INTRODUCTION
A method to evaluate the corrosive environment of annular spaces within casings of natural gas transmission pipelines using commercially available, “off the shelf” equipment has been devised and implemented. Three separate locations were selected for test monitoring of corrosion rates on steel carrier pipelines operating within these environments. The locations were monitored for 22-26 months and average corrosion rates were established for a variety of representative conditions. Test results confirmed the initial hypothesis that cased pipeline segments exist in relatively benign environments as long as cathodic protection/coating systems and electrical isolation status between carrier and casing are maintained. These results lend further credence to the position that cased segments are inherently safer than uncased segments due to the extra layer of protection from third party damage which remains the most significant threat to pipeline integrity.
Local natural gas distribution and transmission operating companies (LDC's) are subject to Federal regulations which require a baseline assessment of cased pipeline segments located in High Consequence Areas (HCA's). The present deadline to perform this assessment is December 17, 2012. Traditional methodologies (CIS, DCVG, PCM, etc.) presently being utilized in conjunction with External Corrosion Direct Assessment (ECDA) protocols to identify areas for direct examination on direct buried transmission pipelines are useful in detecting gross anomalies such as casing contacts (shorts) but are of limited value in detecting discrete conditions such as coating flaws or corrosion defects within the annular space of cased pipeline segments. Hydrostatic Testing and In-Line Inspection (ILI) techniques are typically not feasible for use by LDC's. It is usually not possible to take these lines out of service for extended time periods as would be required for Hydrostatic Testing and the existence of multiple valve sets, pipe offsets and pipe bends usually precludes the use of ILI. Multiple technologies are currently being tested, however other than direct examination, no single procedure or technology has yet been identified to perform an accurate assessment of cased pipeline segments in all types of environments. At the present time, it would appear that the majority of industry is deferring the assessment of cased pipelines because casing removal and direct pipe examination is cost prohibitive and in many instances not practical or feasible. It is important to recognize that the monitoring protocol discussed herein is not presented as a method to identify discrete anomalies, but rather as a tool to draw general conclusions relative to representative corrosive conditions within cased crossings. Consolidated Edison Company of New York operates a natural gas transmission system with multiple cased pipeline segments. To date, these segments have not experienced any failures. The pipelines are of welded steel construction, are well coated with coal tar enamel and cathodically protected. A majority of the casing population (95%) consists of abandoned cast iron that was utilized for ease of construction when the present system was constructed (starting in the early 1950's). The carrier pipes were installed in the casings with dielectric casing spacers.
