clad
825 clad
Alloy 625
Alloy 625
625 solid or clad
625 clad
Any
C276
Ti
Chlorinated aerated
seawater on tube side.
Max. temperature
<30 °C (<86 °F)
Chlorinated aerated
seawater on tube side.
Max. temperature
>30 °C (>86 °F)
NOTES: (1), (2)
(4)
or C22 or
(3)
(3)
(4)
C276 solid or
(3)
clad or Ti solid
(3)
or clad
As inlet pipe,
solid or clad
Notes not used
(3) Clad tubesheets assume the cladding is on the seawater side and tubes are front welded. The suitability of the
tubesheet carbon steel base metal for exposure to the process fluids shall be considered.
(4) Alloy C276 tubes have been known to fail due to the formation of a crevice under chloride-rich deposits. The
likelihood of the formation of such deposits should be duly considered before selecting a material.
(5) Alloy 28 shall be limited to a pH2S below 36000 mbar (522 psi).
(6) When cooling gas, the definition of non-corrosive service may include an assessment of the gas dew point and
corrosion within the tubes, provided appropriate operating controls are in place. Dew point assessment shall
consider field ramp-up flow rates, duration, and minimum controllable heat transfer capacity.
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6.5.2
Plate coolers
Table 6.3: Plate coolers
Service
Seawater cooling oil or
produced water
Max temp. °C
(°F)
Incoming
pipe
Plate material
30
(86)
625, 825, 28,
GRP
625
6Mo, GRP
6Mo
All others
Super duplex
Any
Alloy 625, Alloy C276, or titanium
200
(392)
Closed circuit water cooling
crude oil/gas
NOTE:
60
(140)
AISI
316L
subject
to
the
environmental limitations given in
(2.2.1)
200
(392)
As adjacent produced fluid piping.
Otherwise, Alloy 825, Alloy 625,
Alloy C276, or titanium
See DEP 39.01.10.12-Gen, Section 3.2.9.
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6.5.3 Air cooled heat exchangers
Materials for air cooled heat exchangers shall be per Table 6.4 which refers to external limits. For
internal limits refer to Table 6.1 in Section 6.2.
Table 6.4: Air cooled heat exchangers
Incoming pipe
(Table 6.1)
Tube material
Header Box material
Carbon steel SLC<1
Carbon steel with fully
extruded aluminium fins
Carbon steel fully coated
with TSA, or upgrade to
appropriate stainless steel
below depending on
maximum temperature
Carbon steel SLC>1
Upgrade to appropriate
stainless steel below
depending on maximum
temperature
Carbon steel with
corrosion allowance fully
coated with TSA, or
upgrade to appropriate
stainless steel below,
depending on maximum
temperature
316L
316L
316L
50 (122)
(1)
22Cr Duplex
22Cr Duplex
22Cr Duplex
80 (176)
(1)
Super Duplex
Super Duplex
Super Duplex
110 (230)
(1)
316L
316L with fully extruded
(2)
aluminium fins
316L fully coated with TSA
or 316L internally clad
carbon steel
120 (248)
(2)
22Cr Duplex
22Cr Duplex with fully
(2)
extruded aluminium fins
22Cr Duplex fully coated
with TSA
190 (374)
(2)
Super Duplex
Super Duplex with fully
(2)
extruded aluminium fins
Super Duplex fully coated
with TSA
190 (374)
(2)
6Mo
6Mo
Alloy 625
NOTES
(3)
Alloy 28
Max. temp.
°C (°F)
6Mo
200 (392)
(3)(4)
Alloy 28
200 (392)
(3)
Alloy 825
200 (392)
(3)
Alloy 625
200 (392)
Alloy 825
Alloy 825
Alloy 625
Alloy 625
(1)
The maximum temperatures are dictated by the risk of external chloride SCC, see (2.2.1).
(2)
These temperatures only apply to heat exchangers with coated tubes that have fully extruded aluminium
fins.
(3)
Likely to have extruded aluminium fins for heat transfer requirements, but not required as part of the
corrosion design as these materials are resistant to Chloride SCC up to at least 200 °C (392 °F).
(4) Alloy 28 ishall be limited to a pH2S below 36000 mbar (522 psi)
If extruded aluminium fins are used on tubes, no external corrosion allowance is required. There shall
be no exposed steel tube area for both CS and CRA tubes. Achieving no exposed steel at the
tubesheet end is often problematic and requires special attention. For the fins, aluminium Alloy 5083
(UNS A95083) has the best reported performance.
If coating is required on the header boxes, the tubesheet shall be TSA coated prior to inserting the
tubes in the tubesheet, with any repairs to the coating carried out as each row of tubes is inserted.
Page 43 of 63
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6.5.4
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Compact coolers (printed circuit heat exchangers)
Printed circuit heat exchangers have very fine channels, which restricts them to relatively clean
duties (such as gas or NGL cooling). Upstream filters shall be specified and maintained to reduce the
risk of channel plugging.
