NACE AMPP SP0113 2023.pdf

NACE SP0113-2023
NACE SP0113-2023
Revised January 19, 2023
Pipeline Integrity Management: Methods
Selection and Implementation
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NACE SP0113-2023
©2023 Association for Materials Protection and Performance (AMPP). All rights reserved.
2
This AMPP standard represents a consensus of those individual members who have reviewed this document, its scope,
and provisions. Its acceptance does not in any respect preclude anyone, whether he or she has adopted the standard
or not, from manufacturing, marketing, purchasing, or using products, processes, or procedures not in conformance
with this standard. Nothing contained in this AMPP standard is to be construed as granting any right, by implication or
otherwise, to manufacture, sell, or use in connection with any method, apparatus, or product covered by Letters Patent,
or as indemnifying or protecting anyone against liability for infringement of Letters Patent. This standard represents
minimum requirements and should in no way be interpreted as a restriction on the use of better procedures or materials.
Neither is this standard intended to apply in all cases relating to the subject. Unpredictable circumstances may negate
the usefulness of this standard in specific instances. AMPP assumes no responsibility for the interpretation or use of
this standard by other parties and accepts responsibility for only those official AMPP interpretations issued by AMPP
in accordance with its governing procedures and policies which preclude the issuance of interpretations by individual
volunteers.
Users of this AMPP standard are responsible for reviewing appropriate health, safety, environmental, and regulatory
documents and for determining their applicability in relation to this standard prior to its use. This AMPP standard may
not necessarily address all potential health and safety problems, or environmental hazards associated with the use of
materials, equipment, and/or operations detailed or referred to within this standard. Users of this AMPP standard are
also responsible for establishing appropriate health, safety, and environmental protection practices, in consultation with
appropriate regulatory authorities, if necessary, to achieve compliance with any existing applicable regulatory require-
ments prior to the use of this standard.
CAUTIONARY NOTICE: AMPP standards are subject to periodic review and may be revised or withdrawn at any time
in accordance with AMPP technical committee procedures. AMPP requires that action be taken to reaffirm, revise, or
withdraw this standard no later than five years from the date of initial publication and subsequently from the date of each
reaffirmation or revision. The user is cautioned to obtain the latest edition. Purchasers of AMPP standards may receive
current information on all standards and other AMPP/NACE/SSPC publications by contacting AMPP Customer Sup-
port, 15835 Park Ten Place, Houston, Texas 77084-5145 (Tel: +1-281-228-6200, email: customersupport@ampp.org).
D o c um ent H ist o ry:
2023-01-19: Revised by AMPP Standards Committee 10, Asset Integrity Management
2013-03-16: Developed by NACE Task Group 401, Integrity Assessment Tool Selection

NACE SP0113-2023
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Foreword, Scope, Rationale.............................................................................................................................................7
Referenced Standards and Other Consensus Documents..............................................................................................7
Section 1 General....................................................................................................................................................13
Section 2 Definitions................................................................................................................................................14
Section 3 Documentation Requirements.................................................................................................................19
3.1 Program Management...............................................................................................................19
3.2 Front End Engineering and Design (FEED) Documents............................................................19
3.3 Construction Stage Documents.................................................................................................20
3.4 Commissioning Stage Documents.............................................................................................20
3.5 Operation Stage Documents......................................................................................................20
3.6 Decommissioning and Abandonment Stage Documents...........................................................21
3.7 Failure Stage Document............................................................................................................21
Section 4 Pipeline Types..........................................................................................................................................21
4.1 Onshore production pipeline......................................................................................................21
4.2 Offshore production pipeline......................................................................................................22
4.3 Hydrotransport pipeline (oilsands).............................................................................................22
4.4 Water injection pipeline/flowline.................................................................................................22
4.5 Produced water pipeline/flowline...............................................................................................22
4.6 Slurry pipeline............................................................................................................................22
4.7 Gas transmission pipeline..........................................................................................................22
4.8 Oil transmission pipeline............................................................................................................22
4.9 Hydrocarbon-Products (Oil Product) Pipeline............................................................................22
4.10 Gas distribution pipeline.............................................................................................................23
4.11 Facility pipeline or piping............................................................................................................23
Section 5 Stages of Pipeline Life Cycle...................................................................................................................23
5.1 Front End Engineering and Design (FEED) Stage....................................................................23
5.2 Manufacturing Stage..................................................................................................................24
5.3 Construction Stage....................................................................................................................24
5.4 Commissioning Stage................................................................................................................24
5.5 Operational Stage......................................................................................................................25
5.6 Management of Change............................................................................................................25
5.7 Decommissioning/ Abandonment Stage....................................................................................25
5.8 Failure Occurrence Stage..........................................................................................................26

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Section 6 Typical Threats and Stages of Their Occurrence.....................................................................................27
Section 7 Mitigation of Typical Threats....................................................................................................................32
7.1 Material Change.........................................................................................................................32
7.2 Design Change..........................................................................................................................32
7.3 Operation Change......................................................................................................................32
7.4 External Coating........................................................................................................................32
7.5 Cathodic Protection....................................................................................................................33
7.6 Cleaning or Maintenance or Mechanical Pigging.......................................................................34
7.7 Corrosion Inhibitor......................................................................................................................35
7.8 Biocides......................................................................................................................................36
7.9 Internal Coatings and Linings....................................................................................................36
7.10 Others........................................................................................................................................37
Section 8 Integrity Assessment and Management Methods....................................................................................42
8.1 Pressure Testing........................................................................................................................44
8.2 In-line Inspection (ILI)................................................................................................................45
8.3 Direct assessment (DA).............................................................................................................50
8.4 PDCA (Plan, Do, Check, and Act)..............................................................................................52
8.5 5-M Methodology.......................................................................................................................53
8.6 Risk-Based Inspection (RBI)......................................................................................................54
8.7 Engineering Assessment...........................................................................................................55
8.8 Corrosion Assessment and Integrity Management (CAIMAN)...................................................55
8.9 New and Emerging Technologies...............................................................................................55
Section 9 PIM Method Selection..............................................................................................................................55
Section 10 PIM Program Implementation..................................................................................................................64
Other Referenced Documents........................................................................................................................................65
Bibliography .................................................................................................................................................................66
Appendix A Failure Statistics (Nonmandatory)............................................................................................................67
Appendix B Key Performance Indicators (KPI) (Nonmandatory)................................................................................70
KPI 1 Segmentation of Infrastructure...................................................................................................70
KPI 2 Risks (Probability of Corrosion Risk)..........................................................................................70
KPI 3 Location of Infrastructure (Consequence of Failure)..................................................................70
KPI 4 Overall Corrosion Risk (Probability times Consequence)..........................................................70
KPI 5 Life of the Infrastructure.............................................................................................................70
KPI 6 Material of Construction.............................................................................................................70
KPI 7 Corrosion Allowance..................................................................................................................70
KPI 8 Operating Conditions.................................................................................................................71
KPI 9 Upset Conditions in the Upstream Segment..............................................................................71
KPI 10 Upset Conditions in the Current Segment.................................................................................71
KPI 11 Mechanisms of Internal Corrosion.............................................................................................71
KPI 12 Maximum Internal Corrosion Rate.............................................................................................71

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KPI 13 Maximum External Corrosion Rate............................................................................................71
KPI 14: Installation of Accessories..........................................................................................................71
KPI 15 Commissioning Conditions........................................................................................................71
KPI 16 Mitigation....................................................................................................................................71
KPI 17 Mitigation Strategies..................................................................................................................72
KPI 18 Targeted Mitigated Corrosion Rate............................................................................................72
KPI 19 Mitigation Strategy Effectiveness...............................................................................................72
KPI 20 Mitigation....................................................................................................................................72
KPI 21 Mitigation Strategies..................................................................................................................72
KPI 22 Targeted Mitigated Corrosion Rate............................................................................................72
KPI 23 Mitigation Strategy Effectiveness...............................................................................................72
KPI 24 Monitoring Techniques...............................................................................................................72
KPI 25 Number of Monitoring Probes....................................................................................................72
KPI 26 Corrosion Rates from Monitoring Techniques............................................................................72
KPI 27 Accuracy of Monitoring Techniques...........................................................................................72
KPI 28 Monitoring Techniques...............................................................................................................72
KPI 29 Number of Monitoring Probes....................................................................................................73
KPI 30 Corrosion Rates from Monitoring Techniques............................................................................73
KPI 31 Accuracy of Monitoring Techniques...........................................................................................73
KPI 32 Frequency of Inspection.............................................................................................................73
KPI 33 Corrosion Rates from Inspection Techniques............................................................................73
KPI 34 Corrosion Rates from Inspection Techniques............................................................................73
KPI 35 Measurement Data....................................................................................................................73
KPI 36 Validity and Utilization of Measured Data...................................................................................73
KPI 37 Establishment of Maintenance Schedule...................................................................................73
KPI 38 Maintenance Activities...............................................................................................................73
KPI 39 Internal Corrosion Rates after Maintenance Activities...............................................................74
KPI 40 Percentage Difference in Internal Corrosion Rates before and after Maintenance Activities.....74
KPI 41 External Corrosion Rates after Maintenance Activities..............................................................74
KPI 42 Percentage Difference in Corrosion Rates before and after Maintenance Activities..................74
KPI 43 Workforce – Capacity, Skills, Education, and Training...............................................................74
KPI 44 Workforce – Experience, Knowledge, and Quality.....................................................................74
KPI 45 Data to Database.......................................................................................................................74
KPI 46 Data from Database...................................................................................................................74
KPI 47 Internal Communication Strategies............................................................................................74
KPI 48 External Communication Strategies...........................................................................................74
KPI 49 Review.......................................................................................................................................74
KPI 50 Failure Frequency......................................................................................................................74
Appendix C Illustration of Implementation of KPIs (Nonmandatory)...........................................................................75

