# DIMP - Pipeline Corrosion Final Report Michael Baker Jr. November 2008 - **operation:** document - **citation:** PHMSA Guidance, DIMP - Pipeline Corrosion Final Report Michael Baker Jr. November 2008 - **title:** DIMP - Pipeline Corrosion Final Report Michael Baker Jr. November 2008 - **source type:** guidance - **agency:** Pipeline and Hazardous Materials Safety Administration - **status:** guidance - **official:** true - **published on:** Not available - **effective on:** Not available - **summary:** DIMP - Pipeline Corrosion Final Report Michael Baker Jr. November 2008 Document finalreportpipelinecorrosion.pdf (1.65 MB) This study presents an overview of the corrosion threat to gas and liquid pipelines, focusing on the prevention, detection, characterization, and management of internal and external corrosion, primarily on onshore pipelines. The report provides concise information on the state of pipeline corrosi - **machine formats:** - **json:** https://regulus.evalyn.ai/document/phmsa-guidance-dimp-pipeline-corrosion-final-report-michael-baker-jr-november-2008-757de26f.json - **markdown:** https://regulus.evalyn.ai/document/phmsa-guidance-dimp-pipeline-corrosion-final-report-michael-baker-jr-november-2008-757de26f.md - **app url:** https://regulus.evalyn.ai/document/phmsa-guidance-dimp-pipeline-corrosion-final-report-michael-baker-jr-november-2008-757de26f - **source url:** https://www.phmsa.dot.gov/pipeline/gas-distribution-integrity-management/dimp-pipeline-corrosion-final-report-michael-baker-jr-november-2008 **body:** DIMP - Pipeline Corrosion Final Report Michael Baker Jr. November 2008 Document finalreportpipelinecorrosion.pdf (1.65 MB) This study presents an overview of the corrosion threat to gas and liquid pipelines, focusing on the prevention, detection, characterization, and management of internal and external corrosion, primarily on onshore pipelines. The report provides concise information on the state of pipeline corrosion control, the gaps in current knowledge, and the direction of current research and development. While not formally or comprehensively addressing corrosion of offshore pipelines, this study does highlight aspects of corrosion in offshore pipelines in various sections and is specific in reference when discussed. Effective Date: Saturday, November 1, 2008 <<>> P Pi ip pe el li in ne e C Co or rr ro os si io on n FINAL REPORT Submitted to U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration Office of Pipeline Safety Integrity Management Program Under Delivery Order DTRS56-02-D-70036 Submitted by Michael Baker Jr., Inc. Contributing Author Raymond R. Fessler, Ph.D. BIZTEK Consulting, Inc. November 2008 <<>> Table of Contents Table of Contents 1 Introduction...........................................................................................................................................1 1.1 Corrosion Overview ....................................................................................................................1 1.2 Corrosion in Perspective..............................................................................................................2 1.2.1 Frequency and Consequences in the United States.................................................................2 1.2.2 Transmission Pipelines............................................................................................................3 1.2.3 Natural Gas Distribution Pipelines..........................................................................................5 1.2.4 Gas Gathering Lines................................................................................................................6 1.2.5 Non-U.S. Experience ..............................................................................................................6 1.3 State of Knowledge Regarding Corrosion...................................................................................8 2 Background.........................................................................................................................................10 2.1 Problem Statement.....................................................................................................................10 2.2 Project Scope.............................................................................................................................10 2.3 Report Outline ...........................................................................................................................10 3 Corrosion in Pipelines.........................................................................................................................11 3.1 Understanding the Process.........................................................................................................11 3.2 Uniform vs. Localized Corrosion ..............................................................................................12 3.2.1 Pitting ....................................................................................................................................12 3.2.2 Selective Seam Corrosion .....................................................................................................13 3.2.3 Microbial Corrosion ..............................................................................................................13 3.3 External Corrosion.....................................................................................................................14 3.3.1 Factors that Affect External Corrosion .................................................................................14 3.3.1.1 Onshore Buried Pipelines .............................................................................................14 3.3.1.2 Offshore Pipelines ........................................................................................................15 