{"operation":"document","citation":"PHMSA Guidance, DIMP - Pipeline Corrosion Poster","title":"DIMP - Pipeline Corrosion Poster","source_type":"guidance","agency":"Pipeline and Hazardous Materials Safety Administration","status":"guidance","official":true,"published_on":null,"effective_on":null,"summary":"DIMP - Pipeline Corrosion Poster Document corrosionposter.pdf (581.01 KB) Informational text-heavy poster on pipeline corrosion. Effective Date: Tuesday, January 1, 2008","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-guidance-dimp-pipeline-corrosion-poster-dca5da76.json","markdown":"https://regulus.evalyn.ai/document/phmsa-guidance-dimp-pipeline-corrosion-poster-dca5da76.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-guidance-dimp-pipeline-corrosion-poster-dca5da76","source_url":"https://www.phmsa.dot.gov/pipeline/gas-distribution-integrity-management/dimp-pipeline-corrosion-poster","body":"DIMP - Pipeline Corrosion Poster\n\nDocument\n\n corrosionposter.pdf (581.01 KB)\n\n        Informational text-heavy poster on pipeline corrosion.\n\n          Effective Date: Tuesday, January 1, 2008\n\n<<<PAGE 1>>>\n\nPIPELINE CORROSION\nCORROSION IN PERSPECTIVE\nCOST OF\nGAS TRANSMISSION PIPELINE SIGNIFICANT INCIDENTS (1988 - August 2008)\nIN PIPELINES\nCORROSION\nBASIC CORROSION THEORY\nThe average annual corrosion-related\ncosts for onshore natural gas and\nis estimated to de su oillion. which\n(38 percent), operation and\ncan be divided into the cost of capital\n(10 percent).\nmaintenance (52 percent) and failures\n$7.0 Billion\nReturn Path (metallic)\nclecton row→*\nHAZARDOUS LIQUID PIPELINE SIGNIPICANT INCIDENTS (1988 - August 2008)\nSource: FHWA-RD-01-156. March 2002\nElectrolyte\nrelated significant pipeline incidents per year over the\nOn average, there have been about 52 corrosion-\nincidents insolied liquid pipelines 23 percent occurred\npast tusenta years Approximatel 64 percent of the\nANOUC\n0,+24,0+40 - 40H\nCATHODE\non gas trangmission pipelines. 7 percent on gas\nGAS DISTRIBUTION PIPELINE SIGNIFICANT INCIDENTS (1988 - August 2008\ngathering pipelines and 6 percent on gas distribution\nsystems\nThe primary method of preventing and mitigating external corrosion on buried pipelines involves a combination of\nCORROSION\nEXTERNAL\nfrom the anodic areas of the pipeline, rendering exposed portions of the pipeline surface cathodic. Coatings are\nfrom external sources (sacrificial anodes and/or induced current) sufficient enough to nullity any outgoing currents\ncamnodic orotection ano coalinos. camnedic protection involves dooivine a cuitent to me bipeine mrouen me sol\napplied to hot rotating pipe that is electrically charged. FBE is resistant to high temperatures, can withstand high\nintended to reduce the surface area of exposed metal on the pipeline, thereby reducing the current necessary (and\nstresses, and provides good protection against corrosion.\ncost) to cathodicallv protect the metal. The most widelv used pipe coatina is Fusion Bonded Eooxy (FBE) which is\nCurrent Through\nReturn-Flow\nLocalized corrosion -\nPreviously\ntypicaly mallesls ds\nINTERNAL CORROSION\nof Direct Current\nPipeline to Source\npitting on a small area of\nAnodic Areas\nunior across une sunace\nme mela and is not\nBiturg ortrie pire wall\nUniform/general corrosion -\nwhich procecas di\neneral, but irregular,\nbeing corroded\nrale over une wnole sunace\naporoximatery une same\n•Cosseront aste lines\nhydration/Separation - removal of condensation and free water\n• - Not very ettective as sole measure, but can be\nBURIED PIPELINE\niocidos - Injected into the product stream to kil microbes that cause\nng Pigs - removal of liquids and contaminates that buildup in\nCathodic Protection Current\na - Introducten of abring agent to reduce corrosivity of any\nSource of\nCanceled\nDirect Current\nCurrent\nCorrosion\nAuxiliary Ground Connection\n(Usuallý Termed \"Ground Bed\nneral conosion