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Figures
Figure 1 Illustration of PDCA Cycle........................................................................................................................52
Figure 2 5-M Methodology.....................................................................................................................................54
Figure 3: Example of Risk Matrix............................................................................................................................54
Figure 4 Guidelines to Develop the PIM Manual....................................................................................................56
Figure 5 Relationship between Company Policy Documents and the PIM Manual...............................................57
Figure 6 Establishment of Risk..............................................................................................................................58
Figure 7 Risk Mitigation and Monitoring.................................................................................................................64
Figure A1 Canada Energy Regulator Incident Cause Statistics on Oil and Gas Transmission
Pipelines (2008-2021)..............................................................................................................................68
Figure C1 Ideal Status of Implementation of 50 KPI.................................................................................................75
Figure C2 Status of Implementation of 50 KPI in a Product Pipeline.......................................................................76
Figure C3 Status of Implementation of 50 KPI.........................................................................................................77
Figure C4 Status of Implementation of 50 KPI in a Gas Transmission Pipeline.......................................................78
Tables
Table 1 Typical Threats to Pipelines.....................................................................................................................27
Table 2 Typical Threats Experienced by Different Types of Metallic Pipelines.....................................................29
Table 3 Typical Threats Experienced by Different Types of Non-Metallic Pipelines.............................................31
Table 4 Mitigation Strategies for Metallic Pipelines..............................................................................................38
Table 5 Integrity Management of Metallic Pipelines - Types.................................................................................42
Table 6 Stages of Application of Integrity Management Tools..............................................................................43
Table 7 In-Line Inspection Applicability.................................................................................................................48
Table 8 Comparison of Different ICDA Standards................................................................................................51
Table 9 Monitoring Technique Applicability on Metallic Pipelines.........................................................................61
Table 10 Typical Scoring of KPI..............................................................................................................................65
Table A1 Alberta Energy Regulator (AER),Canada: Number of Incidents on Steel and
Non-Metallic Pipelines (2018-2021).........................................................................................................67
Table A2 Pipeline Hazardous Materials Safety Administration (PHMSA) Statistics................................................69

NACE SP0113-2023
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F o rew o rd
This standard practice provides guidance on selecting and implementing the Pipeline Integrity Management (PIM)
methods (i.e., technologies and processes) to assess and to mitigate threats to pipeline integrity. Predominant threats
to pipeline integrity are external corrosion (EC), internal corrosion (IC), stress corrosion cracking (SCC), mechanical
damage (first, second, and third party or vandalism), equipment malfunctioning, manufacturing anomalies, construction
anomalies, incorrect operations, weather-related, and external forces. The standard is focused on the “selection” and
“implementation” of methods and best practices to manage pipeline integrity, but not necessarily on defining all aspects
of PIM programs. ASME B31.4, ASME B31.8, ASME B31.8S, API RP 1160, CSA Z662, and other standards that deal
with many other aspects of PIM should be used in conjunction with this standard.
A PIM program is a continuous process and is applicable to all stages of the pipeline life cycle, including front-end
engineering and design (FEED), construction, commission, operation, decommission, abandonment, and failure inves-
tigation stages. A particular integrity management method may not be applicable to all stages during the lifecycle of a
pipeline.
The properly designed PIM program is based on processes that incorporate continuous improvement methodology.
The lessons learned from each activity should assist in determining opportunities for improvement and in implementing
appropriate methods in subsequent activities. Through selection of integrity methods and implementation of PIM pro-
gram processes, a pipeline operator may identify which threat(s) has occurred, is occurring, or may occur in order to
establish appropriate mitigation, monitoring, repair, replacement, or other strategies.
This standard is intended for use by individuals (managers, supervisors, and engineers) and teams planning, design-
ing, selecting, implementing, supervising, and managing pipeline integrity activities, projects, and programs. Selection
of optimal integrity methods and implementation overall PIM program processes are key to the successful operation
of pipelines.
The selection and implementation strategies described in this standard are specifically intended for buried onshore
pipelines, submerged offshore pipelines, and underwater pipelines constructed from metallic materials (mostly carbon
steels) and non-metallic materials. Users of this standard must be familiar with all applicable pipeline safety and integ-
rity regulations for the jurisdiction in which the pipeline operates.
In AMPP standards, the terms shall and must are used to state requirements and are considered mandatory. The
term should is used to state something that is recommended, but is not considered mandatory. The term may is used
to state something considered optional.
Sc o p e
The key components for selecting and implementing pipeline integrity management program methods or activities for
pipelines are described in this standard. While this standard is focused on pipelines in the oil and gas industry, it may
also be applicable to similar pipelines in other industries.
Rat io nal e
This standard practice presents guidance to operators for selecting and implementing methods, technologies, or activi-
ties to manage pipeline integrity. This version describes a PIM program that addresses all threats (including from corro-
sion and other risks) and covers both metallic (carbon steel) and non-metallic pipelines. References to other standards
are provided for informational purposes only and are not intended to be requirements or to limit the standards that may
be applicable for any pipeline.

NACE SP0113-2023
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Ref erenc ed St andards and O t h er Co nsensus D o c um ent s
The latest edition, revision, or amendment of the referenced documents in effect shall govern unless otherwise dated.
AMPP/NACE/SSPC, www.ampp.org:
NACE/ASTM G193 Standard Terminology and Acronyms Relating to Corrosion
NACE SP21430 Standard Framework for Establishing Corrosion Management Systems
NACE SP0169 Control of External Corrosion on Underground or Submerged Metallic Piping
Systems
NACE SP0102 In-Line Inspection of Pipelines
NACE SP0206 Internal Corrosion Direct Assessment Methodology for Pipelines Carrying
Normally Dry Natural Gas (DG-ICDA)
NACE SP0208 Internal Corrosion Direct Assessment Methodology for Liquid Petroleum
Pipelines (LP-ICDA)
NACE SP0110 Wet Gas Internal Corrosion Direct Assessment (WG-ICDA) Methodology for
Pipelines
NACE SP0116 Multiphase Flow Internal Corrosion Direct Assessment (MP-ICDA) for Pipe-
lines
NACE SP0204 Stress Corrosion Cracking Direct Assessment (SCC-DA) Methodology
NACE TR35103 External Stress Corrosion Cracking of Underground Pipelines
NACE SP0286 Electrical Isolation of Cathodically Protected Pipelines
NACE SP0104 The Use of Coupons for Cathodic Protection Monitoring Applications
NACE SP0394 Application, Performance, and Quality Control of Plant-Applied, Fusion Bond-
ed Epoxy External Pipe Coating
NACE SP0185 Extruded Polyolefin Resin Coating Systems with Soft Adhesives for Under-
ground or Submerged Pipe
NACE RP0399 Plant-Applied, External Coal Tar Enamel Pipe Coating Systems: Application,
Performance, and Quality Control
NACE RP0105 Liquid-Epoxy Coatings for External Repair, Rehabilitation, and Weld Joints on
Buried Steel Pipelines
NACE RP0402 Field Applied Fusion Bonded Epoxy (FBE) Pipe Coating Systems for Girth
Weld Joints: Application, Performance, and Quality Control
NACE SP0109 Field Application of Bonded Tape Coatings for External Repair, Rehabilitation,
and Weld Joints on Buried Metal Pipelines
NACE SP0375 Wax Coating Systems for Underground Piping Systems
NACE RP0602 Field Applied Coal Tar Enamel Pipe Coating Systems: Application, Perfor-
mance, and Quality Control
NACE RP0303 Field-Applied Heat-Shrinkable Sleeves for Pipelines: Application, Perfor-
mance, and Quality Control
SSPC-SP 1 Solvent Cleaning
SSPC-SP 2 Hand Tool Cleaning
SSPC-SP 3 Power Tool Cleaning
SSPC-SP 5 / NACE No. 1 White Metal Blast Cleaning
SSPC-SP 6 / NACE No. 3 Commercial Blast Cleaning
SSPC-SP 7 / NACE No. 4 Brush-Off Blast Cleaning
SSPC-SP 10 / NACE No. 2 Near-White Metal Blast Cleaning

