SP-2161 Materials Selection & Corrosion Control for Surface Operating Process, Sep 14 - Final
Short Description
pressure vessel sepcification for sour service for pdo...
Description
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 Page 4 of 63
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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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Petroleum Development Oman LLC 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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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 Page 8 of 63
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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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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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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 Page 12 of 63
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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 Page 14 of 63
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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
•
•
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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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Petroleum Development Oman LLC •
• •
• •
• • • • • 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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Petroleum Development Oman LLC • •
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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Petroleum Development Oman LLC
• • • • 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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Petroleum Development Oman LLC •
•
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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Petroleum Development Oman LLC • •
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 Page 25 of 63
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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, Page 26 of 63
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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 Page 27 of 63
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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 Page 28 of 63
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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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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
Revision: 0 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
316L(2) 6Mo 22Cr Duplex(3) 25Cr SuperDuplex(4)
Threshold for crevice corrosion
Negligible risk of CSCC
Significant risk of CSCC
5oC 50oC 40oC
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. Page 31 of 63
Petroleum Development Oman LLC
Revision: 0 Effective: September-2014
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.
Page 32 of 63
Petroleum Development Oman LLC
Revision: 0 Effective: September-2014
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. Page 33 of 63
Petroleum Development Oman LLC 5.2
Revision: 0 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.
Page 34 of 63
Petroleum Development Oman LLC 5.3.1
Revision: 0 Effective: September-2014
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 (
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