A recent PHMSA Advisory Bulletin warns the pipeline industry about Corrosion Under Insulation (CUI), which is frequently used on pipe transporting heavy crude oil. Such products are often heated for more efficient transport, thus the pipe is wrapped with foam insulation over the coating, and then further covered with a tape wrap over the insulation. The crude oil release from a Plains All American pipeline near Santa Barbara in May of 2015 used such thermal insulation, and the government’s investigation following that release prompted this Advisory from PHMSA.
In the Plains incident, PHMSA determined that water infiltrated the foam insulation, which allowed corrosion to develop. The cathodic protection (CP) system became ineffective, although CP readings continued to show sufficient current. Unfortunately, inline inspection (ILI) runs also did not reveal the extent of the corrosion. The most recent ILI of the line, run just before the incident, predicted a 47% wall loss at the point of rupture, which would not by itself trigger immediate repair under PHMSA rules. After the rupture, the actual extent of corrosion was confirmed to be 89%, which would have triggered corrective action. Plains had noted water infiltration after prior tool runs, and had noted an increasing number of corrosion anomalies, but the available data did not accurately predict the severity of corrosion. PHMSA’s Failure Investigation Report on the Plains incident is publicly available.
The risk of corrosion occurring due to water infiltration to pipe coating is certainly not unknown. Pipeline safety law requires that buried steel pipe be coated, with an electric current applied, both actions intended to prevent external corrosion. Different types of coating have been used over the decades, and the risk of corrosion may vary over time, by type of coating. Coating may also become ‘disbonded,’ meaning that airspace develops between the coating material and the pipe. That may also allow corrosion to develop. Electric CP is applied to pipe, in addition to coating, to further prevent the occurrence of corrosion. Disbonded coating or other forms of shielding between the pipe and the electric current can allow corrosion to develop. Current pipeline safety law also requires pipeline integrity assessments for lines located in environmentally sensitive or highly populated areas (called HCAs). Assessment methods include ILI of steel pipelines with technology that can detect corrosion wall loss, dents, cracks and other anomalies. Pipeline operators must inspect the sufficiency of CP on a monthly basis (for all pipeline, not just those in HCAs), and conduct ILI at least once every five years, to monitor and maintain pipeline integrity.
CUI is not a new phenomenon. The National Association of Corrosion Engineers (NACE) issued a report in 2006 that described the risk of corrosion under insulation, noting that while thermal insulation over coating is typically effective, corrosion under insulation can occur and presents a threat to pipeline integrity. Pipeline operators are required by law to take action to address known threats to pipeline integrity (usually more frequent ILIs and confirmation digs at identified locations to evaluate the existence or extent of that threat). The fact that the Plains ILI runs did not detect the CUI in this instance is the subject of continuing evaluation. It may have been due to inadequate ILI equipment or interpretation, unclear communication between the ILI vendor and the operator, or a failure of ILI technology generally to make accurate detection of wall loss associated with CUI.
The PHMSA Advisory Bulletin advises operators of all liquid pipelines to be aware of the risk of CUI and the associated risk of inadequate detection of wall loss by either CP or ILI. The Advisory is expressly linked to the Plains incident, but directed to the entire industry. The Advisory suggests that an operator of pipe with insulated coating consider one of several integrity management activities: (1) replace all pipe using thermal coating; (2) repair or recoat those sections of such pipe identified as having inadequate CP; (3) conduct more frequent ILI; (4) use more sophisticated ILI tools, capable of detecting stress corrosion cracking; (5) adopt more stringent repair criteria than required by law in an attempt to capture undetected corrosion before it becomes a serious risk; or (6) adopt a more advanced method of leak detection.
Advisory Bulletins issued by PHMSA do not have the force of law and cannot by themselves form the basis for enforcement. They often find their way into enforcement actions, however, in the guise of compliance or corrective action orders appended to allegations of violation of other regulations.