NACE SP0113-2023
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SSPC-SP 11 Power Tool Cleaning to Bare Metal
NACE WJ-1/SSPC-SP WJ-1 Waterjet Cleaning of Metals, Clean to Bare Substrate
NACE WJ-2/SSPC-SP WJ-2 Waterjet Cleaning of Metals, Very Thorough Cleaning
NACE WJ-3/SSPC-SP WJ-3 Waterjet Cleaning of Metals, Thorough Cleaning
NACE WJ-4/SSPC-SP WJ-4 Waterjet Cleaning of Metals, Light Cleaning
NACE SP0287 Field Measurement of Surface Profile of Abrasive Blast Cleaned Steel Surfac-
es Using a Replica Tape
NACE SP0188 Discontinuity (Holiday) Testing of New Protective Coatings on Conductive
Substrates
NACE SP0274 High-Voltage Electrical Inspection of Pipeline Coatings Prior to Installation
NACE SP0490 Holiday Detection of Fusion Bonded Epoxy External Pipeline Coatings of 250
to 760 µm (10 to 30 mils)
NACE SP0100 Cathodic Protection to Control External Corrosion of Concrete Pressure Pipe-
line and Mortar-Coated Steel Pipelines for Water or Waste Water Service
ANSI/NACE SP0115/ISO 15589-2 Petroleum and Natural Gas Industries – Cathodic Protection of Pipeline
Transportation Systems – Part 2: Offshore Pipelines
NACE SP0572 Design, Installation, Operation, and Maintenance of Impressed Current Deep
Ground Beds
NACE SP0177 Mitigation of Alternating Current and Lightning Effects on Metallic Structures
and Corrosion Control Systems
NACE SP21424 Alternating Current Corrosion on Cathodically Protected Pipelines
NACE SP0200 Steel-Cased Pipeline Practices
NACE SP0198 Control of Corrosion Under Thermal Insulation and Fireproofing Materials: A
Systems Approach
NACE TM0102 Measurement of Protective Coating Electrical Conductance on Underground
Pipelines
NACE TM0106 Detection, Testing, and Evaluation of Microbiologically Influenced Corrosion
(MIC) on External Surfaces of Buried Pipelines
NACE TM0109 Aboveground Survey Techniques for the Evaluation of Underground Pipeline
Coating Condition
NACE TM0113 Evaluating the Accuracy of Field-Grade Reference Electrodes
NACE TM0207 Performing Close-Interval Potential Surveys and DC Surface Potential Gradi-
ent Surveys on Buried or Submerged Metallic Pipelines
NACE TM0497 Measurement Techniques Related to Criteria for Cathodic Protection on Un-
derground or Submerged Metallic Piping Systems
NACE TR35110 AC Corrosion State-of-the-Art: Corrosion Rate, Mechanism, and Mitigation
Requirements
NACE TR1F192 Use of Corrosion-Resistant Alloys in Oilfield Environments
NACE SP0170 Protection of Austenitic Stainless Steels and Other Austenitic Alloys from
Polythionic Acid Stress Corrosion Cracking During Shutdown of Refinery
Equipment
NACE SP0472 Methods and Controls to Prevent In-Service Environmental Cracking of Car-
bon Steel Weldments in Corrosive Petroleum Refining Environments
NACE SP0403 Avoiding Caustic Stress Corrosion Cracking of Carbon Steel Refinery Equip-
ment and Piping

NACE SP0113-2023
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NACE TM0177 Laboratory Testing of Metals for Resistance to Sulfide Stress Cracking and
Stress Corrosion Cracking in H2
S Environments
NACE TM0284 Evaluation of Pipeline and Pressure Vessel Steels for Resistance to Hydro-
gen-Induced Cracking
NACE TM0198 Slow Strain Rate Test Method for Screening Corrosion-Resistant Alloys
(CRAs) for Stress Corrosion Cracking in Sour Oilfield Service
NACE TM0298 Sheet Rubber Linings for Abrasion and Corrosion Service
NACE SP0304 Design, Installation, and Operation of Thermoplastic Liners for Oilfield Pipe-
lines
NACE SP0775 Preparation, Installation, Analysis, and Interpretation of Corrosion Coupons in
Oilfield Operations
NACE TM0172 Determining Corrosive Properties of Cargoes in Petroleum Product Pipelines
NACE TM0212 Detection, Testing, and Evaluation of Microbiologically Influenced Corrosion
(MIC) on Internal Surfaces of Pipelines
NACE SP0502 Pipeline External Corrosion Direct Assessment (ECDA) Methodology
NACE SP0210 Pipeline External Corrosion Confirmatory Direct Assessment
NACE SP0313 Guided Wave Technology for Piping Applications
ANSI/NACE MR0175/ISO 15156 Materials for Use in H2
S-Containing Environments in Oil and Gas Production
NACE Publication 31215-2015 Laboratory Evaluation of Corrosion Inhibitors
NACE SP0106 Control of Internal Corrosion in Steel Pipelines and Piping Systems
NACE Publication 31205 Selection, Application, and Evaluation of Biocides in the Oil and Gas Industry
NACE TM0194 Standard Test Method Field Monitoring of Bacterial Growth in Oil and Gas
Systems
NACE Publication 35100 In-Line Inspection of Pipelines
NACE SP0407 Format, Content, and Other Guidelines for Developing a Materials Selection
Diagram
NACE 21413 Prediction of Internal Corrosion in Oilfield Systems from Systems Conditions
NACE 21410 Selection of Pipeline Flow and Internal Corrosion Models
NACE TR3T199 Techniques for Monitoring Corrosion and Related Parameters in Field Appli-
cations
NACE Publication 31014 Field Monitoring of Corrosion Rates in Oil and Gas Production Environments
using Electrochemical Techniques
American Petroleum Institute (API), www.api.org:
API RP 1160 Managing System Integrity for Hazardous Liquid Pipelines
API RP 1173 Pipeline Safety Management Systems
API Standard 1163 In-Line Inspection Systems Qualification
API RP 1110 Pressure Testing of Steel Pipelines for the Transportation of Gas, Petroleum
Gas, Hazardous Liquids, Highly Volatile Liquids or Carbon Dioxide
API 579-1 Fitness for Service
API RP 584 Integrity Operating Windows
API RP 581 Risk-Based Inspection Methodology
API RP 580 Risk-Based Inspection
API RP 970 Corrosion Control Documents

NACE SP0113-2023
11
American Society of Mechanical Engineers (ASME), www.asme.org:
ASME B31.8S Managing System Integrity of Gas Pipelines
ASME B31.8 Gas Transmission and Distribution Piping Systems
ASME B31.4 Pipeline Transportation Systems for Liquids and Slurries
ASME PCC-2 Repair of Pressure Equipment and Piping
American Society for Nondestructive Testing (ASNT), www.asnt.org:
ANSI/ASNT ILI-PQ-2017 In-Line Inspection Personnel Qualification and Certification
ASTM International (ASTM), www.astm.org:
ASTM G71 Standard Guide for Conducting and Evaluating Galvanic Corrosion Tests in
Electrolytes
ASTM G82 Standard Guide for Development and Use of a Galvanic Series for Predicting
Galvanic Corrosion Performance
ASTM G96 Standard Guide for Online Monitoring of Corrosion in Plant Equipment (Elec-
trical and Electrochemical Methods)
ASTM G170 Standard Guide for Evaluating and Qualifying Oilfield and Refinery Corrosion
Inhibitors in the Laboratory
ASTM G184 Standard Practice for Evaluating and Qualifying Oil Field and Refinery Corro-
sion Inhibitors using Rotating Cage
sion Inhibitors using Rotating Cylinder Electrode
ASTM G202 Standard Test Method for Using Atmospheric Pressure Rotating Cage
ASTM G205 Standard Guide for Determining Corrosivity of Crude Oils
sion Inhibitors using Jet Impingement
CSA Group, www.csagroup.org:
CSA Z662 Oil and Gas Pipeline Systems
CSA Z245.20 Plant Applied External Coatings for Steel Pipe (Epoxy)
CSA Z245.21 Plant Applied External Coatings for Steel Pipe (Polyethylene)
CSA Z245.22 Plant Applied External Foam Insulation Coatings for Steel Pipe
CSA Z245.30 Field-Applied External Coatings for Steel Pipeline Systems
Canadian Gas Association (CGA), www.cga.ca:
CGA Recommended Practice
OCC–1
Control of External Corrosion on Buried or Submerged Metallic Piping Sys-
tems
European Federation of Corrosion (EFC), www.efcweb.org:
EFC 64 Recommended practice for corrosion management of pipelines in oil and gas
production and transportation
IEEE, www.ieee.org:
IEEE Std 80 Guide for Safety in AC Substation Grounding
International Oil & Gas Producers (IOGP), www.iogp.org:
IOGP Report 510 Operating Management System Framework for controlling risk and delivering
high performance in the oil and gas industry
IOGP Report 456 Process safety - Recommended practice on key performance indicators
International Organization for Standardization (ISO), www.iso.org:

NACE SP0113-2023
12
ISO 15589 Petroleum, petrochemical and natural gas industries — Cathodic protection of
pipeline systems
ISO 31000 Risk Management
ISO 19345-2 Petroleum and natural gas industry — Pipeline transportation systems —
Pipeline integrity management specification — Part 2: Full-life cycle integrity
management for offshore pipeline
ISO 21809-1 Petroleum and Natural Gas Industries; External Coatings for Buried or Sub-
merged Pipelines used in Pipeline Transportation Systems; Part 1 Polyolefin
Coatings (3-Layer)
ISO 21809-2 Petroleum and Natural Gas Industries; External Coatings for Buried or
Submerged Pipelines used in Pipeline Transportation Systems; Part 2 Single
Layer Fusion Bond Epoxy Coatings
merged Pipelines used in Pipeline Transportation Systems; Part 3 Field Joint
Coatings
merged Pipelines used in Pipeline Transportation Systems; Part 4 Polyeth-
ylene Coatings (2-Layer)
merged Pipelines used in Pipeline Transportation Systems; Part 5 External
Concrete Coatings
ISO 21457 Petroleum, Petrochemical and Natural Gas Industries — Materials Selection
and Corrosion Control for Oil and Gas Production Systems
ISO 20074 Petroleum and natural gas industry – Pipeline transportation systems – Geo-
logical hazard risk management for onshore pipeline
British Standards Institute (BSI), www.bsi.org:
BS 7910 Engineering Criticality Analysis