Materials shall be selected to withstand erosion in the small channels and also crevice corrosion at
the anticipated service condition.
Material choice is limited by the Manufacturers and the manufacturing method to AISI 316L, 22 Cr,
Cu or Ti.
6.6
Glycol dehydration system
Shall be in accordance with DEP 39.01.10.12-Gen, Section 3.2.9, Table 8. For severe sour service,
materials selection shall be peer review and approved by TA2 MCI from function.
6.7
Flare & relief systems
Shall be in accordance with DEP 39.01.10.12-Gen, Section 3.2.10, Table 9.
6.8
Rotating equipment
Shall be in accordance with DEP 39.01.10.12-Gen, Section 3.2.11.
Add the following table in the first paragraph related to rotating equipment
a)
b)
c)
6.9
Compressors for PDO shall be designed for sour service.
For dry gas environment confirmed by process. Carbon steel suitability to be
defined based on corrosion assessment vs. % of incidental wet scenarios (upset
conditions leading to free water presence).
For wet or significant SLC, CRA materials shall be specified in sour service as per
Table 5.
Pumps
Centrifugal pumps shall be in accordance with DEP 31.29.02.30-Gen.
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6.10 Bolting
Shall be in accordance with DEP 39.01.10.12-Gen, Section 3.2.12, Table 10 and Table 11.
Add the following notes after second paragraph:
•
PTFE coating may be used up to an operating temperature of 200 °C (392 °F).
•
Quality control procedures shall be developed to cover PTFE handling during
transportation, storage and installation to avoid coating damage.
•
Cadmium plated bolts shall not be used.
6.11 Elastomer Seal Selection
Shall be in accordance with DEP 39.01.10.12 -Gen, Appendix C.
6.12 Pipelines
Pipelines materials selection shall cover the construction materials for below systems:a) Process pipelines
b) Dry hydrocarbon pipelines
c) Water injection pipelines
Carbon steel is widely used for pipelines with or without corrosion inhibition. The corrosion allowance
shall be calculated using DEP 30.10.02.14-Gen. There are two applicable standards for carbon steel
linepipe, according to whether it is critical or non-critical service. Carbon steel line pipe shall conform
to the following standards as appropriate:
•
Critical Service
DEP 31.40.20.37-Gen.
•
Non-Critical Service
DEP 31.40.20.35-Gen.
Guidance on the evaluation of pipeline service criticality is given in DEP 31.40.00.10-Gen.
For linepipe that is required to be resistant to external CSCC, refer to Section 5.3.1in addition to the
information contained in DEP 31.40.20.37-Gen.
When required by the design or welding code, the strain aging shall be applied as part of the weld
procedure qualification program.
CRA line pipe shall conform to the following standards:
Table 6.5: CRA Line pipe standards
Solid Pipe:
Duplex and Super Duplex Stainless Steel Line
pipe
Solid Pipe:
Weldable Martensitic Stainless Steel (13Cr and
Super
13Cr
linepipe).
All applications of weldable martensitic steel shall
have materials testing of welded product form to
confirm resistance against embrittlement and
stress corrosion cracking.
The Principal's
materials and corrosion expert shall be consulted.
(1)
DEP 31.40.20.34-Gen.
DEP 31.40.20.36-Gen.
production.
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Clad Pipe:
Metallurgically bonded clad layer
CRA Lined
Pipe:
CRA lined (mechanically bonded) steel pipe will
require a supplementary project specification in
addition to DEP 31.40.20.32-Gen.
NOTES
DEP 31.40.20.32.Gen
(1) Weldable Martensitic stainless steel materials is not considered suitable
materials option for PDO due to high chloride and H2S
Suitable materials for process pipelines are given in Table 6.6 and shall be in accordance with DEP
39.01.10.11-Gen, DEP 39.01.10.12 and DEP 30.01.10.15-Gen.
Table 6.6: Process pipelines
Item
Onshore/subsea
pipelines
Conditions
(1)
SLC
Temp.
