Other than SCC (stress corrosion cracking) and internal corrosion ruptures of pipelines; it has been a long time since typical external corrosion has caused a pipeline rupture. Pipeline coatings, cathodic protection, CIS (Close Interval Survey), gas leak surveys, and ILI (inline inspection) has been very effective in almost totally eliminating typical external corrosion as a cause of pipeline ruptures. Therefore the news release from NTSB that this pipeline rupture was due to typical external corrosion and not SCC, Pre-1970 ERW pipe seam fatigue failure, or internal corrosion was a surprise. Most consider typical external corrosion now days to be only the cause of leaks.
Pipeline ruptures due to external corrosion outside of pipe seams are now rare. For a rupture to occur the corrosion pitting has to be both deep and long. Deep Corrosion pitting of short length will result only in a gas leak which is typically found by dead plants over the pipeline or a gas leak survey. Typically the pipe coating will limit the length of corrosion pitting to a size that only results in a gas leak.
Only if there is a significant coating failure will corrosion pitting be capable of having sufficient length with deep pitting to result in a pipeline rupture. ILI (Inline Inspection) tools care capable of finding corrosion pitting before a gas leak or pipeline rupture occur, but not all pipelines are designed for the passage of an ILI tool. Information released so far indicates that the pipeline that failed had not been upgraded for the passage of an ILI tool.
The following is required for upgrading a pipeline built before federal minimum pipeline safety rules required that all new pipelines be designed for the passage of ILI tools:
- replace mainline gate valves with full opening ball valves that allow the passage of a ILI tool
- replace pipeline bends that are too short radius for the passage of ILI tools
- replace unbarred tees with barred tees that may not allow the passage of ILI tools
- remove any known pipeline feature that may damage or not allow the passage of an ILI tool
- run a caliper, plate tool, or geometry tool that will verify the pipeline is ready for the running of an ILI metal loss tool or find features that need to removed before running a ILI metal loss tool
For pipelines that cannot be inspected by ILI tools, ECDA (External Corrosion Direct Accessment) with ICDA (Internal Corrosion Direct Assessment) is performed. Since the pipeline that failed was downstream of a gas storage field, odds are an internal corrosion threat existed on the pipeline that would have required ICDA. The pipeline per news releases had a ERW (electric resistance weld) seam which would have been a pre-1970 ERW seam per the construction date of this segment of the pipeline. Since this type of seam has had service issues due to quality control issues during manufacturing, the pipeline would have had a manufacturing defect threat which would require evaluation to determine if this threat was stable or not stable. Typically, manufacturing defects like Pre-1970 pipe seams are stable and the rupture of this pipeline was outside of the ERW seam.
Per the NTSB investigation so far, the failure was due to external corrosion on the bottom of the pipe that resulted in significant wall thinning. The wall thinning was described as being approximately 6 feet long with as much as 70% wall thickness reduction is some locations. Wall thinning of this length and depth is sufficient to result in a rupture of the pipeline. There has been nothing stated to date that internal corrosion on the bottom of the pipe may have contributed to the wall thinning that resulted in a rupture of the pipe.
External corrosion does favor the bottom of the pipe due to a oxygen concentration cell effect that makes the pipe bottom anodic to the rest of the pipe surface. The bottom of the pipe has less oxygen in the soil next to the pipe surface. This corrosion cell can result in deep corrosion pitting which on large diameter pipelines may not be detected by over-the-line-survey CIS (Close Interval Survey) as such surveys record an average pipe-to-soil potential of the pipe surface and not the lowest pipe-to-soil potential on the pipe surface. In addition, over the line surveys tend to not detect corrosion cells on the bottom of the pipe as effectively as corrosion cells are top of the pipe. Corrosion cell activity under disbonded coatings can decrease the effectiveness of over-the-line surveys in detecting possible corrosion activity. MIC (microbiologically influenced corrosion) may accelerate the oxygen concentration cell corrosion cell activity by deplorizing the pipe surface, increasing the amount of cathodic protection current required to create a polarized pipe surface at coating holidays, and requiring an increase in the cathodic protection criterion to a value greater than -850 mV. From photos of the failure site, MIC probably was not a contributing factor in the pipeline failure but cannot be totally ruled out.
ACVG (Alternating Current Voltage Gradient) and DCVG (Direct Current Voltage Gradient) pipe coating surveys may sometimes detect coating damage on the bottom of a large diameter pipeline that a typical CIS inspection may miss due to the average pipe-to-soil potential effect. All methods of finding coating damage that may result in corrosion damage to the pipeline have limited effectiveness if the pipe coating has significant disbondment to the pipe surface with trapped water and few coating holidays. All pipeline coating surveys tend to detect coating holidays more effectively than disbonded coating. The best way of detecting disbonded pipe coating is a ILI EMAT tool.
The photos of the failure site suggests that the backfill around the pipe that failed may have had sufficient rock and stone to damage coal tar and asphalt pipe coatings used at the time the pipeline was built. The amount of clean backfill placed around the pipe during construction would influence how much coating damage may have occurred during backfilling. Cold Applied Tapes were not in much use when the pipeline was built and probably was not the coating system applied to the pipe. Asphalt pipe coatings were popular during the period the pipeline was built and tend to have coating disbondment issues which may result in shielded corrosion cell activity. At this time the pipe coating system on the pipeline that failed has not been stated. The condition of the pipe coating where the failure occurred will be impossible to know absolutely as the explosion and fire totally destroyed it; but the condition of the pipe coating near the failure may give some indication. The amount of corrosion damage to the pipe joint(s) that failed will give some idea of coating condition too.