NACE SP0113-2023
13
Section 1: General
1.1 Introduction
1.1.1 Pipeline Integrity Management (PIM) shall ensure technically-sound, cost-effective, and reliable
operation that protects the safety of the communities, personnel, and environment. The PIM pro-
gram shall complement sound engineering judgment and requires regular review and continuous
improvement to ensure incorporation of the most recent developments in pipeline management.
Selection of optimal integrity assessment methods and risk control strategies and their implemen-
tation are key activities in the PIM program. The program shall incorporate performance measure-
ments of the key activities through defined metrics or key performance indicators (KPI) throughout
the life cycle of the pipeline.
1.1.2 Due to interaction of the program activities and methods described in this Standard, the Standard
shall be used in its entirety. Using or referring to only specific paragraphs or sections may lead to
misinterpretation and misapplication of the recommendations and practices contained herein.
1.1.3 This standard provides the selection and implementation of PIM activities or methods but does not
designate practices for every specific or unique situation because of the complexity of conditions
to which buried onshore, submerged offshore, and underwater pipeline systems are exposed.
1.1.4 This standard presents guidelines for the selection and implementation of PIM methods for buried
onshore and submerged offshore or underwater carbon steel pipelines transporting natural gas
and hazardous liquids as well as associated non-metallic pipelines transporting water, low-pres-
sure corrosive gas, and low-pressure non-corrosive distribution gas lines.
1.1.5 This standard provides flexibility for the pipeline operator to select, tailor, and implement the PIM
method to specific pipeline situations.
1.1.6 Through periodic successive reviews, the program should identify and address locations at which
risk activity has occurred, is occurring, or may occur, and show the effectiveness of various mitiga-
tion programs implemented to minimize the risk.
1.1.6.1 This approach should provide the advantage and benefit of timely locating future
threats (e.g., areas in which wall loss due to corrosion may occur) rather than only
areas in which defects or damage have already formed.
1.1.6.2 Comparing the results of the successive periodic review is one method of evaluating
the PIM process. This process will determine the effectiveness and demonstrate
confidence that the integrity of the pipeline with respect to the threats is continuously
improving.
1.1.7 This standard complements ASME B31.4, ASME B31.8, ASME B31.8S, CSA Z662, and API RP
1160. The pipeline operator shall follow regulatory requirements in the jurisdiction of the specific
pipeline.
1.1.8 Each PIM program complements the others. They do not have identical performance, but each
has advantages over the others. All pipelines may be successfully managed with just one particu-
lar method, or several methods may be required for just one pipeline. Precautions should be taken
when selecting and implementing these methodologies, just as with other management methods.
1.1.9 The provisions of this Standard should be applied under the direction of competent persons who,
by reason of knowledge of the physical sciences and the principles of engineering and mathemat-
ics, acquired by education and related practical experience, are qualified to engage in the practice
of corrosion control and risk management on buried onshore and submerged offshore and under-
water metallic and non-metallic pipeline systems. Such persons may be registered professional

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engineers or persons recognized as integrity managers, integrity engineers, integrity profession-
als, corrosion specialists by organizations such as AMPP, API, ASME, or other certifying agents or
engineers or technicians with suitable levels of experience, if their professional activities include
integrity management of buried onshore and submerged offshore and underwater metallic and
non-metallic pipelines.
Section 2: Definitions
See NACE/ASTM G193 for corrosion terms and definitions not included in this standard.
Abandonment: A process in which a pipeline is taken out of service and the pipeline is no longer needed to be used
in the future.
Acoustic Resonance Scan (ARS): A type of In-Line Inspection (ILI) technique which uses an acoustic waveform to
detect metal loss and geometric anomalies. The tool emits an acoustic signal into the pipe wall and listens to the re-
turning signal. The return signal is directly related to pipe wall thickness. This technique can be used in both gas and
oil pipelines.
Anomaly: A feature identified on a pipeline during an assessment that requires validation or inspection to determine if
it is a defect.
Assessment Segment: A portion of the pipeline that can be isolated as a single length for assessment purposes.
Assessment: Comprehensive process or processes involving various inspection tools and techniques to collect and
analyze data to determine the state or condition of a pipeline segment.
Audit: A systematic, independent, and documented process, normally carried out by a third party, for obtaining records
or information and evaluating them objectively to determine the extent to which a set of policies, procedures, or require-
ments are fulfilled.
Caliper Survey (Caliper pig): A survey using mechanical arms to measure the geometric conditions of a pipelines as
well as other pipeline features by measuring changes in internal diameter of the pipeline. Caliper survey is regularly
carried out prior to intelligent pigging.
Cleaning Pig: A device inserted in a pipeline for cleaning its internal surface or displacing solids and liquids from within
a pipeline. Also known as In-Line Cleaning (ILC) scraper pig.
Corrective Measure: An action taken to respond to a condition or situation thereby limiting adverse consequences
(i.e., actions taken to rectify an existing issue).
Corrosion Management System: A system that links data, personnel, and responsibility, and is designed to manage
the threat of corrosion through the organization’s objectives, policies, procedures, and processes. See Pipeline Corro-
sion Management.
Crack-Like: An anomaly similar to a crack that may or may not have a sharp root radius and with an opening of the
fracture surfaces on the order of 0.1 mm or more.1
Decommission: A process in which the pipeline is taken out of service, whether short term or long term.
Defect: An anomaly that has been confirmed through inspection to validate the characteristics and has operational im-
pact. It may be physically examined to validate the dimensions or may have characteristics that exceed acceptable limits.
Defective Seam: Defective seam or joints may be due to metal loss (undercut, corrosion, less reinforcement) or crack
like (lack of fusion, hook cracks, cold lap).
Dent: A local change in piping surface contour caused by an external force such as mechanical impact or rock impact.

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Discontinuation: A process of discontinuing service (to a customer) and of disconnecting the pipeline from the rest of
the pipeline system.
Eddy Current Survey: A survey in which electromagnetic induction is used to detect and characterize surface and
sub-surface flaws in metallic pipelines.
Engineering Critical Assessment (ECA): An analysis, based on fracture mechanics principles, of whether or not a
given flaw is safe from brittle fracture, fatigue, creep or plastic collapse taking into account its environment and loadings.
Examination (or Direct Examination): A direct physical inspection by touching the exposed profile of a pipeline anom-
aly by a person, which may include the use of non-destructive examination techniques.
External Corrosion: Corrosion occurring on the outside surface of a pipe or other asset.
Flexible (or Spoolable) Pipelines: Flexible pipelines are configurable pipelines that are able to yield under loading
without fracturing. They are mostly made from non-metallic materials such as reinforced composites or reinforced
thermoplastics.
Flow-Induced Corrosion (or Flow-Assisted Corrosion (FAC) or Flow Induced Localized Corrosion (FILC): In-
crease in corrosion resulting from high fluid turbulence due to the flow of a fluid over a surface in a flowing single or
multiphase system.
Gouge: Elongated grooves or cavities usually caused by mechanical removal of metal.
Guided Wave: Sonic or ultrasonic waves that travel along an object and are guided by its surfaces or shape, and
whose wavelength is large compared to a characteristic dimension such as wall thickness.
High Consequence Area (HCA): HCA is location in which a pipeline spill has the potential to cause greater conse-
quence to the public or damage to the environment.
Hydrostatic Test or Hydrostatic Pressure Testing or Hydrotest or Pressure Test or Pressure Testing: Testing
of sections of a pipeline by filling the pipeline with water and pressurizing it until the nominal hoop stresses in the pipe
reach a specified value and remain there for a period without any leaks. A variation of the hydrotest is known as a Spike
Test, which consists of a short duration test at a high “peak” pressure to test the structural integrity of the pipeline. The
pressure is then reduced for a longer-term pressure test designed to detect leaks.
Incident: An undesired event that adversely affects the organization or its stakeholders. This could include asset
damage or failures; failures to meet risk or corrosion management standards in the absence of damage, complaints
that were caused by conformance to substandard procedures or specifications, or failures to comply with appropriate
procedures or specifications.
Indication: An abnormality in the signal or measurement or inspection (e.g., ILI) which may be due to anomaly or
defect.
Inertial Measurement Units (IMU): IMU measures the X-, Y-, and Z-coordinates of the pipeline using gyroscopes.
When used with Geographic Information Systems (GIS), the pipeline route change, curvature change, centerline
change, welds and dents can be mapped.
Inspection: A detailed examination of a location using visual and non-visual methods to detect, measure and quantify
any anomalies on the pipeline. This is part of the validation process to confirm an anomaly as a defect, to determine
the condition or evaluate an anomaly.
In-Line Inspection (ILI): A method of assessing a pipeline using a tool that travels inside and along the length of a
pipeline to provide measurements using non-destructive techniques.
In-Line Inspection Tool (or smart pig or intelligent pig or ILI tool): The device or vehicle that is used for in-line
inspection.