pH2S
Cl
mm (in)
°C (°F)
mbar (psi)
g/l
(2)
Material
<8
(<3/8)
<200
(<392)
<3.5
(<0.05)
Any
CS
with
appropriate
corrosion allowance
<8
(<3/8)
< 200
(<392)
< 100
(<1.45)
Any
SSC and HIC resistant CS
with appropriate corrosion
allowance
N/A
<140
(<284)
0
(0)
<100
Weldable
martensitic
(6)
stainless steel
N/A
<200
(<392)
0
(0)
<12
Weldable
martensitic
(6)
stainless steel
N/A
< 120
(<248)
<3.5
(<0.05)
<120
CS clad with AISI 316L
N/A
<200
(<392)
<10
(<0.15)
<150
22Cr Duplex
N/A
<155
( <311)
15
(<0.22)
<38
N/A
60
(140)
15
(<0.22)
60
CS clad with AISI 316L
N/A
<200
(<392)
<20
(<0.29)
<150
Super duplex
N/A
<200
(<392)
<80
(<1.16)
<30
Super duplex
N/A
<200
(<392)
<350
(<5.08)
<0.6
22Cr Duplex
N/A
<200
(<392)
<1,000
(<14.50)
<0.6
Super duplex
N/A
<200
(<392)
<22,000
(<319)
<120
CS clad/lined with Alloy 825
N/A
<240
(<464)
<30,000
(<435)
<120
CS clad/lined with Alloy 625
N/A
<100
(<212)
N/A
N/A
GRP (see flowline
metallic table)
N/A
<60
(<140)
N/A
N/A
RTP
(Reinforced
thermoplastic pipes) (see
flowline non metallic table
6.7
(3)
(4)
CS clad with AISI 316L
(4)
non
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Item
Conditions
Notes:
(1)
Material
SLC
Temp.
pH2S
Cl
mm (in)
°C (°F)
mbar (psi)
g/l
N/A
<60
(<140)
N/A
N/A
Thermoplastic
lined
CS
(see flowline non metallic
(5)
table 6.7
N/A
<200
(<392)
<22,000
(<319)
<200
CS clad/lined with Alloy 825
N/A
<200
(<392)
<22,000
(<319)
<200
CS clad/lined with Alloy 825
(1)
For some Corrosion Resistant Alloys, e.g., AISI 316L, more detailed sour service SCC limits can be
found in DEP Part 4.
(2)
If there is any chance of H2S increase during the lifetime (e.g., due to reservoir souring) order SCC
and HIC resistant CS, even if the pH2S is below 3.5 mbar (0.05 psi).
(3)
These limits are valid for pH ≥ 3.8.
(4)
The recent CP studies completed revealed that the optimum CP level in DSS lines is recommended to
be adjusted to a potential no less negative than -650 mV. This value is in the range recommended by
ISO 15589 and DEP 30.10.7310 for DSS structures. Previous level ranged from -850 to -1150 mV
increased the risk of internal stray current. This value will reduce significantly the amount of internal
stray current, reducing the risk of failures in the IJ.
(5)
Higher temperature applications are possible – refer to DEP 31.40.30.34-Gen. for higher temperature
thermoplastic liners.
(6)
Higher temperature applications are possible – refer to DEP 31.40.30.34-Gen. for higher temperature
thermoplastic liners.
6.13 Dry Hydrocarbon flow lines:
Shall be in accordance with DEP 39.01.10.12-Gen, Section 3.3.3.
6.14 Flowlines
Flowline material selection philosophy shall be as per section 2.1 of SP-2156. For non-metallic flow
line material selection shall be performed in accordance with Table 6.7. For metallic materials
flowlines shall be as pipeline Table 6.6.
Table 6.7: Limitations of non-metallic materials
Required Service
GRE
HDPE lined CS
(SP-2092)
(SP-2094)
Y
4
FBE coated CS
Flow lines
Reelable Pipes
(SP-2416)
(DEP
31.40.1020-Gen)
Y
Y
Y
Y
Y
Y
Y
Wet Gas
4
Y
X
X
X
Multiphase
Y
Y
Y
Y
Dry gas
X
X
X
X
Max 7 mol%
Max 3 mol%
Region 1 as per
ISO 15156
No limit
No limit
Corrosivity < 3
1
mm/year.
Water
Oil
H2S
CO2
Max 1 mol%
2 (add
permeation issue)
No limit
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Chlorides
>1% Acide
exposure
pH
No limit
No limit
Corrosivity < 3
1
mm/year.
No limit
♦
♦
X
♦
Corrosivity < 3
1
mm/year.
3.5 to 12
3
Sand > 10 g/m3
GOR
Production
Chemical
Wax and Asphalt
Fluid velocity
Design pressure
3
3.5 to 12
X
3.5 to 12
5
5
Y
No specified limit
300
X
Y
Y
5
Y
5
X
Up to 10 m/sec
liquid velocity
10 m/s gas
velocity
As per SP2092
Max 180 bar
70deg C for
water service
and 65 deg C for
oil service
Y
300
Y
4 m/sec liquid
velocity
3
Limited by rapid
decompression
Y
Y
5
2
2-4 m/sec
Limited by rapid
decompression
5
Y
Up to 10 m/sec
liquid velocity
70bar Max
65deg C
(This refers to
Maximum
operating
temperature)
Design
Temperature
Max 100 deg C
Maintenance
pigging
X
X
X
X
Viscosity
Shall be in Liquid
form
Shall be in Liquid
form
Shall be in Liquid
form
Shall be in Liquid
form
Design life
> 20 years
20 years
10 years
Max 2 years
Buried
pipeline/flowlines
Y
Y
Y
Y
Above ground
pipeline/flowlines
X
Y
Y
Y
X
Y limited by
corrosion rate
and piping
configuration
Y limited by
corrosion rate and
piping
configuration
X
Y only water/
burried close drain
Y limited by
corrosion rate
and piping
configuration
Y limited by
corrosion rate and
piping
configuration
X
Manifolds
On plot piping
8
(This refers to
Maximum
operating
temperature)
90 deg C
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Pressure Vessel
Tanks
X
X
X As SP 1246
X
Internal liner
X
X As SP 1246
X
Notes:
1. For service life corrosion requirements refer to section 4.4.
2. Pipe materials can work however, the connections are metallic and the limitations shall
be checked with Materials and corrosion engineer before use.
