# DIMP - Pipeline Corrosion Poster - **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:** Not available - **effective on:** Not available - **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 Document corrosionposter.pdf (581.01 KB) Informational text-heavy poster on pipeline corrosion. Effective Date: Tuesday, January 1, 2008 <<>> PIPELINE CORROSION CORROSION IN PERSPECTIVE COST OF GAS TRANSMISSION PIPELINE SIGNIFICANT INCIDENTS (1988 - August 2008) IN PIPELINES CORROSION BASIC CORROSION THEORY The average annual corrosion-related costs for onshore natural gas and is estimated to de su oillion. which (38 percent), operation and can be divided into the cost of capital (10 percent). maintenance (52 percent) and failures $7.0 Billion Return Path (metallic) clecton row→* HAZARDOUS LIQUID PIPELINE SIGNIPICANT INCIDENTS (1988 - August 2008) Source: FHWA-RD-01-156. March 2002 Electrolyte related significant pipeline incidents per year over the On average, there have been about 52 corrosion- incidents insolied liquid pipelines 23 percent occurred past tusenta years Approximatel 64 percent of the ANOUC 0,+24,0+40 - 40H CATHODE on gas trangmission pipelines. 7 percent on gas GAS DISTRIBUTION PIPELINE SIGNIFICANT INCIDENTS (1988 - August 2008 gathering pipelines and 6 percent on gas distribution systems The primary method of preventing and mitigating external corrosion on buried pipelines involves a combination of CORROSION EXTERNAL from the anodic areas of the pipeline, rendering exposed portions of the pipeline surface cathodic. Coatings are from external sources (sacrificial anodes and/or induced current) sufficient enough to nullity any outgoing currents camnodic orotection ano coalinos. camnedic protection involves dooivine a cuitent to me bipeine mrouen me sol applied to hot rotating pipe that is electrically charged. FBE is resistant to high temperatures, can withstand high intended to reduce the surface area of exposed metal on the pipeline, thereby reducing the current necessary (and stresses, and provides good protection against corrosion. cost) to cathodicallv protect the metal. The most widelv used pipe coatina is Fusion Bonded Eooxy (FBE) which is Current Through Return-Flow Localized corrosion - Previously typicaly mallesls ds INTERNAL CORROSION of Direct Current Pipeline to Source pitting on a small area of Anodic Areas unior across une sunace me mela and is not Biturg ortrie pire wall Uniform/general corrosion - which procecas di eneral, but irregular, being corroded rale over une wnole sunace aporoximatery une same •Cosseront aste lines hydration/Separation - removal of condensation and free water • - Not very ettective as sole measure, but can be BURIED PIPELINE iocidos - Injected into the product stream to kil microbes that cause ng Pigs - removal of liquids and contaminates that buildup in Cathodic Protection Current a - Introducten of abring agent to reduce corrosivity of any Source of Canceled Direct Current Current Corrosion Auxiliary Ground Connection (Usuallý Termed "Ground Bed neral conosion ofonde i patine CORROSION DAMAGE ASSESSMENT METHODS REGULATIONS AND STANDARDS ASSISTED CRACKING ENVIRONMENTALLY To assess the structural integrity of a pipeline that may contain corrosion defects, 49 CFR Part 192 (gas) and 49 CFR Part 195 (liquid) recognize three acceptable approches: PHMSA • Relerred to as smartoccinol • Provides verv good coverage In-Line inspection (ILI Harostauc lesuing • The location ad size of all defects and ability to locate corrosion • Requires filling a section of pressuring it significantly the pipeline with water and • Typically used where hydrostatic or ILI testing is Direct Assessment petroleum, and other hazardous materiais by pipeline. s a form of Environmentally As airess corrosion cracking sc internal and external wall loss • Detects defects, such as above normal operating • Involves a 4 step process using a combination of impractical natural gas pipelines, 49 CFR Part 192, Subpart I, 55192451 to 192. combination or tensile suress and sisted Cracking (EAC), in which a corrosion technologies accompanied by physical menent orme protection of metalie peines fom externat internal, and armo- to operating pipelines). my cess or a concern Common fea- arc prygawic hrough the line - not all lines for "pigs" to pass corrosion pits or cracks, by 3) Direct examination are meant tecting steel pipelines against corrosion. year in the US. to corrosion or cathodic protection) The two types of external SCC which can seriously reduce the ductil- ource of water and consensus organizatons These regulations incorporate standards that are developed by various industry of high-pH SCC, whose crack -pH SCC aost instances metal, causing cracking and cata- strophic brittle failures ity and load-bearing capacity of the disposal of water could be a severe enough to cause a failure before the next NACE International (NACE) is the principal professional • Requires that the pipeline be NACE Tound cownstream orgas com creasino temperature nave been pressor stations and r arely on pipe (i.e., X52). and at "hard spots" of lower strength removed wom service wner tested corrosion for pipelines that carry normally dry gas, and SCC). SCC has been detected on off- ng (SSC) can CORROSION DAMAGE ASSESSMENT 9 (ASNT), American National Stan- no reports of memal sue in pipe- nally. trom okb in soil or water in cor reducing bacteria (SRB); and exter- Costs for Corrosion Damage Assessment Methods of 2002. This law requires PHUMSA/OPS to issue regulations prescribing ntegrita Management standant to derect a natural ges septem operator to conduct a ride andisis anal On Vovember 15, 2002. Congres passed the Pipeline Safety Improvement Act that contain fuel-grade ethanol. due to 55c are relatively tew, with in- High Concequence Areas (HICAs). These requirements have been incorporated adopt and implement en integity management program (FP). The soute sets stress are more susceptible to SSC. forth mininun reqirements for MPs for ges transmision pipelines located in Lever of eus and contest eng that could be exposed to wet hydro- Prevention of ssc lallures in pipelines WEAKNESS nal corrosion, ederal corrosion and SCC as threats that mut be considered for ges pipelines nich residual stress ment of regions of high hardness and welding processes to avoid induce- Similarle MP requirements for hazardous liquid pipelines effective May 29, 2001. and Februar 15, 2002, specify regulations to the integrita of hazardous liquid pipeline exdhuate, repair etie cros of high probabily tenses iR CFR Part 195/452 addreses 4P requirements for hazardous lipid pipelines including the need to asess for corrosion. en atl encie to envoient dorane and commercicle neucat high pressen, ges tronicien pied Prepared for DOT/PHMSA/OPS by Michael Baker Jr., Inc. 2008 - **truncated:** false - **body characters:** 6723