3.3.2 Methods to Prevent or Mitigate External Corrosion on Buried Pipelines.............................15 3.3.2.1 Coatings........................................................................................................................15 3.3.2.2 Cathodic Protection ......................................................................................................19 3.3.2.3 Other Preventive/Mitigative Measures.........................................................................20 3.3.3 Monitoring Techniques for External Corrosion ....................................................................21 3.4 Internal Corrosion......................................................................................................................22 3.4.1 Gas Pipelines.........................................................................................................................22 3.4.2 Liquid Pipelines ....................................................................................................................22 3.4.3 Preventive/Mitigative Measures for Internal Corrosion........................................................23 3.4.3.1 Dehydration ..................................................................................................................23 3.4.3.2 Inhibitors ......................................................................................................................24 3.4.3.3 Coatings........................................................................................................................24 3.4.3.4 Buffering ......................................................................................................................24 3.4.3.5 Cleaning Pigs................................................................................................................24 3.4.3.6 Biocides ........................................................................................................................24 3.4.3.7 Additional Preventive Measures...................................................................................25 3.4.3.8 Preventive/Mitigative Measures for Selective Seam Corrosion...................................25 3.4.3.9 Preventive/Mitigative Measures for MIC on Gas Pipelines .........................................25 3.4.4 Monitoring Internal Corrosion ..............................................................................................25 3.5 Environmentally Assisted Cracking ..........................................................................................26 3.5.1 Stress-Corrosion Cracking (SCC) .........................................................................................26 3.5.1.1 External SCC................................................................................................................26 3.5.1.2 Internal SCC .................................................................................................................27 3.5.2 Corrosion Fatigue..................................................................................................................27 Pipeline Corrosion November 2008 Page i <<>> Table of Contents 3.5.3 Hydrogen Embrittlement.......................................................................................................28 3.5.3.1 Hydrogen-Stress Cracking............................................................................................28 3.5.3.2 Hydrogen-Induced Cracking ........................................................................................29 3.5.3.3 Loss of Ductility...........................................................................................................29 3.5.3.4 Implications for Pipelines in a National Hydrogen Economy ......................................29 3.5.4 Sulfide-Stress Cracking.........................................................................................................29 4 Corrosion Threat Identification...........................................................................................................31 4.1 Overview ...................................................................................................................................31 4.2 External Corrosion.....................................................................................................................31 4.3 Internal Corrosion......................................................................................................................31 4.4 Stress Corrosion Cracking.........................................................................................................31 5 Corrosion Damage-Assessment Methods ...........................................................................................33 5.1 Overview ...................................................................................................................................33 5.2 In-line Inspection.......................................................................................................................33 5.3 Hydrostatic Testing ...................................................................................................................35 5.4 Direct Assessment .....................................................................................................................36 5.4.1 External Corrosion Direct Assessment .................................................................................37 5.4.2 Internal Corrosion Direct Assessment for Gas Pipelines ......................................................38 5.4.3 Stress Corrosion Cracking Direct Assessment......................................................................40 5.5 Emerging Technologies.............................................................................................................40 