SP-2161 Materials Selection & Corrosion Control for Surface Operating Process, Sep 14 - Final

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

Petroleum Development Oman LLC 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


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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1


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



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


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


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



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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4


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



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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Petroleum Development Oman LLC • • •

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


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)


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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Petroleum Development Oman LLC • • • • • • •

Select

210

Initial Materials Selection Report (including Corrosion Management Strategy) (DG3a)


and

•

•


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


Description • • • •

Define

64

MCI Failure Modes and Effects Analysis Report


and •

• • • • •

Define

297

Materials Selection Report - updated


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


and

•


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.

Page 19 of 63

Petroleum Development Oman LLC • •

Define

300

Corrosion Management Framework Preliminary

-


and

•

• • Define

302

Welding & Weld Inspection Specifications


and •


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


Description • •

Execute

Local Rule

Updated Materials Selection Report


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

Page 20 of 63


• • • • Execute

51

Set-up and Optimisation of Corrosion Control System


and • • •

Execute

77

Corrosion Inspection Management System Selection and Population


and

• • • Execute

79

Corrosion Inhibitor Selection Report


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


and


and


and


and


and


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.

•


•


•


•


Page 21 of 63


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)


and


and


and


and


and


and


and


and


and


and



•


•


•


•


•


•


•


•


•


•


• •

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

• •

Page 22 of 63

Petroleum Development Oman LLC •

•

Execute

488

Welding, Fabrication Inspection Procedures

and


and •

•

Execute

1194

Execute



Final Material selection Report


• • and

and

• • •


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


Description • •

Operate

25

Risk Based 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.

Page 23 of 63

Petroleum Development Oman LLC • •

Operate

1197



and • •

• •

Operate

1206

Materials Failure Investigation Report


and

•


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.

Page 24 of 63


4.3 4.3.1


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



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


ErosionCorrosion

Oxygen Corrosion


• 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


Microbial Induced Corrosion (MIC)


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


Hydrogen Induced Cracking

Stress Oriented Hydrogen Induced Cracking Amine Stress Corrosion Cracking Hydrogen Embrittlement Chloride Stress Corrosion Cracking


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

Page 29 of 63



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.

Page 30 of 63


5


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

<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. Page 31 of 63



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



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



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


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 (
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

Page 35 of 63



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.

Page 36 of 63

Petroleum Development Oman LLC 6


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.

Page 37 of 63


Petroleum Development Oman LLC 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


≥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


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


≥6 (≥1/4

<200 (<392)

<80 (<1.16)

<30330

Super 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


Page 39 of 63



≥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


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.

Page 40 of 63


Petroleum Development Oman LLC 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

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)

(5)

(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.

Page 41 of 63



Plate coolers

Table 6.3: Plate coolers Max temp. °C (°F)

Service Seawater cooling oil or produced water

30 (86)

200 (392) Closed circuit water cooling crude oil/gas

NOTE:

Incoming pipe

Plate material

625, 825, 28, GRP

625

6Mo, GRP

6Mo

All others

Super duplex

Any

Alloy 625, Alloy C276, or titanium

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.

Page 42 of 63



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 Alloy 625

NOTES

(3)

6Mo

Alloy 28

(3)(4)

Max. temp. °C (°F)

6Mo

200 (392)

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



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.

Page 44 of 63



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.

Page 45 of 63


Petroleum Development Oman LLC 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

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


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 CS clad with AISI 316L

(4)

non

Page 46 of 63


Petroleum Development Oman LLC 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


N/A

<200 (<392)

<22,000 (<319)

<200


(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 GRE

HDPE lined CS

(SP-2092)

(SP-2094)

Y 4

Wet Gas

4

Required Service

FBE coated CS Flow lines

Reelable Pipes

(SP-2416)

(DEP 31.40.1020-Gen)

Y

Y

Y

Y

Y

Y

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

Y

Max 1 mol%

2 (add

permeation issue)

No limit Page 47 of 63



Chlorides >1% Acide exposure pH

No limit

No limit


No limit

♦

♦

X

♦


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

Shall be in Liquid form




> 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


X

Y only water/ burried close drain



X

Viscosity Design life

Manifolds

On plot piping

8

(This refers to Maximum operating temperature)

90 deg C

Page 48 of 63


Petroleum Development Oman LLC 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. 1 2 3 4

Body 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 Page 49 of 63


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


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.

Page 50 of 63

Petroleum Development Oman LLC 7


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) b) c) d) e) f) g) h) i) j) k) l) m) n) o) p) q)

8.2

Executive Summary Project Introduction and Description Purpose of the document Abbreviations and Definitions Project documents referred to Standard referred to Design Basis Corrosion Predictive Modelling Erosion Assessment Materials Selection Discussion Recommended Materials Selection Specific Materials Manufacturing / Fabrication Requirements Specific Corrosion Control Requirements Threat-Barrier Matrix Outline of Corrosion Monitoring Methods Technical References Attachments / Appendices

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.

Page 51 of 63



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.

Page 52 of 63



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

√ Page 53 of 63

Petroleum Development Oman LLC reservoir temperature

√

Bubble point pressure

√

Reservoir fluid density

√

Sand and silt production

√

Mercury

√


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

√

Page 54 of 63


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


√

√ √

√- Inputs are required

Page 55 of 63



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

Petroleum Development Oman LLC 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


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

Page 57 of 63



APPENDIX C: CMF template

Typical Template for CMF.xlsx

Page 58 of 63



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 …………………………………………....................................................... Page 59 of 63



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 .................................................................................................................................... Page 60 of 63



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...................................................................................... Page 61 of 63



APPENDIX E: Template for required process information in materials selection report.

MSR process data.xlsx

Page 62 of 63



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.

Page 63 of 63

SP-2161 Materials Selection & Corrosion Control for Surface Operating Process, Sep 14 - Final

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