Highway salts used to melt ice can cause chloride concentration to increase in the soil near the highway resulting in accelerated corrosion of buried steel. Since the failure was near a major highway, this may have been a contributing factor.
The casing under the highway if shorted to the carrier pipe may have caused a depression of cathodic protection levels on the pipe that failed. The electrical isolation of the casing to the carrier pipe is presently unknown. Casing use started due to the oxygen concentration corrosion cell effect of the pipe under the highway being more anodic than pipe by the highway. Corrosion failures under highways and railroad crossing caused the requirement of cased pipeline crossings of roads and railroads. Modern construction practice is to use a high performance coating system for the pipe under the highway or railroad and eliminate the use of casings. In addition, pipeline crossings under railroads and highways are done deeper by directional boring which isolates the pipeline from stresses caused by railroad traffic sufficiently to eliminate the need for a casing for load shielding of the carrier pipe.
Desire to declare that I have not worked for Columbia Gas Transmission, but I did interview for the position of Corrosion Engineer in their Charleston, WV office. Discussed corrosion issues with Columbia Gas Transmission staff during the Purdue Corrosion Short Course and NACE International technical committee meetings. Consider their corrosion issues to be not unique to those I had to deal with during my career with other natural gas transmission companies.
Per the NTSB investigation so far, the failure was due to external corrosion on the bottom of the pipe that resulted in significant wall thinning. The wall thinning was described as being approximately 6 feet long with as much as 70% wall thickness reduction is some locations. Wall thinning of this length and depth is sufficient to result in a rupture of the pipeline. There has been nothing stated to date that internal corrosion on the bottom of the pipe may have contributed to the wall thinning that resulted in a rupture of the pipe.
External corrosion does favor the bottom of the pipe due to a oxygen concentration cell effect that makes the pipe bottom anodic to the rest of the pipe surface. The bottom of the pipe has less oxygen in the soil next to the pipe surface. This corrosion cell can result in deep corrosion pitting which on large diameter pipelines may not be detected by over-the-line-survey CIS (Close Interval Survey) as such surveys record an average pipe-to-soil potential of the pipe surface and not the lowest pipe-to-soil potential on the pipe surface. In addition, over the line surveys tend to not detect corrosion cells on the bottom of the pipe as effectively as corrosion cells are top of the pipe. Corrosion cell activity under disbonded coatings can decrease the effectiveness of over-the-line surveys in detecting possible corrosion activity. MIC (microbiologically influenced corrosion) may accelerate the oxygen concentration cell corrosion cell activity by deplorizing the pipe surface, increasing the amount of cathodic protection current required to create a polarized pipe surface at coating holidays, and requiring an increase in the cathodic protection criterion to a value greater than -850 mV. From photos of the failure site, MIC probably was not a contributing factor in the pipeline failure but cannot be totally ruled out.
ACVG (Alternating Current Voltage Gradient) and DCVG (Direct Current Voltage Gradient) pipe coating surveys may sometimes detect coating damage on the bottom of a large diameter pipeline that a typical CIS inspection may miss due to the average pipe-to-soil potential effect. All methods of finding coating damage that may result in corrosion damage to the pipeline have limited effectiveness if the pipe coating has significant disbondment to the pipe surface with trapped water and few coating holidays. All pipeline coating surveys tend to detect coating holidays more effectively than disbonded coating. The best way of detecting disbonded pipe coating is a ILI EMAT tool.
The photos of the failure site suggests that the backfill around the pipe that failed may have had sufficient rock and stone to damage coal tar and asphalt pipe coatings used at the time the pipeline was built. The amount of clean backfill placed around the pipe during construction would influence how much coating damage may have occurred during backfilling. Cold Applied Tapes were not in much use when the pipeline was built and probably was not the coating system applied to the pipe. Asphalt pipe coatings were popular during the period the pipeline was built and tend to have coating disbondment issues which may result in shielded corrosion cell activity. At this time the pipe coating system on the pipeline that failed has not been stated. The condition of the pipe coating where the failure occurred will be impossible to know absolutely as the explosion and fire totally destroyed it; but the condition of the pipe coating near the failure may give some indication. The amount of corrosion damage to the pipe joint(s) that failed will give some idea of coating condition too.
Highway salts used to melt ice can cause chloride concentration to increase in the soil near the highway resulting in accelerated corrosion of buried steel. Since the failure was near a major highway, this may have been a contributing factor.
The casing under the highway if shorted to the carrier pipe may have caused a depression of cathodic protection levels on the pipe that failed. The electrical isolation of the casing to the carrier pipe is presently unknown. Casing use started due to the oxygen concentration corrosion cell effect of the pipe under the highway being more anodic than pipe by the highway. Corrosion failures under highways and railroad crossing caused the requirement of cased pipeline crossings of roads and railroads. Modern construction practice is to use a high performance coating system for the pipe under the highway or railroad and eliminate the use of casings. In addition, pipeline crossings under railroads and highways are done deeper by directional boring which isolates the pipeline from stresses caused by railroad traffic sufficiently to eliminate the need for a casing for load shielding of the carrier pipe.
Desire to declare that I have not worked for Columbia Gas Transmission, but I did interview for the position of Corrosion Engineer in their Charleston, WV office. Discussed corrosion issues with Columbia Gas Transmission staff during the Purdue Corrosion Short Course and NACE International technical committee meetings. Consider their corrosion issues to be not unique to those I had to deal with during my career with other natural gas transmission companies.
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