5.5.1 Long-Range Guided-Wave Ultrasonic Testing (LRGWUT or GWUT)...............................40 5.5.2 Remote Field Testing (RFT) .................................................................................................41 5.5.3 Robotic Investigation ............................................................................................................42 5.5.4 Sound-Wave Testing.............................................................................................................43 5.5.5 NoPig ....................................................................................................................................43 5.5.6 Buried Reference Cell Monitoring........................................................................................43 5.6 Specialized Techniques .............................................................................................................44 5.6.1 Microbiologically Influenced Corrosion Monitoring Techniques ........................................44 5.7 Assessing the Severity of Corrosion..........................................................................................44 5.8 Assessing the Severity of Stress Corrosion Cracking................................................................45 6 Standards Review................................................................................................................................46 6.1 Overview ...................................................................................................................................46 6.2 Standard Development Organizations .......................................................................................46 6.2.1 NACE International ..............................................................................................................46 6.2.2 American Society of Mechanical Engineers .........................................................................46 6.2.3 American Petroleum Institute................................................................................................46 6.2.4 ASTM International ..............................................................................................................46 6.2.5 American Society for Nondestructive Testing ......................................................................46 6.2.6 American National Standards Institute .................................................................................46 6.2.7 International Organization for Standardization.....................................................................47 6.2.8 Det Norske Veritas................................................................................................................47 6.2.9 British Standards Institute .....................................................................................................47 6.3 U.S. Regulations and Standards ................................................................................................47 6.3.1 U.S. Regulations....................................................................................................................47 6.3.2 U.S. Standards.......................................................................................................................47 6.3.3 Relevant Non-U.S. Standards................................................................................................50 6.4 Role of Industry Best Practices Regarding Corrosion...............................................................50 7 Corrosion Risk Management ..............................................................................................................51 7.1 Overview ...................................................................................................................................51 7.2 Risk Assessment Methodologies...............................................................................................51 7.2.1 Subject Matter Expert Model ................................................................................................52 Pipeline Corrosion November 2008 Page ii <<>> Table of Contents 7.2.2 Relative Risk Model..............................................................................................................52 7.2.3 Probabilistic Model ...............................................................................................................53 7.3 Characteristics of an Effective Risk Assessment.......................................................................53 7.4 Summary....................................................................................................................................54 8 Corrosion Research.............................................................................................................................55 8.1 Overview ...................................................................................................................................55 8.2 Corrosion R&D Funding Organizations....................................................................................55 8.3 Current Corrosion R&D Efforts ................................................................................................55 8.3.1 Prevention .............................................................................................................................55 8.3.2 Detection ...............................................................................................................................56 8.3.3 Assessment............................................................................................................................56 8.3.4 Mitigation..............................................................................................................................56 8.4 Corrosion R&D Requirements ..................................................................................................57 8.5 Summary of Corrosion R&D Activities ....................................................................................57 9 Elements of an Effective Corrosion Integrity Management Program.................................................58 9.1 Overview ...................................................................................................................................58 9.2 Technology................................................................................................................................58 9.3 Components of an Effective Integrity Management Program...................................................58 9.4 Resource Requirements (after Byrd, 2004) ...............................................................................59 10 Summary and Conclusions..............................................................................................................61 10.1 Frequency and Consequences of Corrosion Incidents...............................................................61 10.2 Prevention of Corrosion in Pipelines.........................................................................................61 10.3 Corrosion Threat Identification .................................................................................................63 10.4 Assessing the Severity of Corrosion..........................................................................................63 10.5 Regulations and Standards.........................................................................................................65 10.5.1 Regulations .......................................................................................................................65 10.5.2 Standard Development Organizations ..............................................................................65 10.6 Corrosion Risk Management.....................................................................................................66 10.7 Corrosion Research ...................................................................................................................67 10.8 Corrosion Integrity Management Programs ..............................................................................68 11 Bibliography ...................................................................................................................................69 12 Appendix A.....................................................................................................................................71 12.1 Listing of Relevant Current Research .......................................................................................71 12.1.1 PRCI funded R&D (from Web Site):................................................................................71 12.1.2 PHMSA Funded R&D (not listed elsewhere)...................................................................71 12.1.3 NYSEARCH (Part of NGA).............................................................................................72 12.1.4 AGA..................................................................................................................................72 Pipeline Corrosion November 2008 Page iii <<>> List of Abbreviations List of Abbreviations AC Alternating Current AGA American Gas Association AGM Aboveground Marker ANB Anaerobic Bacteria ANSI American National Standards Institute AOPL Association of Oil Pipelines APB Acid-Producing Bacteria API American Petroleum Institute ASME American Society of Mechanical Engineers ASNT American Society for Nondestructive Testing ASTM ASTM International (formerly the American Society for Testing and Materials) AWWA American Water Works Association BSI British Standards Institute CEPA Canadian Energy Pipeline Association CFR Code of Federal Regulations CP Cathodic Protection CSE Copper/Copper Sulfate Electrode DA Direct Assessment DC Direct Current DNV Det Norske Veritas DOE (U.S.) Department of Energy DOI (U.S.) Department of the Interior DOT (U.S.) Department of Transportation DSAW Double Submerged Arc Weld EAC Environmentally Assisted Cracking EC External Corrosion ECDA External Corrosion Direct Assessment EGIG European Gas pipeline Incident data Group EMAT Electromagnetic Acoustic Transducer ERCB Energy Resources Conservation Board (formerly EUB) ERW Electric-Resistance Welded EUB Energy and Utilities Board (Alberta) FBE Fusion-Bonded Epoxy FFS Fitness-For-Service FTE Full-Time Equivalent GPS Global Positioning System GRI Gas Research Institute GTI Gas Technology Institute GUL Guided Ultrasonic GWUT Guided-Wave Ultrasonic Testing HAZ Heat-Affected Zone HCA High-Consequence Area HDD Horizontally Directionally Drilled HIC Hydrogen-Induced Cracking IC Internal Corrosion ICDA Internal Corrosion Direct Assessment IDX Integrity Data Exchange Pipeline Corrosion November 2008 Page iv <<>> List of Abbreviations ILI In-Line Inspection INGAA Interstate Natural Gas Association of America ISO International Organization for Standardization LDC Local Distribution Company LRGWUT Long-Range Guided-Wave Ultrasonic Testing MAOP Maximum Allowable Operating Pressure MFL Magnetic-Flux Leakage MIC Microbiologically Influenced Corrosion MOP Maximum Operating Pressure MPI Magnetic Particle Inspection NACE NACE International NDE Non-Destructive Evaluation NDT Non-Destructive Testing NEB National Energy Board (Canada) NETL National Energy Technology Laboratory NGA Northeast Gas Association O&M Operations and Maintenance OPS (U.S. Department of Transportation) Office of Pipeline Safety OTD Operations Technology Development Company PAMP Portable Acoustic Monitoring Packages P&M Preventative and Mitigative Measures PHMSA (U.S. Department of Transportation) Pipeline and Hazardous Materials Safety Administration PRCI Pipeline Research