{"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":null,"effective_on":null,"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\n\nDocument\n\n finalreportpipelinecorrosion.pdf (1.65 MB)\n\n        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.\n\n          Effective Date: Saturday, November 1, 2008\n\n<<<PAGE 1>>>\n\nP Pi ip pe el li in ne e C Co or rr ro os si io on n\nFINAL REPORT\nSubmitted to\nU.S. Department of Transportation\nPipeline and Hazardous Materials Safety Administration\nOffice of Pipeline Safety\nIntegrity Management Program\nUnder Delivery Order DTRS56-02-D-70036\nSubmitted by\nMichael Baker Jr., Inc.\nContributing Author\nRaymond R. Fessler, Ph.D.\nBIZTEK Consulting, Inc.\nNovember 2008\n\n<<<PAGE 2>>>\n\nTable of Contents\nTable of Contents\n1 Introduction...........................................................................................................................................1\n1.1 Corrosion Overview ....................................................................................................................1\n1.2 Corrosion in Perspective..............................................................................................................2\n1.2.1 Frequency and Consequences in the United States.................................................................2\n1.2.2 Transmission Pipelines............................................................................................................3\n1.2.3 Natural Gas Distribution Pipelines..........................................................................................5\n1.2.4 Gas Gathering Lines................................................................................................................6\n1.2.5 Non-U.S. Experience ..............................................................................................................6\n1.3 State of Knowledge Regarding Corrosion...................................................................................8\n2 Background.........................................................................................................................................10\n2.1 Problem Statement.....................................................................................................................10\n2.2 Project Scope.............................................................................................................................10\n2.3 Report Outline ...........................................................................................................................10\n3 Corrosion in Pipelines.........................................................................................................................11\n3.1 Understanding the Process.........................................................................................................11\n3.2 Uniform vs. Localized Corrosion ..............................................................................................12\n3.2.1 Pitting ....................................................................................................................................12\n3.2.2 Selective Seam Corrosion .....................................................................................................13\n3.2.3 Microbial Corrosion ..............................................................................................................13\n3.3 External Corrosion.....................................................................................................................14\n3.3.1 Factors that Affect External Corrosion .................................................................................14\n3.3.1.1 Onshore Buried Pipelines .............................................................................................14\n3.3.1.2 Offshore Pipelines ........................................................................................................15\n3.3.2 Methods to Prevent or Mitigate External Corrosion on Buried Pipelines.............................15\n3.3.2.1 Coatings........................................................................................................................15\n3.3.2.2 Cathodic Protection ......................................................................................................19\n3.3.2.3 Other Preventive/Mitigative Measures.........................................................................20\n3.3.3 Monitoring Techniques for External Corrosion ....................................................................21\n3.4 Internal Corrosion......................................................................................................................22\n3.4.1 Gas Pipelines.........................................................................................................................22\n3.4.2 Liquid Pipelines ....................................................................................................................22\n3.4.3 