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Integrity Assessment: Comprehensive process or processes involving various tools and techniques to collect and
analyze data to determine the integrity of a pipeline or pipeline segment. Methods can include ILI, pressure testing,
direct assessment, or other technologies that can demonstrate the integrity of the pipe.
Internal Corrosion: Corrosion occurring on the interior surface of a pipeline or other asset.
ILI - Axial Magnetic Flux Leakage (AMFL): A magnetic flux leakage (MFL) technology with the magnetic field induced
in the axial direction of the pipe, longitudinally along the flow of the pipeline. This technology is typically used for volu-
metric, non-linear metal loss anomalies (e.g., corrosion defects). AMFL is the standard technology for MFL tool in ILI.
ILI - Circumferential Magnetic Flux Leakage (CMFL): An MFL technology with the magnetic field induced in the
circumferential direction of the pipe, perpendicular to the flow of the pipeline. This technology is typically used for ax-
ially oriented metal loss and cracking anomalies (e.g., corrosion, manufacturing defects along the longitudinal welds,
cracking) of the pipeline.
ILI - Combination: A combination tool is one that combines two or more ILI techniques into a single tool. The most
common combinations are MFL+GEO and MFL + XYZ.
ILI - Deformation: See ILI Geometry (GEO).
ILI Electro-Magnetic Acoustic Transducer (EMAT): A technology that generates sound waves into the fluid media
and pipe to receive signal responses that can be interpreted as axially oriented pipe anomalies (e.g., corrosion, crack-
ing). This tool does not require a liquid couplant for the sound wave transmission.
ILI - Geometry (GEO): Testing (using e.g., caliper, eddy current) performed to detect and size deformation features in
pipelines.
ILI - MFL (Magnetic Flux Leakage or MFL): A standard technology that uses a magnetic field oriented parallel to the
flow (longitudinal) of a pipeline. This method is suitable for general metal loss and corrosion of girth welds.
ILI - Ultrasonic Testing Wall Measurement (UTWM): A piezoelectrical-based ultrasonic technology that emits an
induced sound wave from the ultrasonic sensor to the pipe wall and back to measure metal loss in the pipe. This tool
requires a liquid couplant and is commonly used in liquid pipelines.
ILI - Ultrasonic Crack Detection CD (UTCD): A method that uses sound waves generated in a transducer to provide
measurement of cracks. The transducers can be oriented parallel or perpendicular to the pipe flow. This tool requires a
liquid couplant and is commonly used for liquid service pipelines.
ILI - Positioning (XYZ) or Inertial: A technology using an Inertial Measurement Unit (IMU) to determine the positioning
of the pipeline (e.g., pipeline centerline, anomaly location). The IMU is normally installed in the other tools (e.g., MFL,
UTWM, UTCD, EMAT) to provide more accurate location of the anomalies. The IMU also measures the longitudinal and
vertical curvature of the pipeline enabling to calculate the bending (i.e., global) strain and with multiple runs to figure out
plane and elevation displacement in the pipeline.
Launcher (Also known as a pig launcher): A location and device used to insert a pigging tool into a pressurized
pipeline.
Long-Range Ultrasonic Testing (LRUT): LRUT is a technique used to test a length of pipeline (typically between 20
and 50 meters) from a single test point. See also Guided Wave.
Magnetometry or Large Standoff Magnetometry (LSM): A non-intrusive technique able to detect localized mechan-
ical stresses in a pipeline. It can be used to identify corrosion, cracks, and dents in a pipeline.
Mechanical Damage: Damage to coating or pipe caused by pipeline operators (1st
party), service providers to the pipe-
line operator (2nd
party) or persons not connected to the pipeline (3rd
party). Mechanical damage may be intentionally
caused by vandalism or illegal taps, or accidentally caused by dragged anchors or dropped objects.

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Metal Loss: Any pipe anomaly in which metal has been removed. Metal loss is usually the result of corrosion, but
gouging, manufacturing defects, or mechanical damaging can also cause metal loss or wall thinning.
Metallic Material: Materials constructed from metals or alloys. Most metallic materials used to construct oil and gas
pipelines are carbon steels. Under special considerations, corrosion-resistant alloys (CRA) are used. Commonly used
CRA are stainless steels.
Mitigation: The effort to reduce pipeline operating risk resulting from corrosion or other threats through a defined set of
actions that reduce the likelihood or probability of that threat leading to undesired consequences.
Monitoring: A continuous, albeit not necessarily constant and complete, observation of parameters of a process.
Mothballing: A process in which the pipeline is temporarily taken out of service. The pipeline will be preserved for
possible future service.
Nonconformance: The failure to follow a standard, specification, procedure, or plan, or non-fulfillment of a requirement
contained in such a document.
Non-Destructive Testing (NDT) or Non-Destructive Examination (NDE): An inspection technique to quantify any
anomalies or defects in a pipeline without damaging or modifying the pipeline.
Non-Metallic: Non-metallic materials may be thermoplastics, thermosets, composites (engineered structural or fiber-
glass), and fiberglass reinforced plastics.
Operator: A person or organization that owns or operates pipeline facilities as an owner or as an agent for an owner.
Piggability: Characteristics of pipeline or pipeline section that has no restrictions for running pigs.
Pipeline: A continuous part of a pipe system used to transport a hazardous liquid or gas. A pipeline includes pipe,
valves, fittings, and other appurtenances attached to the pipe.
Pipeline Corrosion Management: A comprehensive and series of efforts for managing corrosion of a pipeline and
preventing corrosion feature from becoming threat to the integrity of the pipeline.
Pipeline Integrity Management (PIM): A comprehensive series of efforts for managing the integrity of a pipeline and
preventing a feature from becoming a threat to the integrity of the pipeline.
PIM Activity: An activity, task or action carried out within a PIM program.
PIM Document: A report or procedure that describes how a specific PIM activity is carried out.
PIM Element: A tool or activity carried out within a PIM program.
PIM Manual: A document that describes various aspects of PIM. A PIM manual may consist of several documents or
may refer to several documents.
PIM Method: A procedure used in a PIM program.
PIM Process: An analysis carried out within the PIM program.
PIM Program: A program to manage several repeatable activities in PIM.
PIM Project: A project carried out within the or in support of the PIM program.
PIM Strategy: An act or art to develop or arrive at an appropriate PIM activity.
PIM System: A system that governs various PIM activities, including organization, human resources, their competency,
data, quality control and process control.

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PI M T ec h no l o g y: A technology used in the PIM program.
PI M T em p l at e: A pattern used for carrying out exactly a PIM activity repeatedly.
Pip el ine Syst em : All portions of the physical facilities through which gas, oil, or product moves during transportation.
This includes pipe, valves, fittings, and other appurtenances attached to the pipe, compressor units, pumping units,
metering stations, regulator stations, delivery stations, tanks, holders, and other fabricated assemblies.
Pressure: The force applied perpendicular to the surface of the pipeline per unit area over which that force is distributed.
Prevent ive M easure: An action taken to eliminate the cause(s) of a credible threat to avoid its occurrence.
Pro c ess: A series of actions or steps taken in order to achieve a particular end goal.
Rec eiver: A pipeline facility used for removing a pig from a pressurized pipeline. It may be referred to as trap, pig trap,
or scraper trap.
Rem ediat io n: Corrective actions taken to mitigate or reduce failure likelihood from a threat.
Rep air: A process used to remove a defect or reduce its impact on the integrity of the pipeline. The common repairs are
application of sleeves, welding, and application of polymeric coating or patches.
Rig h t o f W ay ( RO W ) : An area designated for pipelines, including the surface and subsurface area and areas required
to access the pipeline. May also be known as Right of User (RoU).
Ro o t -Cause Anal ysis: A family of processes implemented to determine the primary cause of an event. These process-
es all seek to establish a cause-and-effect relationship through the organization and analysis of data.
Rup t ure: The instantaneous tearing or fracturing of pipe material causing large-scale containment loss.
Seam W el d: The longitudinal or spiral weld in pipe, which is made in the pipe mill.
Seg m ent : A portion of the pipeline with defined start and end points.
Sm art Pig : See In-Line Inspection Tool.
St ray Current Co rro sio n: The corrosion caused by electric current from a source external to the intended electrical cir-
cuit, for example, extraneous current in the earth. Stray current may be direct current (DC) or alternating current (AC).
St ress: The force per unit area when a force acts on a body of a pipeline.
St ress Co rro sio n Crac k ing ( SCC) : Cracking of a material produced by the combined action of corrosion, environ-
ment, and sustained tensile stress (residual and/or applied).
Sulfide Stress Cracking (SSC): Cracking of metal involving corrosion and tensile stress (residual and/or applied) in
the presence of water and H2
S. Pipelines that transport wet, sour products or are in other sulfidic environments can
experience SSC.
T el l uric Current Co rro sio n: Corrosion due to variations in pipe-to-soil potentials caused by telluric current from the
earth’s magnetic field that take the potentials outside the desired range for cathodic protection.
T h reat : An anomaly or defect or indication that when not addressed (by repair, replacement or remediation) will result
in leak, rupture, or failure.
T ransit F at ig ue: May occur due to anomalies in manufacturing that grow during transport. Mostly occurs when line
pipe is transported by rail.