Council International R&D Research and Development RAPID Real-Time Active Pipeline Integrity Detection RFEC Remote Field Eddy Current RFET Remote Field Electromagnetic Technique RFT Remote Field Testing RP Recommended Practice RSTRENG Remaining Strength of Corroded Pipe SATT Shear Appearance Transition Temperature SCC Stress Corrosion Cracking SCC DA Stress Corrosion Cracking Direct Assessment SGA Southern Gas Association SME Subject Matter Expert SMYS Specified Minimum Yield Strength SP Standard Practice SRB Sulfate-Reducing Bacteria SSAW Single Submerged Arc Weld SSC Sulfide Stress Cracking UT Ultrasonic Testing Pipeline Corrosion November 2008 Page v <<>> Chapter 1 1 Introduction This study was developed at the request of the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) to provide a non-technical, high-level common understanding of issues related to pipeline corrosion. This study follows similar efforts by PHMSA to provide information on topics regarding pipeline integrity issues in report format. The intent is that the report be used to facilitate effective communication on issues with all stakeholders (public officials, industry representatives, trade associations, pipeline companies, and the general public). Readers who desire more technical depth are encouraged to refer to books such as Peabody’s Control of Pipeline Corrosion or the many technical papers published by NACE International (NACE), American Society of Mechanical Engineers (ASME), and other technical societies and research organizations. This study presents an overview of the corrosion threat to gas and liquid pipelines, focusing on the prevention, detection, characterization, and management of internal and external corrosion, primarily on onshore pipelines. The report provides concise information on the state of pipeline corrosion control, the gaps in current knowledge, and the direction of current research and development. While not formally or comprehensively addressing corrosion of offshore pipelines, this study does highlight aspects of corrosion in offshore pipelines in various sections and is specific in reference when discussed. 1.1 Corrosion Overview Corrosion is one of the leading causes of failures in onshore transmission pipelines (both gas and hazardous liquids) in the United States. It also is a threat to gas distribution mains and services, as well as oil and gas gathering systems. PHMSA uses specific criteria to identify the incidents that are significant from a pipeline safety viewpoint. An incident is defined as significant if it meets any of the following conditions: Fatality, or injury requiring in-patient hospitalization $50,000 or more in total costs, measured in 1984 dollars Highly volatile liquid releases of five barrels or more, or other liquid releases of 50 barrels or more Liquid releases resulting in an unintentional fire or explosion. As shown in Figure 1-1, corrosion has been responsible for 18 percent of the significant incidents (both onshore and offshore) in the 20-year period from 1988 through 2008. By comparison, during this same period, excavation damage accounted for 26 percent of significant incidents. By contrast, corrosion accounted for only 5.8 percent of all serious incidents (onshore and offshore), defined as those resulting in fatality or injury requiring in-patient hospitalization, during this same period, while excavation damage was responsible for 34.5 percent of all serious incidents. NACE currently estimates the total costs attributed to all types of corrosion at $276 billion. Corrosion of onshore gas and liquid transmission pipelines represents $7 billion of this total. Table 1-1 shows the estimated corrosion costs in the 1990s for onshore transmission pipelines. The costs are broken down by the cost of capital, operations and maintenance (O&M), and the cost of failures (non-related O&M costs). The pipeline rehabilitation and replacement costs are included in the capital costs. O&M costs comprise approximately half of the total costs associated with corrosion. Pipeline Corrosion November 2008 Page 1 <<>> Chapter 1 All Pipeline Significant Incidents (1988 – August 2008) Figure 1.1 – Causes of significant incidents in onshore and offshore pipelines (Source: PHMSA Filtered Incident Files) Table 1.1 – Cost of Corrosion in U. S. Transmission Onshore Pipelines Low Estimate High Estimate Average (Millions of US $) (Millions of US $) (Millions of US $) Percent Cost of Capital 2,500 2,840 2,670 38 Operations and Maintenance (O&M) 2,420 4,840 3,630 52 Cost of Failures (Non- Related O&M) 471 875 673 10 Total Cost Due To Corrosion 5,391 8,555 6,973 100 (Source: http://www.corrosioncost.com/pdf/gasliquid.pdf ) FHWA-RD-01-156, March 2002. 1.2 Corrosion in Perspective 1.2.1 Frequency and Consequences in the United States As is shown in Figure 1-2, there have been 40 to 65 significant corrosion incidents per year on pipelines during the past 20 years, which averages to 52 such incidents per year. Typically, half or more involve onshore liquid pipelines; the next highest frequency involves onshore gas transmission pipelines. The pattern has been relatively consistent over time and, rather surprisingly, has not been influenced by the aging of the infrastructure. The fact that the pipeline failure rate has not increased significantly over a 20-year interval attests to the effectiveness of industry efforts at corrosion control. Pipeline Corrosion November 2008 Page 2 <<>> Chapter 1 50 - Hazardous Liquid Onshore • Hazardous Liquid Offshore Number of Significant Incidents 40 Gas Transmission Onshore 30 Gas Transmission Offshore Gas Gathering - Gas Distribution - Total Significant Corrosion 1030 1900 1053 1,050 2000 1002 100° ,006 Year (Source: PHMSA Filtered Incident Files) Figure 1.2- History of significant corrosion incidents in the U.S. The 1,074 significant incidents during that 20-year