Preventive/Mitigative Measures for Internal Corrosion........................................................23\n3.4.3.1 Dehydration ..................................................................................................................23\n3.4.3.2 Inhibitors ......................................................................................................................24\n3.4.3.3 Coatings........................................................................................................................24\n3.4.3.4 Buffering ......................................................................................................................24\n3.4.3.5 Cleaning Pigs................................................................................................................24\n3.4.3.6 Biocides ........................................................................................................................24\n3.4.3.7 Additional Preventive Measures...................................................................................25\n3.4.3.8 Preventive/Mitigative Measures for Selective Seam Corrosion...................................25\n3.4.3.9 Preventive/Mitigative Measures for MIC on Gas Pipelines .........................................25\n3.4.4 Monitoring Internal Corrosion ..............................................................................................25\n3.5 Environmentally Assisted Cracking ..........................................................................................26\n3.5.1 Stress-Corrosion Cracking (SCC) .........................................................................................26\n3.5.1.1 External SCC................................................................................................................26\n3.5.1.2 Internal SCC .................................................................................................................27\n3.5.2 Corrosion Fatigue..................................................................................................................27\nPipeline Corrosion November 2008 Page i\n\n<<<PAGE 3>>>\n\nTable of Contents\n3.5.3 Hydrogen Embrittlement.......................................................................................................28\n3.5.3.1 Hydrogen-Stress Cracking............................................................................................28\n3.5.3.2 Hydrogen-Induced Cracking ........................................................................................29\n3.5.3.3 Loss of Ductility...........................................................................................................29\n3.5.3.4 Implications for Pipelines in a National Hydrogen Economy ......................................29\n3.5.4 Sulfide-Stress Cracking.........................................................................................................29\n4 Corrosion Threat Identification...........................................................................................................31\n4.1 Overview ...................................................................................................................................31\n4.2 External Corrosion.....................................................................................................................31\n4.3 Internal Corrosion......................................................................................................................31\n4.4 Stress Corrosion Cracking.........................................................................................................31\n5 Corrosion Damage-Assessment Methods ...........................................................................................33\n5.1 Overview ...................................................................................................................................33\n5.2 In-line Inspection.......................................................................................................................33\n5.3 Hydrostatic Testing ...................................................................................................................35\n5.4 Direct Assessment .....................................................................................................................36\n5.4.1 External Corrosion Direct Assessment .................................................................................37\n5.4.2 Internal Corrosion Direct Assessment for Gas Pipelines ......................................................38\n5.4.3 Stress Corrosion Cracking Direct Assessment......................................................................40\n5.5 Emerging Technologies.............................................................................................................40\n5.5.1 Long-Range Guided-Wave Ultrasonic Testing (LRGWUT or GWUT)...............................40\n5.5.2 