3. For fluids having PH out of this range shall be referred to Materials and corrosion TA2 for
review and recommendation.
4. Electrical conductivity of the fluid shall not be less tahn 10,000pS/m
5. Flow assurance study shall demonstrate that the produce sand, wax, asphat, etc. will
not have any erosion effect in pipe service and that solid removal will not be required
during the life time of the project. No test data viable. Any sand production areas it is not
recommended to use the non metallic materials without study. Consult MCI Engineer.
6. Paffin wax and Asphalt deposits may have swelling effect on PE materials. Consult
Materials & Corrosion Engineer before selection.
7. Design pressure changes with size & connections. Max Design temperature changes
with type of curing systems used. Refer to SP2092-1 for more details.
8. Compatibility test shall be carried out
Symbols:
Y – The material may be considered within the boundaries specified in the above table
♦ - No test data or filed experience available. Consult with the PDO materials function TA2 authority
for more details.
X – Shall not be used.
6.15 Water Injection flow lines
Shall be in accordance with DEP 39.01.10.12-Gen, Section 3.3.4.
6.16 Flexibles
Shall be in accordance with DEP 39.01.10.12-Gen, Section 3.3.6. Corrosion Prevention and Control
for Water Injection Systems shall be per DEP 31.01.10.11-Gen.
6.17 Multi Selective Valves (MSV’S)
S. No.
Body
1
2
3
4
CS
CS
CS
CS+3mm two pass undiluted
316L weld overlay
Internals
CS
316L
825
316L
Skid piping
CS
CS
CS
CS+3mm two pass 316L weld overlay
or
solid SS316L
or
CS+1mmCA+rotolining
or
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5
6
7
8
9
CS+3mm two pass undiluted
(1)
625 weld overlay
CS+3mm two pass undiluted
625 weld overlay
DSS
316L
DSS
SDSS
316L
DSS
SDSS
625
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CS+3mmCA + FBE coated
DSS
CS+625 weld overlay
or
solid 825
or
CS+1mmCA+rotolining
or
CS+3mmCA + FBE coated
316L
DSS
SDSS
NOTE (1) DSS weld overlay is feasible but the application requires MIC TA approval.
** Material limits to be in accordance with Table 3 (vessel/piping materials)
6.18 Utilities
Materials selection for utilities shall be in accordance with DEP 39.01.10.12-Gen, Section 3.4. Utilities
materials selection shall cover the construction materials for below systems and the criteria for
individual selection is as stated in DEP 39.01.10.12 -Gen
•
•
•
•
•
•
•
•
•
•
•
Water systems
Fresh potable water
Brackish/seawater for service water system
Closed circuit cooling water
Fire fighting system
Water injection system
Tubing materials and completion accessories for water injection and disposal wells
Seawater caissons and dip tubes
Inhibitors and other chemicals (shall be in accordance with DEP 39.01.10.12-Gen, Table
22.
Miscellanies Utilities systems (e.g. air system, instrumentation, etc) shall be in accordance
with DEP 39.01.10.12-Gen, Table 23.
Diesel fuel systems (shall be in accordance with DEP 39.01.10.12-Gen, Table 24)
6.19 Steam Injection systems
DEP 39.01.10.12-Gen, Section 3.5. shall not be used for the selections of steam projects. The
construction materials recommendations included in the DEP 39.01.10.12-Gen, Section 3.5.1, Table
25, is based on experience in North America and Canada where continuous high temperature
production of heavy oil with typical low corrosion have been observed. This is not applicable for PDO
steam operations. Materials selection shall be completed based on standard material selection
process as specified in Section.3 of this SP.
6.20 ENHANCED OIL RECOVERY (EOR)
Materials selection for enhanced oil recovery is based primarily on proven operating experience.
Where CRAs are required, process conditions shall be used to determine the type of CRA from the
relevant tables in this standard. The materials selection shall be endorsed by the Principal’s Materials
and Corrosion TA1.
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MATERIALS SELECTION STUDY ROLES & RESPONSIBILITIES
Materials selection report for all SELECT phase shall be carried by PDO Materials and Corrosion
engineering discipline (Function).
During the DEFINE and EXECUTE phase, materials and corrosion deliverables shall be prepared by
materials, corrosion and welding specialists that have been assessed and approved by PDO
Materials and Corrosion Engineering discipline (UEOC) prior the start of FEED and DD studies.