period resulted in 30 fatalities, 100 injuries, and which resulted in 147 fatalities, 619 injuries, and $518 million in property damage. Table 1-2 $551 million in property damage. This contrasts with 1,552 significant excavation damage incidents presents comparable data on significant corrosion incident consequences. Table 1.2 - Average Annual Consequences of Significant Corrosion Incidents Between 1988 and 2007 Type of Pipeline Mileage 1988 2007 Number Fatalities Injuries Property Damage Hazardous Liquid 153K 166K Onshore 33 0.05 0.8 $14M Offshore 0.9 0 0 $1.7M Gas Transmission Onshore 284K 294K 7.7 0.6 0.2 $8.2M Offshore 7K 7K Gas Gathering 32K 4.4 0 0 20K 2.7 0 $1.2M 0.2 $1.2M Gas Distribution 802K Total 1278K 1172K 3.4 0.8 3.9 1659K 51.9 1.4 5.2 $0.6M $25M (Source: PHMSA Filtered Incident Files) 1.2.2 Transmission Pipelines As is shown in Figures 1-3 and 1-4, corrosion accounts for about 23 percent of the significant failures in both hazardous liquid and gas transmission pipelines. In terms of absolute numbers, there were more significant failures and more property damage associated with liquid pipelines than with gas Pipeline Corrosion November 2008 Page 3 <<>> Chapter 1 Hazardous Liquid Pipeline Significant Incidents (1988 – August 2008) Figure 1.3 – Causes of significant incidents in onshore and offshore hazardous liquid transmission pipelines (Source: PHMSA Filtered Incident Files) Gas Transmission Pipeline Significant Incidents (1988 – August 2008) Figure 1.4 – Causes of significant incidents in onshore and offshore natural gas transmission pipelines (Source: PHMSA Filtered Incident Files) Pipeline Corrosion November 2008 Page 4 <<>> Chapter 1 Corrosion failures can be either leaks or ruptures. Leaks are more common. Leaks from gas pipelines generally do not cause property damage, because the escaping gas disperses into the atmosphere. However, leaks from a liquid line can contaminate the soil, groundwater or surface water. Conversely, ruptures in a gas pipeline are more likely to cause an explosion and fire, thus resulting in more fatalities and injuries on average. Almost all of the corrosion incidents in liquid pipelines have involved onshore lines. The few impacting offshore lines have caused neither fatalities nor injuries, which is not surprising, since the probability of an individual being in proximity to an offshore failure is extremely remote. On a per-mile basis, a disproportionate number of reported corrosion failures in gas transmission pipelines occurred offshore, but 97 percent were due to internal corrosion. Conversely, 77 percent of the onshore incidents were due to external corrosion. 1.2.3 Natural Gas Distribution Pipelines External force damage is much more prevalent for distribution pipelines than for transmission pipelines since the majority of distribution pipelines are non-metallic and generally are located in more densely populated areas. The failure rate of distribution pipelines due to various causes is shown in Figure 1-5. Gas Distribution Pipeline Significant Incidents (1988 – August 2008) Figure 1.5 – Causes of significant incidents in natural gas distribution pipelines (Source: PHMSA Filtered Incident Files) External corrosion causes more than 90 percent of corrosion-related failure in distribution pipelines. Prior to the implementation of 49 CFR Part 192 in 1970, distribution pipelines were required neither to be coated nor to have cathodic protection. In the 1950s, many operators did coat their distribution mains and services but did not provide cathodic protection until required to do so. Therefore, older distribution systems may contain many miles of pipe that have been unprotected for some time and have suffered corrosion damage. Distribution pipelines are not thought to be as prone to internal corrosion as transmission pipelines because they are located further downstream from gathering and production systems which might Pipeline Corrosion November 2008 Page 5 <<>> Chapter 1 introduce water into the gas stream. Since many of the gathering and transmission systems have equipment to scrub and clean the gas stream, internal corrosion in the gas transmission system is not as prevalent a threat as it was prior to the installation of cleaning and conditioning equipment. Early transmission lines did not perform this function, and there is evidence that they may contain inactive internal corrosion. If a distribution pipeline is near a storage field and the transmission system operator does not sufficiently dehydrate and clean the stored gas prior to its introduction into the distribution system, internal corrosion in the distribution pipeline can occur. Distribution companies have tariffs and specifications that limit the amount of water that can be present in their delivered gas (whether from a transmission pipeline or storage field). 1.2.4 Gas Gathering Lines Gas gathering lines account for very few corrosion failures, and those failures that have occurred resulted in no fatalities and very few injuries. More than 90 percent of the reported incidents were caused by internal corrosion. 1.2.5 Non-U.S. Experience There are substantial differences between the Canadian pipeline system and the U.S. system. Besides encompassing only 20 percent as many miles, the Canadian pipelines are of much more recent construction, on average, which not only means that they have had less time to corrode, but also that they have benefited from newer and better coatings as well as more consistently applied cathodic protection. In addition, because of the low population density in Canada, outside force damage is extremely low. Consequently, the Canadian experience, as illustrated in Figure 1-6, is somewhat different from the U.S. experience. Corrosion failures, including stress-corrosion cracking (SCC), made up about half of the failures in Canadian gas transmission systems – more than twice the proportion realized in the United States. 