
[Federal Register Volume 81, Number 119 (Tuesday, June 21, 2016)]
[Notices]
[Pages 40398-40400]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-14651]


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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

[Docket No. PHMSA-2016-0071]


Pipeline Safety: Ineffective Protection, Detection, and 
Mitigation of Corrosion Resulting From Insulated Coatings on Buried 
Pipelines

AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA); 
DOT.

ACTION: Notice; Issuance of Advisory Bulletin.

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SUMMARY: PHMSA is issuing this advisory bulletin to remind all owners 
and operators of hazardous liquid, carbon dioxide, and gas pipelines, 
as defined in 49 Code of Federal Regulations (CFR) Parts 192 and 195, 
to

[[Page 40399]]

consider the overall integrity of the facilities to ensure the safety 
of the public and operating personnel and to protect the environment. 
Operators are reminded to review their pipeline operations to ensure 
that pipeline segments that are both buried and insulated have 
effective coating and corrosion-control systems to protect against 
cathodic protection shielding, conduct in-line inspections for all 
threats, and ensure in-line inspection tool findings are accurate, 
verified, and conducted for all pipeline threats.

FOR FURTHER INFORMATION CONTACT: Operators of pipelines subject to 
regulation by PHMSA should contact Mr. Kenneth Lee at 202-366-2694 or 
email to: kenneth.lee@dot.gov.

SUPPLEMENTARY INFORMATION: 

I. Background

    On May 19, 2015, the Plains Pipeline, L.P. (Plains), Line 901, a 
24-inch pipeline in Santa Barbara County, California, ruptured, 
resulting in the release of approximately 2,934 barrels of heavy crude 
oil. The spill resulted in substantial damage to natural habitats and 
wildlife. This buried pipeline failed due to extensive external 
corrosion that occurred under the insulated coating.
    The Line 901 pipeline is coated with coal tar urethane and covered 
with foam insulation which, in turn, is covered by a tape wrap over the 
insulation. Shrink wrap sleeves, which provide a barrier between the 
steel pipeline and soil for corrosion prevention, are present at the 
pipeline joints (girth welds) on Line 901. Line 901 carried high-
viscosity crude oil at a temperature of approximately 135 degrees 
Fahrenheit to facilitate transport. Line 901's pipe specifications are 
API 5L, Grade X-65 pipe, 0.344-inch wall thickness, with a high 
frequency-electric resistance welded (HF-ERW) long seam. Line 901 was 
hydrotested to 1,686 pounds per square inch gauge (psig) on November 
25, 1990, and has a maximum operating pressure (MOP) of 1,341 psig. 
Line 901 delivered crude oil into 30-inch Line 903. Line 901 is 10.7 
miles in length and Line 903 is 128 miles in length. Line 903 has 
similar insulated coating and shrink wrap sleeves at girth welds.
    Under 49 CFR 195.563, cathodic protection (CP) is required to 
prevent external corrosion of buried pipelines. Historical CP records 
for Line 901 revealed protection levels that typically are sufficient 
to protect non-insulated, buried, coated steel pipe. As mentioned 
previously, however, Line 901 and Line 903 are insulated. An increasing 
frequency and extent of corrosion anomalies were noted on both Lines 
901 and 903 on in-line inspection tool (ILI) survey results, anomaly 
excavations, and repairs. PHMSA inspectors noted moisture entrained in 
the insulation at four excavations performed by Plains on Line 901 
after the May 19, 2015 spill.
    Plains conducted ILI surveys on Line 901 to assess the integrity of 
the pipeline in accordance with pipeline safety regulations in 2007, 
2012, and 2015. Under Sec.  195.452(j)(3), all pipelines are required 
to be surveyed at intervals commensurate with the pipeline's risk of 
integrity threats, but at least every five years. Plains changed Line 
901 from a five-year assessment cycle to a three-year assessment cycle 
after the 2012 ILI survey. Preliminary data from the results of the ILI 
surveys are summarized below and show a growing number of corrosion 
anomalies on Line 901. Discrepancies between the ILI data generated 
during the 2007 and 2012 surveys of Line 901 and the ``as found'' 
anomaly sizes discovered in correlation digs after those prior surveys 
had not been shared with the ILI vendor to reanalyze the data. The 
frequency and magnitude of the anomalies below are derived from the 
reported ILI vendor analysis.

                                    24-Inch Line 901--ILI Assessment Results
----------------------------------------------------------------------------------------------------------------
                           Metal loss                              June 19, 2007   July 3, 2012    May 6, 2015 *
----------------------------------------------------------------------------------------------------------------
Greater than 80%................................................               0               0               2
60 to 79%.......................................................               2               5              12
40 to 59%.......................................................              12              54              80
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* Results not received until after spill.