FEED and DD materials selection report shall be endorsed and approved by PDO Materials and
Corrosion Engineering discipline (UEOC) in peer review session following the requirements indicated
in Section 4.1. Materials selection peer review sessions shall be organized by the Materials and
Corrosion Engineers from the projects or the author of the report and ensuring participation from
Process, Mechanical, Rotating and Pipeline engineering.
8
CONTENT OF MATERIALS SELECTION REPORTS
8.1
SELECT Phase
Materials selection report shall contain the following but not limited to:
a) Executive Summary
b) Project Introduction and Description
c) Purpose of the document
d) Abbreviations and Definitions
e) Project documents referred to
f) Standard referred to
g) Design Basis
h) Corrosion Predictive Modelling
i) Erosion Assessment
j) Materials Selection Discussion
k) Recommended Materials Selection
l) Specific Materials Manufacturing / Fabrication Requirements
m) Specific Corrosion Control Requirements
n) Threat-Barrier Matrix
o) Outline of Corrosion Monitoring Methods
p) Technical References
q) Attachments / Appendices
8.2
DEFINE Phase
During the DEFINE phase Materials selection report shall include detailed assessments and
specifications to develop required materials and corrosion testing program. The detailed assessment
should be carried out as per the sequences of the process flow diagrams. The materials selection
shall discuss the process description for each system and the basis for the materials selection shall
be documented. All the unknowns identified during select phase shall be addressed, documented
and close.
Typical template with the required content for a materials selection in DEFINE phase is shown in
Appendix D.
Materials selection report shall consider and document all the process information and assumptions
for each stream and shall be presented as per the template included in appendix E.
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8.3
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EXECUTE Phase
Required content shall be as per DEFINE phase and shall be updated to as approved for
construction status for handover.
9
CORROSION MANAGEMENT FRAMEWORK
Elements of corrosion management framework and corrosion management manual (CMM) shall be
in accordance with DEP 39.01.10.11- Gen.
Template for typical CMF is shown in Appendix C.
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APPENDIX A: Basic Information required and factors effecting materials selection
Table A.1: Basic information required and factors effecting materials selection
Basic Information Required for Materials Selection for Hydrocarbon Systems
Field Name
Design Life
Essential Information Required for materials Selection
Equipment
Carrying
produced
fluids
Utility Systems
Equipment
carrying sea
water
including
water injection
and fire water
√
Presence of free Water
Co2 content of Gas
mol%
√
√
H2S content of Gas
mol%
√
√
Dissolved H2S
ppm
√
√
Dissolved Co2
ppm
√
√
Elemental sulphur
ppm
√
√
√
Maximum Operating Pressure
Bara
√
√
√
Maximum design pressure
Bara
√
√
√
Maximum Operating Temperature
C
√
√
√
Maximum deign Temperature
C
√
√
√
Ambient Temperature
C
Multiphase/gas/oil
√
√
√
√
√
√
√
√
√
Type of fluid
Flow type
Stratified/ annular/
slug etc
Gas flow Rate
mIn Sm3/d
√
√
Oil Flow rate
m3/d
√
√
Water flow Rate
m3/d
√
√
Liquid Velocity
m/s
√
Debris present
yes/No
√
Inside diameter
m
√
Length
Km
√
Water cut
%
√
GOR
√
√
√
√
Reservoir Date
Reservoir pressure
√
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reservoir temperature
√
Bubble point pressure
√
Reservoir fluid density
√
Sand and silt production
√
Mercury
√
Revision: 0
Effective: September-2014
Water analysis
type of water
Cond/form/iron
saturated
√
√
Bicarbonates
ppm
√
√
Sulphates
ppm
√
√
chlorides
ppm
√
√
Dissolved Fe2+ in Water
ppm
√
√
Total dissolved solids
g/l
√
√
Oxygen in water
ppm
√
√
Total suspended solids
ppm
√
√
√
√
pH
Sodium
ppm
√
√
ORGANIC ACIDS
ppm
√
√
Formic acid
ppm
√
√
Acetic acid
ppm
√
√
Propionic acid
ppm
√
√
Mercury
ppm
√
√
kg/kmol
√
Fluid Properties
Gas molecular weight
Gas compressibility factor
√
API gravity
√
Oil density
kg/m3
√
Oil viscosity @ reference temp
Ns/m2
√
Oil viscosity reference temp
deg C
√
Gas liquid surface tension
N/m
√
Water solubility in oil C1
Water solubility in oil C2
Additional information required for service life corrosion calculation
The full stream molar composition Whether inhibitor are
to be injected.