8.7% 4.3% 8.7% 4.3% 50.0% 6.5% Corrosion Excavation Damage Operational Material failure Natural Forces Fatigue All Other 17.9% Figure 1.6 – Causes of the 46 ruptures that occurred in Canadian pipelines from 1984-2004 (Source: National Energy Board. [2008, July]. Focus on Safety and the Environment. A Comparative Analysis of Pipeline Performance, 2000 – 2006) Pipeline Corrosion November 2008 Page 6 <<>> Chapter 1 As is shown in Figure 1-7, Europe, on the other hand, has experienced a slightly lower proportion of corrosion failures but a much higher proportion of outside force damage failures. This can be attributed to high population density, which has significantly increased the outside force failure rate. Figure 1.7– European pipeline incident causes (Source: The 6th EGIG Report, 1970 – 2004. [2005, December]. Gas Pipeline Incidents. Doc. Number EGIG 05.R.0002) Figure 1-8 shows that the U. S. experience with corrosion failures as a percentage of total incidents (not on a per-mile basis) falls within the middle range between the European (lower) and Canadian (higher).This difference probably is primarily due to differences in population density. Pipeline Corrosion November 2008 Page 7 <<>> Chapter 1 Rupture Primary Cause Comparison Percent of All Causes 70% 60% 50% 40% 30% 20% 10% 0% NEB (1991-2006) ERCB (2000-2006) EGIG (1970-2004) PHMSA (1991-2006) Corrosion M aterial (M anufacturing or Construction) Other Causes External Interference Geotechnical Primary Causes Figure 1.8 – Comparison of pipeline failure causes for Canada (NEB and ERCB), Europe (EGIG) and the US (PHMSA) (Source: National Energy Board. [2008, July]. Focus on Safety and the Environment. A Comparative Analysis of Pipeline Performance, 2000 - 2006) 1.3 State of Knowledge Regarding Corrosion From a scientific point of view, corrosion is well understood, both in terms of causal mechanisms and method of control. The corrosion behavior of a piece of steel in a beaker of salt water is predictable and controllable. However, despite the current level of industry knowledge, pipelines continue to experience a modest but significant number of failures due to corrosion. The reason is that the corrosion behavior of a buried pipeline is much more complicated than that of a piece of steel in a beaker of salt water. The most important factors that complicate the investigation and/or mitigation of corrosion include the following: The chemical properties of the environment surrounding a buried pipeline are not adequately understood. Variations in the oxygen content, moisture content, and chemical composition of the soil along the pipe length and from top to bottom of the pipe can act as concentration cells that promote corrosion. Moisture content and oxygen content of the soil also vary with time. Coating quality varies along the length of a pipeline. Coatings sometimes become disbonded from the pipe surface, allowing groundwater to contact the steel but shielding the steel from cathodic-protection currents. Disbonded coating will prevent aboveground survey detection of underlying corrosive conditions. Physical variations in soil characteristics and placement (gaps, etc.) affect the distribution of cathodic-protection current. Pipeline Corrosion November 2008 Page 8 <<>> Chapter 1 Visual inspection of the outside of the pipe and the coating require excavation. Stray currents from nearby buried structures can interfere with a pipeline’s cathodic-protection system. Thus, the pipeline engineer is faced with a challenging problem – preventing corrosion in a very lengthy (and frequently large-diameter) metal structure contained within a unique environment of predominantly undetermined chemical and physical properties – without the means for direct observation of the majority of the structure’s length. Pipeline Corrosion November 2008 Page 9 <<>> Chapter 2 2 Background 2.1 Problem Statement A reduction in the number of corrosion incidents is desirable both a safety and financial standpoint. The Pipeline and Hazardous Materials Safety Administration (PHMSA), industry trade organizations, and the scientific community have worked to increase pipeline safety and reduce incidents and related costs for many years and, in fact, have made significant improvements to corrosion detection, assessment, and mitigation technology. However, not all stakeholders and decision-makers engaged in discussions of issues such as continued research funding, regulatory review and legislative oversight of corrosion-related issues have a fundamentally sound understanding of pipeline corrosion. 2.2 Project Scope This project was initiated to facilitate communications among all stakeholders engaged in the discussion of corrosion-related issues, including PHMSA personnel, state and federal regulators, elected officials and their staffs, representatives form the pipeline industry and the research community, as well as the general public by producing a document that would provide all stakeholders with a common, high-level understanding of the issues involved. 2.3 Report Outline This report has been structured to address the following subjects: Description of the types of corrosion found on pipelines and the methods of management for each Factors to consider in deciding which types of corrosion may be a threat to a specific pipeline Current methods to assess the extent or severity of corrosion on an existing pipeline Standards and regulations governing pipeline corrosion inspection and management Methods used by the industry to manage the risk of corrosion Current research and development programs directed at developing better tools and methods to manage corrosion, and identifying gaps that are not being addressed Elements of an effective corrosion integrity management prog - **truncated:** true - **body characters:** 212250