Remote Field Testing (RFT) .................................................................................................41\n5.5.3 Robotic Investigation ............................................................................................................42\n5.5.4 Sound-Wave Testing.............................................................................................................43\n5.5.5 NoPig ....................................................................................................................................43\n5.5.6 Buried Reference Cell Monitoring........................................................................................43\n5.6 Specialized Techniques .............................................................................................................44\n5.6.1 Microbiologically Influenced Corrosion Monitoring Techniques ........................................44\n5.7 Assessing the Severity of Corrosion..........................................................................................44\n5.8 Assessing the Severity of Stress Corrosion Cracking................................................................45\n6 Standards Review................................................................................................................................46\n6.1 Overview ...................................................................................................................................46\n6.2 Standard Development Organizations .......................................................................................46\n6.2.1 NACE International ..............................................................................................................46\n6.2.2 American Society of Mechanical Engineers .........................................................................46\n6.2.3 American Petroleum Institute................................................................................................46\n6.2.4 ASTM International ..............................................................................................................46\n6.2.5 American Society for Nondestructive Testing ......................................................................46\n6.2.6 American National Standards Institute .................................................................................46\n6.2.7 International Organization for Standardization.....................................................................47\n6.2.8 Det Norske Veritas................................................................................................................47\n6.2.9 British Standards Institute .....................................................................................................47\n6.3 U.S. Regulations and Standards ................................................................................................47\n6.3.1 U.S. Regulations....................................................................................................................47\n6.3.2 U.S. Standards.......................................................................................................................47\n6.3.3 Relevant Non-U.S. Standards................................................................................................50\n6.4 Role of Industry Best Practices Regarding Corrosion...............................................................50\n7 Corrosion Risk Management ..............................................................................................................51\n7.1 Overview ...................................................................................................................................51\n7.2 Risk Assessment Methodologies...............................................................................................51\n7.2.1 Subject Matter Expert Model ................................................................................................52\nPipeline Corrosion November 2008 Page ii\n\n<<<PAGE 4>>>\n\nTable of Contents\n7.2.2 Relative Risk Model..............................................................................................................52\n7.2.3 Probabilistic Model ...............................................................................................................53\n7.3 Characteristics of an Effective Risk Assessment.......................................................................53\n7.4 Summary....................................................................................................................................54\n8 Corrosion Research.............................................................................................................................55\n8.1 Overview ...................................................................................................................................55\n8.2 Corrosion R&D Funding