ofonde i patine\nCORROSION DAMAGE ASSESSMENT METHODS\nREGULATIONS AND\nSTANDARDS\nASSISTED CRACKING\nENVIRONMENTALLY\nTo assess the structural integrity of a pipeline that may contain corrosion defects, 49 CFR Part 192 (gas)\nand 49 CFR Part 195 (liquid) recognize three acceptable approches:\nPHMSA\n• Relerred to as smartoccinol\n• Provides verv good coverage\nIn-Line inspection (ILI\nHarostauc lesuing\n• The location ad size of all\ndefects\nand ability to locate corrosion\n• Requires filling a section of\npressuring it significantly\nthe pipeline with water and\n• Typically used where hydrostatic or ILI testing is\nDirect Assessment\npetroleum, and other hazardous materiais by pipeline.\ns a form of Environmentally As\nairess corrosion cracking sc\ninternal and external wall loss\n• Detects defects, such as\nabove normal operating\n• Involves a 4 step process using a combination of\nimpractical\nnatural gas pipelines, 49 CFR Part 192, Subpart I, 55192451 to 192.\ncombination or tensile suress and\nsisted Cracking (EAC), in which a\ncorrosion technologies accompanied by physical\nmenent orme protection of metalie peines fom externat internal, and armo-\nto operating pipelines).\nmy cess or a concern\nCommon fea-\narc prygawic\nhrough the line - not all lines\nfor \"pigs\" to pass\ncorrosion pits or cracks, by\n3) Direct examination\nare meant\ntecting steel pipelines against corrosion.\nyear in the US.\nto corrosion or cathodic protection)\nThe two types of external SCC\nwhich can seriously reduce the ductil-\nource of water and\nconsensus organizatons\nThese regulations incorporate standards that are developed by various industry\nof high-pH SCC, whose crack\n-pH SCC aost instances\nmetal, causing cracking and cata-\nstrophic brittle failures\nity and load-bearing capacity of the\ndisposal of water could be a\nsevere enough to cause a failure before the next\nNACE International (NACE) is the principal professional\n• Requires that the pipeline be\nNACE\nTound cownstream orgas com\ncreasino temperature nave been\npressor stations and r\narely on\npipe (i.e., X52).\nand at \"hard spots\" of lower strength\nremoved wom service wner\ntested\ncorrosion for pipelines that carry normally dry gas, and SCC).\nSCC has been detected on off-\nng (SSC) can\nCORROSION DAMAGE ASSESSMENT\n9 (ASNT), American National Stan-\nno reports of memal sue in pipe-\nnally. trom okb in soil or water in cor\nreducing bacteria (SRB); and exter-\nCosts for Corrosion Damage Assessment Methods\nof 2002. This law requires PHUMSA/OPS to issue regulations prescribing\nntegrita Management\nstandant to derect a natural ges septem operator to conduct a ride andisis anal\nOn Vovember 15, 2002. Congres passed the Pipeline Safety Improvement Act\nthat contain fuel-grade ethanol.\ndue to 55c are relatively tew, with in-\nHigh Concequence Areas (HICAs). These requirements have been incorporated\nadopt and implement en integity management program (FP). The soute sets\nstress are more susceptible to SSC.\nforth mininun reqirements for MPs for ges transmision pipelines located in\nLever of eus and contest eng\nthat could be exposed to wet hydro-\nPrevention of ssc lallures in pipelines\nWEAKNESS\nnal corrosion, ederal corrosion and SCC as threats that mut be considered\nfor ges pipelines\nnich residual stress\nment of regions of high hardness and\nwelding processes to avoid induce-\nSimilarle MP requirements for hazardous liquid pipelines effective May 29, 2001.\nand Februar 15, 2002, specify regulations to\nthe integrita of hazardous liquid pipeline\nexdhuate, repair\netie cros of high probabily\ntenses iR CFR Part 195/452 addreses 4P requirements for hazardous\nlipid pipelines including the need to asess for corrosion.\nen atl encie to envoient dorane and commercicle neucat\nhigh pressen, ges tronicien pied\nPrepared for DOT/PHMSA/OPS by Michael Baker Jr., Inc. 2008","truncated":false,"body_characters":6723}