Internal Corrosion Direct Assessment Detection of Water

016431042010Final Report, Rev. 3PDFTech ReportEAWUS811-80612405, Rev. 3Detection and identificationInspectionNatural gas pipelinesPipeline safetyWaterWireless communication systemsHazardous liquids pipelinesHydrostatic testsInternal corrosion (Pipelines)Internal corrosion direct assessment processPiggingPipeline integrity managementResearch HubUnited StatesDet Norske Veritas, IncorporatedBrossia, C. SeanDet Norske Veritas, IncorporatedUnited States. Dept. of Transportation. Pipeline and Hazardous Materials Safety AdministrationUS Transportation CollectionInternal corrosion of natural gas pipelines is the result of interaction between the inside pipe wall and impurities in the product being transported. Such interactions can lead to an overall loss of material thereby thinning the pipe wall and thus reducing the range of operating pressure. Corrosion, however, tends to be localized along the pipeline with some areas experiencing significant corrosion rates and others much less so. Part of the variability arises from both spatial and temporal differences in the composition of the product. For example, brines may be observed in segments of natural gas pipelines close to producing areas (i.e., carry-over produced water), but condensed water are more likely further downstream (i.e., without chlorides). Some of the common corrosion inducing species includes carbon dioxide, hydrogen sulfide, water, salts (such as chloride), solids and precipitates, organic acids, and microorganisms. As a consequence of the wide range of possible corrosion inducing species, their inherent variability with both position and time within the pipeline, accurate inspection and determination of the true condition within the pipeline is difficult