Organizations....................................................................................55\n8.3 Current Corrosion R&D Efforts ................................................................................................55\n8.3.1 Prevention .............................................................................................................................55\n8.3.2 Detection ...............................................................................................................................56\n8.3.3 Assessment............................................................................................................................56\n8.3.4 Mitigation..............................................................................................................................56\n8.4 Corrosion R&D Requirements ..................................................................................................57\n8.5 Summary of Corrosion R&D Activities ....................................................................................57\n9 Elements of an Effective Corrosion Integrity Management Program.................................................58\n9.1 Overview ...................................................................................................................................58\n9.2 Technology................................................................................................................................58\n9.3 Components of an Effective Integrity Management Program...................................................58\n9.4 Resource Requirements (after Byrd, 2004) ...............................................................................59\n10 Summary and Conclusions..............................................................................................................61\n10.1 Frequency and Consequences of Corrosion Incidents...............................................................61\n10.2 Prevention of Corrosion in Pipelines.........................................................................................61\n10.3 Corrosion Threat Identification .................................................................................................63\n10.4 Assessing the Severity of Corrosion..........................................................................................63\n10.5 Regulations and Standards.........................................................................................................65\n10.5.1 Regulations .......................................................................................................................65\n10.5.2 Standard Development Organizations ..............................................................................65\n10.6 Corrosion Risk Management.....................................................................................................66\n10.7 Corrosion Research ...................................................................................................................67\n10.8 Corrosion Integrity Management Programs ..............................................................................68\n11 Bibliography ...................................................................................................................................69\n12 Appendix A.....................................................................................................................................71\n12.1 Listing of Relevant Current Research .......................................................................................71\n12.1.1 PRCI funded R&D (from Web Site):................................................................................71\n12.1.2 PHMSA Funded R&D (not listed elsewhere)...................................................................71\n12.1.3 NYSEARCH (Part of NGA).............................................................................................72\n12.1.4 AGA..................................................................................................................................72\nPipeline Corrosion November 2008 Page iii\n\n<<<PAGE 5>>>\n\nList of Abbreviations\nList of Abbreviations\nAC Alternating Current\nAGA American Gas Association\nAGM Aboveground Marker\nANB Anaerobic Bacteria\nANSI American National Standards Institute\nAOPL Association of Oil Pipelines\nAPB Acid-Producing Bacteria\nAPI American Petroleum Institute\nASME American Society of Mechanical Engineers\nASNT American Society for Nondestructive Testing\nASTM ASTM International (formerly the American Society for Testing and Materials)\nAWWA American Water Works Association\nBSI British Standards Institute\nCEPA Canadian Energy Pipeline Association\nCFR Code of Federal Regulations\nCP Cathodic Protection\nCSE Copper/Copper Sulfate Electrode\nDA Direct Assessment\nDC Direct Current\nDNV Det Norske Veritas\nDOE (U.S.) Department of Energy\nDOI (U.S.) Department of the Interior\nDOT (U.S.) Department of Transportation\nDSAW Double Submerged Arc Weld\nEAC Environmentally Assisted Cracking\nEC External Corrosion\nECDA External Corrosion Direct Assessment\nEGIG European Gas pipeline Incident data Group\nEMAT Electromagnetic Acoustic Transducer\nERCB Energy Resources Conservation Board (formerly EUB)\nERW Electric-Resistance Welded\nEUB Energy and Utilities Board (Alberta)\nFBE Fusion-Bonded Epoxy\nFFS Fitness-For-Service\nFTE Full-Time Equivalent\nGPS Global Positioning System\nGRI Gas Research Institute\nGTI Gas Technology Institute\nGUL Guided Ultrasonic\nGWUT Guided-Wave Ultrasonic Testing\nHAZ Heat-Affected Zone\nHCA High-Consequence Area\nHDD Horizontally Directionally Drilled\nHIC Hydrogen-Induced Cracking\nIC Internal Corrosion\nICDA Internal Corrosion Direct Assessment\nIDX Integrity Data Exchange\nPipeline Corrosion November 2008 Page iv\n\n<<<PAGE 6>>>\n\nList of Abbreviations\nILI In-Line Inspection\nINGAA Interstate Natural Gas Association of America\nISO International Organization for Standardization\nLDC Local Distribution Company\nLRGWUT Long-Range Guided-Wave Ultrasonic Testing\nMAOP Maximum Allowable Operating Pressure\nMFL Magnetic-Flux Leakage\nMIC Microbiologically Influenced Corrosion\nMOP Maximum Operating Pressure\nMPI Magnetic Particle Inspection\nNACE NACE International\nNDE Non-Destructive Evaluation\nNDT Non-Destructive Testing\nNEB National Energy Board (Canada)\nNETL National Energy Technology Laboratory\nNGA Northeast Gas Association\nO&M Operations and Maintenance\nOPS (U.S. Department of Transportation) Office of Pipeline Safety\nOTD Operations Technology Development Company\nPAMP Portable Acoustic Monitoring Packages\nP&M Preventative and Mitigative Measures\nPHMSA (U.S. Department of Transportation) Pipeline and Hazardous Materials Safety\nAdministration\nPRCI Pipeline Research Council International\nR&D Research and Development\nRAPID Real-Time Active Pipeline Integrity Detection\nRFEC Remote Field Eddy Current\nRFET Remote Field Electromagnetic Technique\nRFT Remote Field Testing\nRP Recommended Practice\nRSTRENG Remaining Strength of Corroded Pipe\nSATT Shear Appearance Transition Temperature\nSCC Stress Corrosion Cracking\nSCC DA Stress Corrosion Cracking Direct Assessment\nSGA Southern Gas Association\nSME Subject Matter Expert\nSMYS Specified Minimum Yield Strength\nSP Standard Practice\nSRB Sulfate-Reducing Bacteria\nSSAW Single Submerged Arc Weld\nSSC Sulfide Stress Cracking\nUT Ultrasonic Testing\nPipeline Corrosion November 2008 Page v\n\n<<<PAGE 7>>>\n\nChapter 1\n1 Introduction\nThis study was developed at the request of the U.S. Department of Transportation’s Pipeline and\nHazardous Materials Safety Administration (PHMSA) to provide a non-technical, high-level common\nunderstanding of issues related to pipeline corrosion. This study follows similar efforts by PHMSA to\nprovide information on topics regarding pipeline integrity issues in report format. The intent is that the\nreport be used to facilitate effective communication on issues with all stakeholders (public officials,\nindustry representatives, trade associations, pipeline companies, and the general public). Readers who\ndesire more technical depth are encouraged to refer to books such as Peabody’s Control of Pipeline\nCorrosion or the many technical papers published by NACE International (NACE), American Society of\nMechanical Engineers (ASME), and other technical societies and research organizations.\nThis study presents an overview of the corrosion threat to gas and liquid pipelines, focusing on the\nprevention, detection, characterization, and management of internal and external corrosion, primarily on\nonshore pipelines. The report provides concise information on the state of pipeline corrosion control, the\ngaps in current knowledge, and the direction of current research and development. While not formally or\ncomprehensively addressing corrosion of offshore pipelines, this study does highlight aspects of corrosion\nin offshore pipelines in various sections and is specific in reference when discussed.\n1.1 Corrosion Overview\nCorrosion is one of the leading causes of failures in onshore transmission pipelines (both gas and\nhazardous liquids) in the United States. It also is a threat to gas distribution mains and services, as well as\noil and gas gathering systems.\nPHMSA uses specific criteria to identify the incidents that are significant from a pipeline safety\nviewpoint. An incident is defined as significant if it meets any of the following conditions:\nFatality, or injury requiring in-patient hospitalization\n$50,000 or more in total costs, measured in 1984 dollars\nHighly volatile liquid releases of five barrels or more, or other liquid releases of 50 barrels or\nmore\nLiquid releases resulting in an unintentional fire or explosion.