√
Water content in glycol (where added for corrosion or
hydrate control)
√
HCO3 content of water
√
projected operating pressure and temperature profile
over life of project
√
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Heat transfer coefficient of coating system used
(pipeline) reservoir type ( carbonate or sandstone)
for water injection system the anticipated amount and
particle size of corrosion products are often require to
manage well sand control efficiency
Inhibition philosophy
Revision: 0
Effective: September-2014
√
√
√
√- Inputs are required
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APPENDIX B: Risk Assessment
Corrosion risk assessment forms an important part of materials selection and risk based inspection.
It is necessary to perform these activities in a structured manner to ensure that all credible materials
and corrosion related threats are evaluated.
The corrosion risk assessment is, essentially, an analysis of the controls in place for preventing the
realisation of a loss of primary containment top event via the corrosion threats that may be identified
by a bow tie analysis as shown in Figure 1. Selection of the corrosion threats can be made from the
listing below. Users must ascertain the threats that apply in each case under consideration, and
positively discount those that do not apply. It is not sufficient to simply disregard a listed threat
without any justifying statement in the MSR.
•
Figure 91: Generic bow-tie model
Related Business Control Documents and References
Version
Reference
Title
API RP 571
Damage Mechanisms Affecting Fixed Equipment in the
Refining Industry
Maintenance and Integrity Management – Code of
Practice
Corrosion Management Code of Practice
Corrosion Inhibitor Efficiency Limits And Key Factors,
NACE Corrosion 2011, Paper 11062
Metallic Materials – Selected Standards
2 Edition
Carbon Steel Corrosion Engineering Manual For
Upstream Facilities
Materials For Use In H2S-containing Environments In
Oil And Gas Production (Amendments And
Supplements to ISO 15156:2009)
February 2012
CP-114
CP-208
Crossland, A., et al
DEP Specification
30.10.02.11-Gen
DEP Specification
30.10.02.14-Gen
DEP Specification
30.10.02.15-Gen
nd
Revision 5.0
1.0
February 2013
February 2013
Page 56 of 63
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DEP Specification
30.10.02.31-Gen
DEP Specification
31.38.01.29-Gen
DEP 31.38.01.84-Gen
DEP Informative
39.01.10.11-Gen
DEP Specification
39.01.10.11-Gen
Energy Institute
Energy Institute
European Federation Of
Corrosion EFC
GU-475
GU-611
GU-637
GU-672
ISO 15156
Smart, J
SP-2041
SP-2062
UK HSE
UK HSE
Revision: 0
Effective: September-2014
Metallic Materials – Prevention Of Brittle Fracture In
New Assets
Pipe Supports
February 2013
Piping Classes – Service And Materials Selection
Index
Selection Of Materials For Life Cycle Performance
(Upstream Facilities) – Materials Selection Process
Selection Of Materials For Life Cycle Performance
(Upstream Facilities) – Materials Selection Process
Guidance for corrosion management in oil and gas
production and processing
Guidelines for the Avoidance of Vibration Induced
Fatigue Failure in Process Pipework
Publication 46 – Amine Unit Corrosion In Refineries
February 2013
Corporate Flowline Materials Selection Guideline
PDO Engineering Standards and Procedures
Sour Gas Wells Completion Materials Selection
Guidelines
Produced Water Analysis Requirement
Petroleum and natural gas industries – Materials for
use in H2S-containing environments in oil and gas
production – All parts
Flow Velocity Required for Solid Particle Movement in
Oil & Gas Pipelines, NACE Corrosion 2009, Paper
09469
Specification for Cracking Resistant Materials in H2S
Containing Environment
Specification for HSE Cases
Research Report 320: Elastomers for fluid
containment in offshore oil and gas production:
Guidelines and review
http://www.hse.gov.uk/research/rrpdf/rr320.pdf
Research Report 485: Elastomeric seals for rapid gas
decompression applications in high pressure services
http://www.hse.gov.uk/research/rrpdf/rr485.pdf
Version 1.0
18a
Revision 1.0
February 2013
February 2013
February 2013
May 2008
January 2008
2007
Revision 0
nd
2 edition with
Technical
Circulars
3.0
1.0
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APPENDIX C: CMF template
Typical Template for
CMF.xlsx
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APPENDIX D: Feed and Detailed Design MSR minimum standard requirements
template
Materials Selection Report (MSR)
FEED Stage
INDEX
1. PROJECT INTRODUCTION................................................................................................
2. PROJECT DESCRIPTION...................................................................................................
3. PURPOSE OF THE DOCUMENT .......................................................................................
4. ABBREVIATIONS ...............................................................................................................
5. STANDARDS AND PROJECT DOCUMENTS ...................................................................
5.1 Company Standards and Reference Documents ..............................................................
5.1.1 Company Asset Integrity Management Documents...........................................
5.1.2 Company Standards, Specifications and Procedures........................................
5.2 Project Documents..............................................................................................................
5.2.1 Mechanical .........................................................................................................
5.2.2 Pipelines .............................................................................................................
5.2.3 Piping...................................................................................................................
5.2.4 Process................................................................................................................
5.2.5 Structural .............................................................................................................