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T rap : See Receiver.
U l t raso nic T est ing ( U T ) : A type of inspection technology that uses ultrasound for volumetric inspection of a pipe.
U nder-D ep o sit Co rro sio n: Corrosion occurring beneath deposits or solids on a metal surface.
V al ve Sec t io n: A portion of a pipeline that is isolated by two adjacent valves.
W el l h ead ( Ch rist m as T ree) : The component at the surface of a well that provides a structural and pressure containing
interface for drilling or production equipment.
Sec t io n 3: D o c um ent at io n Req uirem ent s
Execution of a PIM program involves multiple activities (PIM Project, PIM Strategy, development of PIM system, PIM
Technology, PIM template), that are carried out by various persons or departments and at different frequencies on
pipeline system. To coordinate the activities and assure repeatability and measurability of the performed activities, it
is essential to establish concise, pro-active, and clear program documentation. Ideally, these documentation require-
ments should be established at the front-end engineering and design (FEED) stage and continuously updated during
operation stages based on experience and lessons learned.
The number of processes or procedures and other work activities that would benefit from formal documentation will vary
depending on the company size and level of complexity of operations. All documentation requirements (e.g., manuals,
procedures, and work steps) shall be either contained within the main PIM manual (which is legally required in many
jurisdictions) or referred to from the Manual. This manual shall detail all aspects of the PIM program, including, but not
limited to planning, implementation, continuous improvement, risk management including mitigation and assessment,
performance management, communication, and management of change (MOC). Examples of procedures and activi-
ties that may require either separate formal documentation or inclusion within the manual itself are listed in the following
sections.
No t e: The titles listed in this section are only provided as examples. Depending on the company size and assets, the
activities that may benefit from formal documentation will differ from this list, but the manual structure is often similar.
3. 1 Pro g ram M anag em ent
A PIM manual shall define the overall program processes and the manual may serve as a container for all
documented program activities. Common PIM elements defined within the manual may be prescribed by reg-
ulations.2-4
Common PIM documents include:
• Management and Organization Structure as relevant to the Program
• PIM Template
• Quality Management System
• Performance Management
• Risk Assessment, Mitigation, and Management
• Communication
• Management of Change
• Audit and Review
• Document and Data Management
• Competency and Training
• Third Party Service Providers Engagement
• Emergency Response Practices
• Disaster Management
3. 2 F ro nt End Eng ineering and D esig n ( F EED ) D o c um ent s
The PIM program benefits from including aspects of the future integrity management at the front-end design to
minimize future costs. Some examples of the documents that are utilized and/or created at the FEED stage include:

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• Land Records
• Geotechnical Assessment Procedure
• Route Survey
• Soil survey/Test Records including Soil Resistivity
• Engineering Design Basis Documents
• Waterway and Other Crossings
• Road / Rail / Other Obstacle Crossing
• Location Class Determination
• Pipeline Design
• Material Selection
• Corrosion Control
• Corrosion monitoring, sample collection, and chemical injection locations.
3.3 Construction Stage Documents
Typical construction documents utilized later in the integrity program or influenced by the program include:
• Procurement of Line Pipes
• Mill Applied Coating Specifications
• Long Term Preservation of Coated Line Pipes
• Pipeline Field Verification Procedure
• Welding of Pipeline
• Mainline Valves
• Isolating Joints
• Mainline Flow Tees, Elbows & Fittings and Scraper Traps
• Anomaly Management
• Weld Joint Coating and Repair of Coating in Field
• Pipeline Casings, Casing Fillers & End Seals
• Pipeline Field Joint Coating and Coating Repairs
• NDT Records and Reports for Welding
• Material Test Certificates
• Temporary Cathodic Protection System
3.4 Commissioning Stage Documents
Typical documents needed for commissioning include:
• Pipeline Pressure Testing
• Records of water quality (including total dissolved solids [TDS], chlorides, total suspended solids, and
bacterial counts), applicable water treatment, time records showing how long a pipeline segment has
been exposed to the hydrotest water, and dewatering and drying procedures.
• Pipeline Commission Requirements
• Cathodic Protection System Requirements
• Baseline Data (including First ILI Performed)
3.5 Operation Stage Documents
Operational personnel may perform or supervise regular maintenance and other activities. Documents that
define activities to be carried out by operational personnel include:
• Pipeline Integrity Management System
• Facility Integrity Management System
• Corrosion Management System Manual
• In-Service Pipeline Hydrotest for Integrity Assessment
• Corrosion Monitoring, Maintenance, and Management
• Inline Inspection
• Direct Assessment Procedure
• Pipeline Internal Corrosion Monitoring
• Monitoring & Maintenance of CP System

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• Alternating Current /Direct Current Interference Surveys
• Pipeline High-Tension Cable / Foreign Pipeline crossing
• Above-Ground Surveys
• Pipeline Cleaning Pigging
• Pig Residue Sample Collection, Testing and Reporting
• Chemicals (Inhibitor, Biocide, Scale Inhibitor, Odorant): Selection, Testing, Application, and Performance
Monitoring
• Welding In-Service Pipelines
• Coating Rehabilitation
3.6 Decommissioning and Abandonment Stage Documents
• Pipeline Decommissioning, Recommissioning, and Abandonment
3.7 Failure Stage Document
• Retrieval and Testing of Pipe Piece for Failure Investigation
• Root Cause Investigation
• Failure Investigation
Standards providing further guidelines for development of documents include:
• ISO 21457, Petroleum, petrochemical and natural gas industries — Materials selection and corrosion
control for oil and gas production systems
• ISO 31000, Risk Management
• ISO 19345, Petroleum and natural gas industry — Pipeline transportation systems — Pipeline integrity
management specification — Part 1: Onshore Pipelines and Part 2: Offshore pipelines
• NACE SP0407, Format, Content, and Other Guidelines for Developing a Materials Selection Diagram
• API RP 970, Corrosion Control Documents
• NACE SP21430, Standard Framework for Establishing Corrosion Management Systems
• API RP 1160, Managing System Integrity for Hazardous Liquid Pipelines
• ASME B31.8S, Managing System Integrity of Gas Pipelines
• ASME B31.8, Gas Transmission and Distribution Piping Systems
• ASME PCC-2, Repair of Pressure Equipment and Piping
• EFC 64, Recommended practice for corrosion management of pipelines in oil and gas production and
transportation
• IOGP Report 510, Operating Management System Framework for controlling risk and delivering high
performance in the oil and gas industry
• API 579-1, Fitness-for-Service
Section 4: Pipeline Types
Depending on the product the pipelines transport, they may be classified into different types. Most pipelines are buried
under land or submerged in water. Some pipelines may be aboveground.
4.1 Onshore production pipeline (also known as a flowline or gathering line)
A pipeline transporting oil, gas, solids (e.g., organic solids, hydrates; separately, dissolved, or in combination),
and water separately or in combination (multiphase fluids) from a wellhead (commonly known as a “Christmas
Tree” because of its appearance) that is on the land to production facility is referred to as an “onshore flowline,”
an “onshore gathering line,” an “onshore production pipeline,” a “pipeline lateral,” or a “well line.” If the pipeline
connects the wellhead directly to a production facility or a gathering line, it is often known as a flowline. If the
pipeline gathers fluids from several flowlines and transports them to production facility, it is known as a gath-
ering line, pipeline lateral, or well line. Onshore production pipelines are normally metallic materials, mostly
carbon steels.

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4.2 Offshore production pipeline (also known as a flowline or gathering line)
A pipeline transporting oil, gas, solids, and water separately or in combination (multiphase fluids) from a
submerged or underwater wellhead or from a single or multiwell above-surface platform to a production fa-
cility is referred to as an “offshore flowline,” an “offshore gathering line,” an “offshore production pipeline” or
a “pipeline lateral.” If the pipeline connects the wellhead directly to a production facility or a gathering line,
it is often known as a flowline, pipeline lateral or well line. If the pipeline gathers fluids from several flowlines
and transports them to a production facility, it is known as a gathering line. Offshore production pipelines are
normally metallic materials, mostly carbon steels.
4.3 Hydrotransport pipeline (oilsands)
A pipeline transporting oil, sand, and water as a mixture from an oilsands production facility to a processing
facility is known as a hydrotransport pipeline. Hydrotransport pipelines are normally metallic materials, mostly
carbon steels.
4.4 Water injection pipeline/flowline
Pipelines transporting water from oil, gas, and water separators, water sources (ocean, rivers, ponds), or
storage locations to injection wellheads are known as water injection pipelines or flowlines. Water injection
pipelines or water injection flowlines may be constructed from metallic or non-metallic materials.
4.5 Produced water pipeline/flowline
A pipeline transporting water that may be naturally present in the formation, water discarded from a treatment
facility process or water from the introduction of water into deep underground formations to treatment facilities,
disposal locations, or storage locations is known as a produced water pipeline or produced water flowline.
Produced water pipelines or flowlines may be constructed from metallic or non-metallic materials.
4.6 Slurry pipeline
A pipeline transporting a mixture of solids and liquids (mostly water) is known as a slurry pipeline. Slurry
pipelines may be operated between various processing stages or from the processing facilities to a disposal
location. Slurry pipelines are normally metallic materials, mostly carbon steels.
4.7 Gas transmission pipeline
A pipeline transporting natural gas from a treatment plant, storage facility, or collection point in a gas field to
a consumer distribution line, service line, storage facility, or another gas transmission line is known as a gas
transmission pipeline. Most pipelines are dry, i.e., free from water and/or other condensable hydrocarbons
and/or operating above the water vapor dew point. However, depending on the operation conditions, some
gas transmission pipelines may intermittently contain water and/or other condensable hydrocarbons. Gas
transmission pipelines are normally metallic materials, mostly carbon steels.
4.8 Oil transmission pipeline
A pipeline transporting crude oil from a treatment plant, storage facility, or field collection point to refineries,
service line, storage facility, or another transmission line is known as an oil transmission pipeline. The product
quality is specified. Oil transmission pipelines typically transport 98 to 99.5% crude oil and 0.5 to 2% basic
sediment and water (BS&W). Oil transmission pipelines are normally metallic materials, mostly carbon steels.
4.9 Hydrocarbon-Products (Oil Product) Pipeline
A pipeline transporting refined products (petrol, diesel, or kerosene) from refineries to storage tanks is known
as an oil product pipeline. The product quality is specified. Oil product pipelines typically transport 99.5%
refined hydrocarbon products and up to 0.5% BS&W. Hydrocarbon-products pipelines are normally metallic
materials, mostly carbon steels.