\nAs shown in Figure 1-1, corrosion has been responsible for 18 percent of the significant incidents (both\nonshore and offshore) in the 20-year period from 1988 through 2008. By comparison, during this same\nperiod, excavation damage accounted for 26 percent of significant incidents. By contrast, corrosion\naccounted for only 5.8 percent of all serious incidents (onshore and offshore), defined as those resulting in\nfatality or injury requiring in-patient hospitalization, during this same period, while excavation damage\nwas responsible for 34.5 percent of all serious incidents.\nNACE currently estimates the total costs attributed to all types of corrosion at $276 billion. Corrosion of\nonshore gas and liquid transmission pipelines represents $7 billion of this total. Table 1-1 shows the\nestimated corrosion costs in the 1990s for onshore transmission pipelines. The costs are broken down by\nthe cost of capital, operations and maintenance (O&M), and the cost of failures (non-related O&M costs).\nThe pipeline rehabilitation and replacement costs are included in the capital costs. O&M costs comprise\napproximately half of the total costs associated with corrosion.\nPipeline Corrosion November 2008 Page 1\n\n<<<PAGE 8>>>\n\nChapter 1\nAll Pipeline Significant Incidents (1988 – August 2008)\nFigure 1.1 – Causes of significant incidents in onshore and offshore pipelines\n(Source: PHMSA Filtered Incident Files)\nTable 1.1 – Cost of Corrosion in U. S. Transmission Onshore Pipelines\nLow Estimate\nHigh Estimate\nAverage\n(Millions of US $)\n(Millions of US $) (Millions of US $) Percent\nCost of Capital 2,500 2,840 2,670 38\nOperations and\nMaintenance (O&M) 2,420 4,840 3,630 52\nCost of Failures (Non-\nRelated O&M) 471 875 673 10\nTotal Cost Due To\nCorrosion 5,391 8,555 6,973 100\n(Source: http://www.corrosioncost.com/pdf/gasliquid.pdf ) FHWA-RD-01-156, March 2002.\n1.2 Corrosion in Perspective\n1.2.1 Frequency and Consequences in the United States\nAs is shown in Figure 1-2, there have been 40 to 65 significant corrosion incidents per year on\npipelines during the past 20 years, which averages to 52 such incidents per year. Typically, half or\nmore involve onshore liquid pipelines; the next highest frequency involves onshore gas transmission\npipelines. The pattern has been relatively consistent over time and, rather surprisingly, has not been\ninfluenced by the aging of the infrastructure. The fact that the pipeline failure rate has not increased\nsignificantly over a 20-year interval attests to the effectiveness of industry efforts at corrosion control.\nPipeline Corrosion November 2008 Page 2\n\n<<<PAGE 9>>>\n\nChapter 1\n50\n- Hazardous Liquid Onshore\n• Hazardous Liquid Offshore\nNumber of Significant Incidents\n40\nGas Transmission Onshore\n30\nGas Transmission Offshore\nGas Gathering\n- Gas Distribution\n- Total Significant Corrosion\n1030\n1900\n1053\n1,050\n2000\n1002\n100° ,006\nYear\n(Source: PHMSA Filtered Incident Files)\nFigure 1.2- History of significant corrosion incidents in the U.S.\nThe 1,074 significant incidents during that 20-year period resulted in 30 fatalities, 100 injuries, and\nwhich resulted in 147 fatalities, 619 injuries, and $518 million in property damage. Table 1-2\n$551 million in property damage. This contrasts with 1,552 significant excavation damage incidents\npresents comparable data on significant corrosion incident consequences.\nTable 1.2 - Average Annual Consequences of Significant Corrosion Incidents Between 1988 and 2007\nType of Pipeline\nMileage\n1988\n2007\nNumber\nFatalities\nInjuries\nProperty\nDamage\nHazardous Liquid\n153K\n166K\nOnshore\n33\n0.05\n0.8\n$14M\nOffshore\n0.9\n0\n0\n$1.7M\nGas Transmission\nOnshore\n284K\n294K\n7.7\n0.6\n0.2\n$8.2M\nOffshore\n7K\n7K\nGas Gathering\n32K\n4.4\n0\n0\n20K\n2.7\n0\n$1.2M\n0.2\n$1.2M\nGas Distribution\n802K\nTotal\n1278K\n1172K\n3.4\n0.8\n3.9\n1659K\n51.9\n1.4\n5.2\n$0.6M\n$25M\n(Source: PHMSA Filtered Incident Files)\n1.2.2 Transmission Pipelines\nAs is shown in Figures 1-3 and 1-4, corrosion accounts for about 23 percent of the significant failures\nin both hazardous liquid and gas transmission pipelines. In terms of absolute numbers, there were\nmore significant failures and more property damage associated with liquid pipelines than with gas\nPipeline Corrosion\nNovember 2008\nPage 3\n\n<<<PAGE 10>>>\n\nChapter 1\nHazardous Liquid Pipeline Significant Incidents (1988 – August 2008)\nFigure 1.3 – Causes of significant incidents in onshore and offshore hazardous liquid transmission pipelines\n(Source: PHMSA Filtered Incident Files)\nGas Transmission Pipeline Significant Incidents (1988 – August 2008)\nFigure 1.4 – Causes of significant incidents in onshore and offshore natural gas transmission pipelines\n(Source: PHMSA Filtered Incident Files)\nPipeline Corrosion November 2008 Page 4\n\n<<<PAGE 11>>>\n\nChapter 1\nCorrosion failures can be either leaks or ruptures. Leaks are more common. Leaks from gas pipelines\ngenerally do not cause property damage, because the escaping gas disperses into the atmosphere.\nHowever, leaks from a liquid line can contaminate the soil, groundwater or surface water.