5.2.6 Materials & Welding ..............................................................................................
5.3 International, Regional, National and Industry Standards ..................................................
5.3.1 International Standards .......................................................................................
5.3.2 National Standards................................................................................................
5.3.3 Industry Standards ...............................................................................................
5.4 Document References .........................................................................................................
6. FIELD AND PROJECT DESCRIPTION FROM A CORROSION PERSPECTIVE ................
6.1 Existing Facility Experience ..................................................................................................
6.1.1 Corrosion / Leak History........................................................................................
6.1.2 Existing Chemical Treatment & Chemical Performance.................
7. MATERIALS SELECTION AND CORROSION CONTROL BASIS.........................................
7.1 Corrosion Study Basis..........................................................................................................
7.2 Materials Selection Basis.......................................................................................................
7.3 Corrosion Risk Analysis Basis……………………………………………………………………..
7.4 Life Cycle Cost LCC Analysis Basis ………………………....................................................
8. ASSUMPTIONS, UPSETS AND UNCERTAINTIES .............................................................
8.1 Assumptions.......................................................................................................................
8.2 Uncertainties and Impact of Possible Changes ...................................................................
8.2.1 Watercut ...............................................................................................................
8.2.2 CO2 and H2S Levels ..............................................................................................
8.2.3 Temperatures and Pressures................................................................................
8.2.4 Chloride Concentration..........................................................................................
8.2.5 Sand Production.....................................................................................................
8.2.6 Elemental Sulphur .................................................................................................
8.2.7 Organic Acids ........................................................................................................
8.2.8 Additional or Altered Chemical Treatments............................................................
8.3 New Technologies and Basis for Use....................................................................................
9. Corrosion Threats ………………………………………….......................................................
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9.1 Factors Affecting Fluid Corrosivity .......................................................................................
9.1.1 “Sweet” and “Sour” Corrosion Mechanisms .........................................................
9.2 CO2 Corrosion ......................................................................................................................
9.2.1 CO2 Corrosion in Satah Field Production Facilities..............................................
9.3 The Influence of H2S on Corrosion .....................................................................................
9.3.1 Control of H2S Corrosion in Satah Field Production Facilities ............................
9.4 H2S Cracking.......................................................................................................................
9.5 Oxygen Corrosion ...............................................................................................................
9.6 Microbiologically Influenced Corrosion ...............................................................................
9.6.1 MIC Mitigation.......................................................................................................
9.7 Chloride Stress Corrosion Cracking.....................................................................................
9.8 Erosion and Erosion Corrosion ...........................................................................................
9.9 Atmospheric Corrosion........................................................................................................
9.10 Corrosion under Insulation (CUI) ......................................................................................
9.11 Preferential Weld Corrosion...............................................................................................
9.12 Sour Water Corrosion ........................................................................................................
9.13 Galvanic Corrosion.............................................................................................................
9.14 Vibration Induced Fatigue ..................................................................................................
9.15 Polythionic Acid Stress Corrosion Cracking (PASCC)........................................................
9.16 Flange Face Corrosion........................................................................................................
9.17 Brittle Fracture.....................................................................................................................
9.18 Long Running Ductile Fracture ...........................................................................................
9.19 Degradation of Non-Metallic Seals .....................................................................................
9.20 Sulphidation ........................................................................................................................
9.21 Soil Corrosion......................................................................................................................
9.22 Corrosion Mitigation for Pipelines .......................................................................................
10. EXTERNAL CORROSION CONTROL – COATING..............................................................
10.1 Onshore Plant Facilities .......................................................................................................
10.2 Topside Piping and Equipment ............................................................................................
10.3 Submerged Pipelines ...........................................................................................................
11. CATHODIC PROTECTION.....................................................................................................
11.1 Pipelines.................................................................................................................
11.2 Onshore Buried Piping, Buried Vessels and Vessel Interiors................................................
12. MATERIALS SELECTION PHILOSOPHY FOR VALVES, INSTRUMENTS AND BOLTING....
12.1 Valves...................................................................................................................................
12.2 Instrument Tubing and Fittings ..............................................................................................
12.3 Bolting ..................................................................................................................................
13. CORROSION INHIBTION AND MICROBIOLOGICAL CONTROL PHILOSOPHY ................
13.1 General..................................................................................................................................
13.2 Basis of Corrosion Inhibition Philosophy..................................................................................
13.3 Inhibitor Effectiveness and Availability.....................................................................................
13.4 Operation and Reliability..........................................................................................................
13.5 Chemical Performance.............................................................................................................
13.6 Delivery System Design............................................................................................................
13.7 Injection Locations and Equipment ..........................................................................................
13.7.1 Injection Location Considerations ..........................................
13.7.2 Associated KPIs ............................................................
13.7.3 Equipment and
Fittings.....................................................................................................
13.8 Chemical Compatibility........................................................................................................
13.9 Inhibitor Type and Indicative Injection Rates ......................................................................