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4 . 10 G as dist rib ut io n p ip el ine
A pipeline transporting dry natural gas (with no water content) from a service line, storage facility, or another
transmission line to a customer is known as a gas distribution pipeline. Gas distribution pipelines normally
operate at lower pressures than those of gas transmission pipelines and may be constructed from metallic or
non-metallic materials. Non-metallic pipelines may be flexible pipelines.
4 . 11 F ac il it y p ip el ine o r p ip ing
A pipeline or piping transporting liquids or gases within a facility is known as a facility pipeline or facility piping.
Facility pipelines or piping are often above ground but can also be found buried. Facility pipelines or piping
are normally metallic materials, mostly carbon steels. Facility pipelines may have several valve sections to
convert, control, and change flow velocity, pattern, and direction.
Sec t io n 5 : St ag es o f Pip el ine L if e Cyc l e
Irrespective of the type of pipeline, a pipeline goes through different stages during its life cycle. The most distinguish-
able stages are described in this section. Pipeline operators should develop a PIM program at the FEED stage, imple-
ment the PIM program during the design and construction stages; verify the PIM program during the commissioning
phase, maintain and continually improve the PIM program throughout the operational phase, modify, if appropriate, at
the MOC stage, and continue, if required, in the abandonment stage. The PIM program is transferred from the FEED
and construction stages to the operational stage. This interface involves transfer of PIM documentation and information
about the pipeline, which is the key to the success of implementing an integrity management plan.
5 . 1 F ro nt End Eng ineering and D esig n ( F EED ) St ag e
At the FEED stage, the route of the pipeline is selected after geological and operational requirements are
confirmed. The right of way (ROW) is established. Properties and range of volume of fluids to be transported
are analyzed. Based on the route and fluid properties, materials of construction are selected and a risk man-
agement program, including specified minimum yield strength (SMYS) and corrosion control, is established.
Operating boundaries in terms of fluids, volume, rate of flow, temperature, pressure, and elevation change
are established; mechanisms of corrosion and other risk threats anticipated in the operation stages are estab-
lished; and best practices to implement mitigation and monitoring activities are identified.
As the PIM program may influence the design, the program’s characteristics and capabilities should be taken
into consideration at the FEED stage.

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5.2 Manufacturing Stage
Engineering and designing pipelines for appropriate type and process is essential for pipeline integrity and
safety. In the manufacturing stage, components of line, associated coating, and other accompaniments are
manufactured. The mill that will fabricate the line pipe and shop that will apply the coating on the line pipe are
established. Strategies to establish quality of pipe, weld, and coating are established.5
The following integrity activities are typically carried out:
• Material selection
• Mill test reports (MTR)
• Coating evaluation, selection, and application
• Quality control
• The records of these activities shall be retained for the entire life of the pipeline.
5.3 Construction Stage
In the construction stage, the line pipes are brought from manufacturing locations to the construction location.
Best practices to prevent mechanical damage to the pipe and coating during the transportation from manufac-
turing location to the construction location are implemented. The line pipes are girth welded to make pipeline,
all accessories are installed, the pipeline is buried, and soil is reclaimed or immersed in water and anchored.
Note: If the construction is delayed, suitable arrangements must be established to secure and protect the
line pipe and mill-applied coating.
• Visual inspection
• Destructive inspection
• Non-destructive inspection
• The records of completed activities (e.g., non-destructive inspection and destructive testing [including
repair procedures]) should be retained for the entire life of the pipeline.
5.4 Commissioning Stage
In the commissioning stage, the pipeline is often pressure-tested and may be inspected for any gouging or
dents using a caliper survey and in-line inspected to establish its baseline condition. The water used for pres-
sure-testing or hydrotesting must be properly treated to avoid/minimize internal corrosion. Treatments may
include inhibitors, biocides, and oxygen scavengers. Specific hydrotesting water and hydrotesting process
procedures must be developed. Operation may start immediately or may be delayed. When the operation is
delayed, the pipeline shall be preserved (mothballed) until operation commences. For preservation, the water
used for hydrotesting is drained, the pipeline dried, and filled with inert gas.
• Pressure test
• Gauge pigging
• Caliper pigging
• Baseline ILI pigging
• The records of the completed activities must be retained for the entire life of the pipeline.
Note: The manner in which a pipeline is preserved will vary based on feasibility, type of product to be
later transported, requirements for treatment or disposal of preservation medium, etc. However;
the intent of any preservation activity is to maintain the pipeline in an “as new” condition until the
line can be placed in service. Preservation, preservation maintenance and depreservation are
developed and approved prior start of construction.

NACE SP0113-2023
25
5.5 Operational Stage
The pipeline is typically operated as per boundaries established at the FEED stage.
Guidance for first-time assessment should be derived from information from the FEED, construction, and com-
missioning stages as well as from current operational data. In the absence of construction and commissioning
information, the following should be collected and used to guide first-time assessment.
• Diameter
• Length
• Pipeline grade, category, and standard
• Wall thickness
• Design pressure
• Operating pressure (as % Specified Minimum Yield Strength [SMYS])
• Pipeline accessibility or piggability
• Inspection difficulties such as shielding from coatings
• The expectation of excessive corrosion
• Right of way, accessibility, and number of digs
• Significant interference threats to CP system
• Presence of historical mill and construction problems, such as a long-seam threat
• Other threats that interact with and are known to accelerate corrosion
• Operational economics and reliability of service
• Operational considerations
• Environmental considerations.
Consideration should be given to conditions that have changed and been learned of since the commissioning
stage and first or subsequent assessment. In addition, an operator may consider the benefits of performing
a different assessment method to gain different or additional data to better understand the corrosion and risk
activity. Integration of all available data can improve the operator’s understanding of the pipeline’s condition.
In addition to the original method used during the FEED stage and in the first assessment, the decision as to
what technology to utilize for follow up assessments must consider a number of factors, including:
• Integration of all available data to understand the current conditions of the pipeline
• Results of first assessment and the ongoing mitigation activities
• Feasibility of a follow up assessment using different method/technique
• Changes in codes, regulations, or in operator procedures
• Significant events between assessments leading to alternate priorities
• Root-cause analysis, if an incident has occurred.
5.6 Management of Change
A management of change (MOC) program shall be developed and implemented by all organizations. During
the operation of a pipeline, any change that meets or exceeds the program definition of a change managed
item shall be addressed in accordance with the program.
During the operation of the pipelines, changes such as change of ownership, change of operating conditions
(e.g., increase or decrease of temperature), change of entire products (e.g., conversion of a natural gas
pipeline to crude oil), introduction of other products (e.g., introduction of hydrogen in a natural gas pipeline),
changes of chemical treatment, and other changes that can affect the integrity of the pipeline internally and/or
externally, may happen. A management of change (MOC) plan helps to facilitate the change.
If operational requirements warrant changing the operating conditions established in the FEED stage, the
impact of change is analyzed and best practices to make the change are established.
5.7 Decommissioning/ Abandonment Stage
Depending on the operational needs, economy, status of the pipeline, at times, pipelines may be decommis-
sioned or abandoned. The extent of steps to be followed during decommissioning depends on whether the
pipeline is permanently decommissioned or temporarily decommissioned (mothballed), regulations, industry
best practices, and company policy.

NACE SP0113-2023
26
5.7.1 Discontinuation
Whenever a pipeline service is discontinued (e.g., service to a customer is discontinued), the fol-
lowing activities must be carried out:
• The valve that is to be closed to prevent the flow of gas to the discontinued pipeline must be
provided with a locking device.
• Following isolation of the line to be discontinued, the line shall be safely vented or drained
completely. If line contents are hazardous, proper disposal of contents shall be conducted.
Pressure within the line will be dependent on whether the line is to be discontinued or aban-
doned; see Paragraphs 5.7.2 or 5.7.3, respectively.
• The discontinued piping must be physically disconnected from the operating pipeline sys-
tem and the open pipe ends are sealed.
• If the line in question is to be returned to service, refer to Paragraph 5.7.2. If the line is to be
abandoned, refer to Paragraph 5.7.3.
5.7.2 Decommissioning
Whenever a pipeline service is temporarily discontinued or decommissioned / mothballed, the
following activities shall be carried out:
• The pipeline is emptied of service fluids.
• The pipeline is purged, appropriately cleaned, or both.
• Add biocide and/or inhibitor batch to ensure the line has internal protection in its dormant state.
• A small amount of inert gas should be left on the line (around 100 kPa) to allow for occa-
sional pressure readings on the line.
• The pipeline is physically separated from any in-service piping or equipment.
• The pipeline is capped, plugged, or otherwise effectively sealed.
• The following integrity activities shall be carried out:
• Maintained cathodic protection on the external surfaces of the pipe
• Annual checks of the pipeline
• All records are required to be maintained for future evaluations and usage.
5.7.3 Abandonment
Whenever a pipeline service is permanently abandoned, a decision must be made whether the line
will be abandoned in place or removed. With either option, the first stage will be the same as for
decommissioning (Paragraph 5.7.2, excluding bullets 3, 4 and 7 through 9).
• If removing the pipeline, it will then be pulled or lifted out of the ground.
• When all activities are complete, the surface should not show any evidence that there was a
pipeline there.
• If the line is being kept in place:
▪ It will need to be cut and capped underground. There will be no need to maintain ca-
thodic protection on the pipeline or pressure in the pipeline. However, various jurisdic-
tions may have alternate regulations in place which would need to be followed.
▪ Local or company as well as government regulations will determine what requirements
are needed for land and rights of way.
Note: Abandoned in-place pipeline sections passing through sensitive areas such as road,
railway crossings, under-water, or populated areas may be filled with concrete to
prevent the line from caving in or floating.
5.8 Failure Occurrence Stage
Depending on the importance of the pipeline, failure, or incident may be defined as:
• Loss of functionality (e.g., swelling or “loss of roundness or increase in ovality”)
• Loss of electrical continuity (e.g., in a CP-protected pipeline)
• Release of products that were to be present inside the pipeline
• Pinhole leak
• Catastrophic structural failure or weld failure leading to crack or rupture