\nConversely, ruptures in a gas pipeline are more likely to cause an explosion and fire, thus resulting in\nmore fatalities and injuries on average.\nAlmost all of the corrosion incidents in liquid pipelines have involved onshore lines. The few\nimpacting offshore lines have caused neither fatalities nor injuries, which is not surprising, since the\nprobability of an individual being in proximity to an offshore failure is extremely remote.\nOn a per-mile basis, a disproportionate number of reported corrosion failures in gas transmission\npipelines occurred offshore, but 97 percent were due to internal corrosion. Conversely, 77 percent of\nthe onshore incidents were due to external corrosion.\n1.2.3 Natural Gas Distribution Pipelines\nExternal force damage is much more prevalent for distribution pipelines than for transmission\npipelines since the majority of distribution pipelines are non-metallic and generally are located in\nmore densely populated areas. The failure rate of distribution pipelines due to various causes is shown\nin Figure 1-5.\nGas Distribution Pipeline Significant Incidents (1988 – August 2008)\nFigure 1.5 – Causes of significant incidents in natural gas distribution pipelines\n(Source: PHMSA Filtered Incident Files)\nExternal corrosion causes more than 90 percent of corrosion-related failure in distribution pipelines.\nPrior to the implementation of 49 CFR Part 192 in 1970, distribution pipelines were required neither\nto be coated nor to have cathodic protection. In the 1950s, many operators did coat their distribution\nmains and services but did not provide cathodic protection until required to do so. Therefore, older\ndistribution systems may contain many miles of pipe that have been unprotected for some time and\nhave suffered corrosion damage.\nDistribution pipelines are not thought to be as prone to internal corrosion as transmission pipelines\nbecause they are located further downstream from gathering and production systems which might\nPipeline Corrosion November 2008 Page 5\n\n<<<PAGE 12>>>\n\nChapter 1\nintroduce water into the gas stream. Since many of the gathering and transmission systems have\nequipment to scrub and clean the gas stream, internal corrosion in the gas transmission system is not\nas prevalent a threat as it was prior to the installation of cleaning and conditioning equipment. Early\ntransmission lines did not perform this function, and there is evidence that they may contain inactive\ninternal corrosion.\nIf a distribution pipeline is near a storage field and the transmission system operator does not\nsufficiently dehydrate and clean the stored gas prior to its introduction into the distribution system,\ninternal corrosion in the distribution pipeline can occur. Distribution companies have tariffs and\nspecifications that limit the amount of water that can be present in their delivered gas (whether from a\ntransmission pipeline or storage field).\n1.2.4 Gas Gathering Lines\nGas gathering lines account for very few corrosion failures, and those failures that have occurred\nresulted in no fatalities and very few injuries. More than 90 percent of the reported incidents were\ncaused by internal corrosion.\n1.2.5 Non-U.S. Experience\nThere are substantial differences between the Canadian pipeline system and the U.S. system. Besides\nencompassing only 20 percent as many miles, the Canadian pipelines are of much more recent\nconstruction, on average, which not only means that they have had less time to corrode, but also that\nthey have benefited from newer and better coatings as well as more consistently applied cathodic\nprotection. In addition, because of the low population density in Canada, outside force damage is\nextremely low. Consequently, the Canadian experience, as illustrated in Figure 1-6, is somewhat\ndifferent from the U.S. experience. Corrosion failures, including stress-corrosion cracking (SCC),\nmade up about half of the failures in Canadian gas transmission systems – more than twice the\nproportion realized in the United States.\n8.7%\n4.3%\n8.7%\n4.3%\n50.0%\n6.5%\nCorrosion\nExcavation Damage\nOperational\nMaterial failure\nNatural Forces\nFatigue\nAll Other\n17.9%\nFigure 1.6 – Causes of the 46 ruptures that occurred in Canadian pipelines from 1984-2004\n(Source: National Energy Board. [2008, July]. Focus on Safety and the Environment.\nA Comparative Analysis of Pipeline Performance, 2000 – 2006)\nPipeline Corrosion November 2008 Page 6\n\n<<<PAGE 13>>>\n\nChapter 1\nAs is shown in Figure 1-7, Europe, on the other hand, has experienced a slightly lower proportion of\ncorrosion failures but a much higher proportion of outside force damage failures. This can be\nattributed to high population density, which has significantly increased the outside force failure rate.\nFigure 1.7– European pipeline incident causes\n(Source: The 6th EGIG Report, 1970 – 2004. [2005, December]. Gas Pipeline Incidents.