Covino, Brenard S. (U.S. Department of Energy) | Cramer, Steven D. (U.S. Department of Energy) | Bullard, Sophie J. (U.S. Department of Energy) | Holcomb, Gordon R. (U.S. Department of Energy) | Moroz, Malgorzata Ziomek (U.S. Department of Energy) | Kane, Russell D. (InterCorr International Inc) | Eden, Dawn C. (InterCorr International Inc)
This paper is a report on the evaluation of the use of electrochemical corrosion rate probes to detect internal corrosion in natural gas transmission pipeline environments. Flange and flush-mount probes were used in four different environments at three different sites that were selected to represent normal and upset conditions in a gas transmission pipeline. The environments consisted of humidified natural gas, organic/water mixtures removed from natural gas, and the environments at the 6 and 12 o?clock positions of a natural gas pipeline carrying multiphase gas/liquid flow. This paper will summarize and extend results presented previously and add additional data. A re-analysis of previously-reported data will be presented along with the results of physical examinations on the probes. New data on the measurement of corrosion in multiphase gas/liquid environments and for coupons used to determine corrosion rate and to detect the presence of microbiologically-influenced corrosion (MIC) will also be presented.
Natural gas transmission pipelines are essential to the economics and security of most nations. In the US and Canada, the 180,000 mile network of steel transmission pipelines is more than 50 years old and has suffered some deterioration due to corrosion. While corrosion can occur on both external and internal surfaces of pipelines, internal corrosion is the subject of interest for this paper. Current methods of determining internal corrosion attack in pipelines rely on after-the-fact inspections using smart pigs.
A study1 conducted in the USA from 1970 to 1984 reported that 54% of the service failures to gas pipelines were attributable to outside forces such as earth movement, weather, and third party equipment operation. In addition, 17% were attributable to material failures, and 17% to corrosion. A later study2 in Canada from 1980 to 1997 concluded that 63% of pipeline failures were caused by corrosion, with 50% due to internal corrosion and 13% due to external corrosion.
While external corrosion of pipelines is controlled by the use of barriers and cathodic protection (CP), instances of corrosion and stress corrosion cracking (SCC) have been reported3. External corrosion of gas transmission pipelines is usually controlled by the application of various polymeric coatings augmented with CP. When corrosion does occur on the outside of the pipeline, the combination of general and localized corrosion with the high stresses in the pressurized pipelines can sometimes lead to SCC. In cases where CP is inadequate or nonexistent, pipelines exposed to ground waters can experience transgranular SCC due to exposure to low pH (6.5) CO2-containing ground water. In cases where CP is adequate, gas pipelines may also be susceptible to intergranular SCC due to higher pH environments created adjacent to the pipeline3.