13.10 Batch Inhibitor Treatment..................................................................................................
14. CORROSION MONITORING BASIS AND PHILOSOPHY (DETAILS TO BE COVERED IN CMF
DOCUMENT)
14.1 Aim ....................................................................................................................................
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14.2 Monitoring and Testing Facilities - General .........................................................................
14.3 Corrosion Monitoring Techniques and Equipment................................................................
14.4 Corrosion Coupons ..............................................................................................................
14.5 Electrical Resistance Probes ...............................................................................................
14.6 Permanent UT Monitoring Probes .......................................................................................
14.7 Bacterial Monitoring and Bioprobes .....................................................................................
14.8 Process Monitoring ..............................................................................................................
14.9 Inhibitor Residuals................................................................................................................
14.10 Submerged Corrosion Monitoring ......................................................................................
14.11 Corrosion Monitoring Instrumentation.................................................................................
14.11.1 Recommendation................................................................................................
14.12 Positioning and Spacing of Access Fittings ....................................................................
14.13 Corrosion Monitoring Manual...........................................................................................
15. PIPELINE PIGGING PHILOSOPHY (DETAILS TO BE COVERED IN CMF DOCUMENT)
15.1 General.............................................................................................................................
15.2 Control of Pyrophoric Iron Sulphide Scale..........................................................................
15.3 Operational Pigging Frequency ..........................................................................................
15.3.1 Other operational pigging requirements..............................................................
15.4 Intelligent Pigging Frequency..............................................................................................
15.5 Pigging and Corrosion Control at Low Gas Velocities ........................................................
15.5.1 Effectiveness of Continuous Inhibitor Injection
15.5.2 Capability for Operational Pigging....................................
15.5.3 Capability for Batch Inhibition between Pigs
15.5.4 Intelligent Pigging ................................................................................................
16. MATERIALS SELECTION FOR PROCESS SYSTEMS........................................................
16.1. Corrosion Rate Calculations (Stream wise)………………………………………………………
16.2. Materials Selection Options (Stream wise) ……………………………………………………….
16.3. Life Cycle Cost (LCC) Analysis (For all valid options)……..……………………………………
16.4. Corrosion Risk Analysis (For selected option) …..………………………………………………
17. MATERIALS SELECTION FOR UTILITY SYSTEMS............................................................
17.1. Corrosion Rate Calculations (Stream wise)………………………………………………………
17.2. Materials Selection Options (Stream wise) ……………………………………………………….
17.3. Life Cycle Cost (LCC) Analysis (For all valid options)……..……………………………………
17.4. Corrosion Risk Analysis (For selected option) …..………………………………………………
18. FABRICATION, WELDING AND INSPECTION REQUIREMENTS.....................................
ATTACHMENTS.........................................................................................................................
ATTACHMENT 1 INTERNAL CORROSION PREDICTION MODEL SUMMARY SHEETS........
ATTACHMENT 2 MATERIALS SELECTION DIAGRAMS (see Appendix F)
ATTACHMENT 3 CORROSION INHIBITOR TEST PROTOCOL................................................
ATTACHMENT 4 CHEMICAL TREATMENT REQUIREMENT................................
ATTACHMENT 5 INTERNAL MONITORING AND SURVEILLANCE SYSTEM SPECIFICATION.
ATTACHMENT 6 LINEPIPE AND FIELD JOINT COATING SPECIFICATION.................
ATTACHMENT 7 CATHODIC PROTECTION SPECIFICATION.....................................................
ATTACHMENT 8 PIGGING REQUIREMENTS................................................................................
ATTACHMENT 9 TECHNICAL QUERIES......................................................................................
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APPENDIX E: Template for required process information in materials selection
report.
MSR process
data.xlsx
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APPENDIX F: Materials Selection Diagrams (MSD)
The Materials Selection Diagram (MSD) shall be prepared during DEFINE phase and shall include
the information required by NACE SP0407 including the following:a) Materials selection and corrosion allowance for components and pipe line/piping systems shall
use an easily recognizable, generic materials description which shall be shown on the MSD.
b) The alloy type and minimum thickness for CRA lining or weld overlay and generic coating type for
an internal coating system shall use an easily recognizable, generic materials description which
shall be shown on the MSD
c) MSD shall be made by marking up each individual system / unit on PFS and should have colour
coding system for materials.
d) Changes in piping materials or corrosion allowances shall be clearly identified - if the change
occurs at a valve, the higher alloy (or corrosion allowance) shall be specified for the valve.
e) Mix points, third party entry points and chemical injection points shall be clearly identified.
f)
Corrosion mitigation measures applicable to a particular item or piping system (e.g. chemical
treatment, cathodic protection) shall be clearly identified.
g) If Contractor MSD does not record the above information for package licensor or Vendor units,
the licensor or Vendor shall supply their own MSD to record such information which shall then be
cross referenced in Contractor’s materials selection report.
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