\nDoc. Number EGIG 05.R.0002)\nFigure 1-8 shows that the U. S. experience with corrosion failures as a percentage of total incidents\n(not on a per-mile basis) falls within the middle range between the European (lower) and Canadian\n(higher).This difference probably is primarily due to differences in population density.\nPipeline Corrosion November 2008 Page 7\n\n<<<PAGE 14>>>\n\nChapter 1\nRupture Primary Cause Comparison\nPercent of All Causes\n70%\n60%\n50%\n40%\n30%\n20%\n10%\n0%\nNEB (1991-2006)\nERCB (2000-2006)\nEGIG (1970-2004)\nPHMSA (1991-2006)\nCorrosion M aterial\n(M anufacturing\nor Construction)\nOther Causes External\nInterference\nGeotechnical\nPrimary Causes\nFigure 1.8 – Comparison of pipeline failure causes for Canada (NEB and ERCB), Europe\n(EGIG) and the US (PHMSA)\n(Source: National Energy Board. [2008, July]. Focus on Safety and the Environment. A\nComparative Analysis of Pipeline Performance, 2000 - 2006)\n1.3 State of Knowledge Regarding Corrosion\nFrom a scientific point of view, corrosion is well understood, both in terms of causal mechanisms and\nmethod of control. The corrosion behavior of a piece of steel in a beaker of salt water is predictable and\ncontrollable.\nHowever, despite the current level of industry knowledge, pipelines continue to experience a modest but\nsignificant number of failures due to corrosion. The reason is that the corrosion behavior of a buried\npipeline is much more complicated than that of a piece of steel in a beaker of salt water. The most\nimportant factors that complicate the investigation and/or mitigation of corrosion include the following:\nThe chemical properties of the environment surrounding a buried pipeline are not adequately\nunderstood.\nVariations in the oxygen content, moisture content, and chemical composition of the soil along\nthe pipe length and from top to bottom of the pipe can act as concentration cells that promote\ncorrosion.\nMoisture content and oxygen content of the soil also vary with time.\nCoating quality varies along the length of a pipeline.\nCoatings sometimes become disbonded from the pipe surface, allowing groundwater to contact\nthe steel but shielding the steel from cathodic-protection currents.\nDisbonded coating will prevent aboveground survey detection of underlying corrosive conditions.\nPhysical variations in soil characteristics and placement (gaps, etc.) affect the distribution of\ncathodic-protection current.\nPipeline Corrosion November 2008 Page 8\n\n<<<PAGE 15>>>\n\nChapter 1\nVisual inspection of the outside of the pipe and the coating require excavation.\nStray currents from nearby buried structures can interfere with a pipeline’s cathodic-protection\nsystem.\nThus, the pipeline engineer is faced with a challenging problem – preventing corrosion in a very lengthy\n(and frequently large-diameter) metal structure contained within a unique environment of predominantly\nundetermined chemical and physical properties – without the means for direct observation of the majority\nof the structure’s length.\nPipeline Corrosion November 2008 Page 9\n\n<<<PAGE 16>>>\n\nChapter 2\n2 Background\n2.1 Problem Statement\nA reduction in the number of corrosion incidents is desirable both a safety and financial standpoint. The\nPipeline and Hazardous Materials Safety Administration (PHMSA), industry trade organizations, and the\nscientific community have worked to increase pipeline safety and reduce incidents and related costs for\nmany years and, in fact, have made significant improvements to corrosion detection, assessment, and\nmitigation technology. However, not all stakeholders and decision-makers engaged in discussions of\nissues such as continued research funding, regulatory review and legislative oversight of corrosion-related\nissues have a fundamentally sound understanding of pipeline corrosion.\n2.2 Project Scope\nThis project was initiated to facilitate communications among all stakeholders engaged in the discussion\nof corrosion-related issues, including PHMSA personnel, state and federal regulators, elected officials and\ntheir staffs, representatives form the pipeline industry and the research community, as well as the general\npublic by producing a document that would provide all stakeholders with a common, high-level\nunderstanding of the issues involved.\n2.3 Report Outline\nThis report has been structured to address the following subjects:\nDescription of the types of corrosion found on pipelines and the methods of management for each\nFactors to consider in deciding which types of corrosion may be a threat to a specific pipeline\nCurrent methods to assess the extent or severity of corrosion on an existing pipeline\nStandards and regulations governing pipeline corrosion inspection and management\nMethods used by the industry to manage the risk of corrosion\nCurrent research and development programs directed at developing better tools and methods to\nmanage corrosion, and identifying gaps that are not being addressed\nElements of an effective corrosion integrity management prog","truncated":true,"body_characters":212250}