NACE SP0113-2023
27
When failure occurs, failure analysis and root cause analysis must be carried out. The extent and details of
the analysis depend on the extent of damage, location in which the failure happened (e.g., high consequence
area), regulations, industry best practices, and company policy. Failure analysis typically includes analysis
of overall failure site conditions, operating conditions at the time of failure, history of the pipeline and its op-
eration, product sampling, environmental sampling, metallurgical and electrochemical factors, morphology
(mode) of failure, and based on all information, deducing the cause(s) of failure.
Failure analysis may also include evaluation of the effectiveness of various mitigation strategies.
Root cause analysis comprises a wide range of tools and techniques used to analyze various problems and
understand the underlying causes.
Standards providing guidance to carry out failure analysis include:
• ASTM G161, “Standard Guide for Corrosion-Related Failure Analysis”
Sec t io n 6 : T yp ic al T h reat s and St ag es o f T h eir O c c urrenc e
Table 1 lists typical threats to the internal and external surfaces of metallic pipelines. Though these threats are identified
separately, in practice one or two or more of them may occur simultaneously and may occur in stages different from the
stage indicated in Table 1. If these threats are not addressed in a timely manner, failures such as leaks or ruptures may
occur. Appendix A (nonmandatory) lists typical threats causing failures in pipelines.
T ab l e 1
T yp ic al T h reat s t o Pip el ines
Ph ase o f
o c c urrenc e
T im e
D ep endenc y
T h reat s
classification
T yp ic al T h reat s
I nt ernal Ex t ernal
Start up
Stable*
Manufacturing
• Defective seam
• Defective pipe body
(lamination, gouge, groove,
cavity)
• Hard spots
• Hard heat affected zone
• Defective seam
• Defective pipe body
(lamination, gouge, groove,
cavity)
• Hard spots
• Hard heat affected zone
Construction
• Defective joints (including girth
weld, fabrication weld, fusion
joints, bolted joints, crimped
connections)
• Defective joints (including
girth weld, fabrication weld,
fusion joints, bolted joints,
crimped connections)
• Geometric anomalies (dents,
wrinkles, buckles)
• Defective attachments
(Stripped threads, broken
pipe, broken coupling
• On bottom stability
Equipment
• Gasket failure
• O-ring failure
• Control/relief system failure
• Seal/pump packing (SPP)
failure
• Gasket failure
• O-ring failure
• Control/relief system failure
• Seal/pump packing (SPP)
failure

NACE SP0113-2023
28
Ph ase o f
o c c urrenc e
T im e
D ep endenc y
T h reat s
classification
T yp ic al T h reat s
Constant
Operation
Time
Independent
Mechanical
damage
• Mechanical damage to
coating or pipe
• Dropped objectives
• Dragged anchors
• Vandalism
• Illegal tapping
Incorrect
operations
a. Overpressure
b. Vacuum
c. Surge
Natural hazards
(geotechnical
hazards,
hydrotechnical
hazards, and
natural hazards)
• Heavy rains (floods or wash
outs)
• Ground movements
(earthquake, subsidence,
seabed movement,
landslides, mudslides,)
• Scouring
• Volcanic eruption
• Weather extremes
(temperature, wind, wave,
lightning, current [telluric]
extremes)
• Vibration
Wear out
Time
dependent**
Corrosion
• Galvanic corrosion
• General corrosion
• Pitting corrosion
• Microbiologically Influenced
Corrosion
• Under-deposit corrosion
• FILC
• Erosion-corrosion
• Seam weld corrosion
• Galvanic corrosion
• General corrosion
• Pitting corrosion
• Microbiologically Influenced
Corrosion
• Seam weld corrosion
• Stray current corrosion
• Corrosion under insulation
Environment
Assisted Cracking
• Hydrogen induced cracking
• Sulfide stress cracking
• Stress corrosion cracking
• Stress corrosion cracking
Fatigue
• Pressure cycle induced
• Transit fatigue
• Thermal fatigue
• Corrosion fatigue
• Corrosion fatigue
*May also be known as “Dormant”
**May also be known as “Active”
Table 2 lists typical threats experienced in different types of metallic pipelines and their locations (Internal [I] or External
[E]). Table 3 list typical threats experienced in different types of non-metallic pipelines and their locations (Internal [I] or
External [E]). The probability of a typical threat listed in Table 2 and Table 3 in each pipeline may vary. For a specific
pipeline, not all threats listed in Tables 2 and 3 need to be considered. It is also possible that additional threats not listed
in Table 2 and Table 3 may occur under a particular situation.

NACE SP0113-2023
29
T ab l e 2
T yp ic al T h reat s Ex p erienc ed b y D if f erent T yp es o f M et al l ic Pip el ines
G eneral t h reat s O nsh o re
p ro duc t io n
p ip el ine
O f f sh o re
p ro duc t io n
p ip el ine
H ydro -
t ransp o rt
p ip el ine
W at er
inj ec t io n
p ip el ines/
flowlines
Pro duc ed
W at er
p ip el ines/
flowlines
Sl urry
p ip el ine
G as
t ransm issio n
p ip el ine
O il
t ransm issio n
p ip el ine
O il p ro duc t
p ip el ine
G as
D ist rib ut io n
Pip el ine
F ac il it y
p ip el ine o r
p ip ing
Defective Seam I, E I, E I, E I, E I, E I, E I, E I, E I, E I, E I, E
Defective pipe body I, E, M I, E, M I, E, M I, E, M I, E, M I, E, M I, E, M I, E, M I, E, M I, E, M I, E, M
Hot spot I, E I, E I, E I, E I, E I, E I, E I, E I, E I, E I, E
Hard heat affected
zone
I, E I, E I, E I, E I, E I, E I, E I, E I, E I, E I, E
Defective joints I, E I, E I, E I, E I, E I, E I, E I, E I, E I, E I, E
Geometric
anomalies
E E E E E E E E E E E
Defective
attachments
E E E E E E E E E E E
On bottom stability No E No No No No E E E No No
Gasket failure I, E I, E I, E I, E I, E I, E I, E I, E I, E I, E I, E
O-ring failure I, E I, E I, E I, E I, E I, E I, E I, E I, E I, E I, E
Control/relief system
failure
Seal/pump packing
(SPP)
Vandalism E No No No No No E E E E No
Mechanical damage E No E E E E E E E E E
Dropped objects No E No No No No No No No No E
Dragged anchors No E No No No No No No No No No
Illegal tapping E No No No No No No E E No No
Overpressure I I No No No No I I I No I
Vacuum No No No No No No No I I No I
Surge No I No No No No No I I No I
Heavy rains No No No No No No E E E No No
Ground movements E E E E E E E E E No No
Scouring* No E No No No No No No No No No
Volcanic eruption** E E E E E E E E E E E
Weather extremes E No E E E E E E E E E
Vibration E E E E E E E E E E E
Galvanic corrosion I I I I I I I I I I I
General corrosion I, E I, E I, E I, E I, E I, E I, E I, E I, E I, E I, E

NACE SP0113-2023
30
G eneral t h reat s O nsh o re
p ro duc t io n
p ip el ine
O f f sh o re
p ro duc t io n
p ip el ine
H ydro -
t ransp o rt
p ip el ine
W at er
inj ec t io n
p ip el ines/
flowlines
Pro duc ed
W at er
p ip el ines/
flowlines
Sl urry
p ip el ine
G as
t ransm issio n
p ip el ine
O il
t ransm issio n
p ip el ine
O il p ro duc t
p ip el ine
G as
D ist rib ut io n
Pip el ine
F ac il it y
p ip el ine o r
p ip ing
Pitting corrosion I, E I, E I, E I, E I, E I, E I, E I, E I, E I, E I, E
MIC I, E I, E I, E I, E I, E I, E I, E I, E I, E I, E I, E
UDC I I I I I I I I I I I
FILC I I I I I I I I I I I
EC I I I I I I No No No No I
Seam weld
corrosion
Stray current
corrosion***
No No No No No No E E E No No
CUI No E**** No No No No No E**** No No E****
HIC I I No No No No I I I No I
SSC I I No No No No I I I No I
SCC E E No No No No E E E No I
Pressure cycle
induced fatigue
I I I No No I I, E I, E I, E No I
Transit fatigue No No No No No No I, E I, E I, E No No
Thermal fatigue No No No No No No No No No No I, E
Corrosion fatigue No No No No No No I, E I, E I, E No I, E
I: Occurs on the internal surface; E: Occurs on the external surface; No means the threat has not been experienced by the operators or the probability of occurrence of the threat is extremely low. M:
Mid wall (e.g., laminations).
*May occur, leading to washout or pipe snap, in all pipelines at perineal river crossings if pipeline is not laid at sufficient depth below scour depth of the river.
**Considered at the FEED stage
***Including DC and AC current
****If insulated.

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