How corrosion control requirements will change under the PHMSA final rule
In August 2022, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a Final Rule regarding the safety of gas transmission pipelines. These new requirements amend 49 CFR 192 and will take effect on May 24, 2023. This final rule updates regulations surrounding integrity management, extreme weather events, management of change and corrosion control.
Here’s a summary of what you need to know about the impact of this final rule on protective coatings, cathodic protection (CP) surveys, and internal corrosion monitoring and mitigation.
Coating requirements will be updated, with PHMSA intending to see that any damage incurred during installation does not go unaddressed. Coating assessments/surveys are now required to be completed within six months of a transmission line going in service (with exceptions for geographical, technical or safety reasons). PHMSA recommends direct current voltage gradient (DCVG) or alternating current voltage gradient (ACVG) surveys, but makes allowances for “other technology,” which must be reported to PHMSA a minimum of 90 days before use.
If any “severe” damage is detected — defined as a voltage drop greater than 60% for DCVG or 70 dBμV for ACVG — it must be repaired within six months of the assessment, or as soon as practicable after obtaining permits, not to exceed six months. Operators are required to make and retain public records of these coating assessments and repairs for the life of the pipe.
The amendments also include language regarding the protective coating having sufficient strength to resist damage from handling, transportation, installation, boring and backfilling. This may imply that protective wraps or abrasion resistant overcoats (AROs) are recommended for trenchless crossings or where particularly abrasive backfill will be used.
Cathodic Protection Monitoring
Another focus of the final rule is regarding CP monitoring and mitigating the impact that interference can have on a cathodically protected pipeline. During annual test station readings, if inadequate CP levels are discovered in specific locations — i.e., not a systemic issue across an entire pipeline or region — a close-interval survey (CIS) needs to be conducted in both directions from the test station, with a maximum interval of 5 feet, to determine the cause and extent of the issue.
When new current sources — such as high-voltage power lines, electrical substations, or other cathodically protected pipelines — are introduced near a transmission line, or when stray current is suspected as a cause for inadequate or unusual CP levels, interference surveys will be required. If interference is discovered in excess of the industry-accepted current density limits (i.e., 100 A/m2 for AC induced corrosion), or if the interference is determined to cause safety or environmental concerns, mitigation is required.
In all these cases, operators must apply for the necessary permits within six months of identifying CP deficiencies or interference issues, and the deficiency must be corrected as soon as possible. The maximum time limits for action are within 15 months of identifying the deficiency and within six months of obtaining permits.
Internal Corrosion Control
Operators will be required to implement a monitoring and mitigation program if any corrosive constituents — such as carbon dioxide, hydrogen sulfide, other forms of sulfur, microbes or water — are in the gas stream. The partial pressures of these constituents must be measured, and their effect on internal corrosion must be determined. PHMSA offers several recommendations that may be useful in a monitoring and mitigation program:
- Injecting inhibitors
- Frequent pigging to clean the pipe
- The use of separators
Annual evaluations and program reviews, not to exceed 15 months, will be required so that adjustments can be implemented as needed.
Overall, the Final Rule will implement more significant assessment and survey requirements for corrosion control, as well as specific timelines for addressing any issues discovered. Pipeline operators will need to be diligent in maintaining traceable, verifiable and complete records. Working with partners experienced in designing CP systems, selecting pipeline coatings, performing stray current assessments and conducting AC interference studies could help operators meet their new obligations.
DC interference and stray current corrosion could be damaging your metal assets. The risks are important to identify and understand for addressing underground corrosion problems.