    The most recent ILI survey for Line 901 was completed on May 6, 
2015. At the time of the spill, the preliminary vendor report had not 
been received. As a result, no correlation digs for this ILI survey had 
been attempted.
    The May 6, 2015, ILI survey data and subsequent analysis by the ILI 
vendor predicted external corrosion at the failure site with an area of 
5.38 inches by 5.45 inches, and a maximum depth of 47% of the original 
pipe wall thickness. After the failure, the metallurgical investigators 
physically measured external corrosion at the failure site to have a 
maximum depth of 89%. The dimensions of the corrosion feature were 12.1 
inches axially by 7.4 inches in circumference. The maximum depth, as 
measured using laser scan data, was 0.318 inches or 89% of the measured 
pipe wall thickness (0.359 inches). Discrepancies between the historic 
ILI data and the ``as found'' anomaly size had not been shared with the 
ILI vendor to reanalyze the data.
    PHMSA determined that the proximate or direct cause of the release 
was progressive external corrosion of the insulated, buried steel 
pipeline. The corrosion occurred under the pipeline's coating system, 
which consisted of a urethane coal tar coating applied directly to the 
bare steel pipe, covered by foam thermal insulation with an overlying 
tape wrap. Water was noted in the foam insulation at a number of digs, 
indicating that the integrity of the coating system had been 
compromised. The external corrosion was facilitated by the 
environment's wet/dry cycling, as determined by the PHMSA-approved, 
third-party metallurgical laboratory. The release was a single event 
caused at an area where external corrosion had thinned the pipeline 
wall thickness. There is no evidence that the pipeline leaked before 
the rupture. There was a telltale ``fish mouth'' (a split due to over-
pressurization) at the release site indicating the line failed in a 
single event.
    PHMSA's Failure Investigation Report indicated that the proximate 
or direct cause of the Line 901 failure was external corrosion that 
thinned the pipe wall to a level where it ruptured suddenly and 
released heavy crude oil. PHMSA's Failure Investigation Report of the 
Plains Line 901 incident can be reviewed at:.http://phmsa.dot.gov/staticfiles//PHMSA/DownloadableFiles/Files/PHMSA_Failure_Investigation_Report_Plains_Pipeline_LP_Line_901_Public.pdf. PHMSA's investigation identified numerous contributory causes of the 
rupture, including:
    (1) Ineffective protection against external corrosion of the 
pipeline:
     The condition of the pipeline's coating and insulation 
system fostered

[[Page 40400]]

an environment that led to external corrosion; and
     The pipeline's CP system was not effective in preventing 
corrosion from occurring beneath the pipeline's coating/insulation 
system.
    (2) Failure to detect and mitigate the corrosion:
     The ILI and subsequent analysis of ILI data did not 
characterize the extent and depth of the external corrosion accurately.
    Corrosion under insulation (CUI) is recognized as an integrity 
threat difficult to address through conventional cathodic protection 
systems and can lead to accelerated wall-loss corrosion and stress 
corrosion cracking of the pipe steel. A NACE International (NACE) 
technical committee report titled ``Effectiveness of Cathodic 
Protection on Thermally Insulated Underground Metallic Structures'' 
dated September 2006 (NACE International Publication 10A392, 2006 
Edition), was prepared as a guide for external corrosion control of 
thermally-insulated underground metallic surfaces and considerations of 
the effectiveness of CP. A summary of the NACE report's conclusions are 
as follows:
    (1) ``Generally, the application of external CP to thermally 
insulated metallic surfaces has been ineffective.
    (2) The principal or primary means of corrosion control of 
thermally-insulated metallic surfaces is the application of an 
effective coating on the metallic surface.
    (3) Care is typically taken in the application of the external 
jacket and during pipe installation to minimize water ingress, which 
causes corrosion at imperfections in the primary coating.
    (4) When practical, the thermally insulated metallic surfaces need 
to be inspected at routine time intervals for metal loss (e.g., an 
internal pipeline inspection tool could be used).''

II. Advisory Bulletin (ADB-2016-04)

    To: Owners and Operators of Hazardous Liquid, Carbon Dioxide and 
Gas Pipelines.
    Subject: Ineffective Protection, Detection, and Mitigation of 
Corrosion Resulting from Insulated Coatings on Buried Pipelines.
    Advisory: Operators of hazardous liquid, carbon dioxide and gas 
pipelines, as defined in 49 CFR parts 192 and 195, should review their 
operating, maintenance, and integrity management activities to ensure 
that their insulated and buried pipelines have effective cathodic 
protection systems, including coating systems to protect against 
cathodic protection shielding and moisture under the coatings with 
higher operating temperatures, and in-line inspection tool findings are 
accurate, verified, and the in-line tools are appropriate for the 
pipeline threat. This bulletin is intended to inform operators about 
PHMSA' failure investigation of the Plains Pipeline May 19, 2015, 
accident in Santa Barbara, California and to urge operators to take all 
necessary actions, including, but not limited to, those set forth in 
this bulletin, to prevent and mitigate the breach of integrity, leaks, 
and/or failures of their pipeline facilities and to ensure the safety 
of the public and operating personnel and to protect the environment.
    Operators must have and implement procedures to operate, maintain, 
assess, and repair their pipelines. These procedures for insulated and 
buried pipelines should take into consideration:
    (1) The need for coatings and cathodic protection systems to be 
designed, installed, and maintained so as not to foster an environment 
of shielding and moisture that can lead to excessive external corrosion 
growth rates and pipe steel cracking such as stress corrosion cracking.
    (2) Coatings for buried, insulated pipelines that may result in 
cathodic protection ``shielding'' yet still comply with 49 CFR part 
192, subpart I or 49 CFR part 195, subpart H. Inadequate corrosion 
prevention may be addressed through any one or more methods, or a 
combination of methods, including, but not limited to, the following:
     Replacing insulated and buried pipelines with compromised 
coating systems or inadequate cathodic protections systems;
     Repairing or re-coating compromised portions of the 
coating on insulated and buried pipelines to ensure adequate corrosion 
control; or
     Taking other special precautions if an operator suspects 
that adequate cathodic protection cannot be provided due to shielding 
resulting from insulated coatings that have become disbonded. Such 
precautions may include:
    [cir] More frequent reassessments;
    [cir] Usage of the appropriate assessment tools for all threats 
including stress corrosion cracking;
    [cir] Coordination of data from the appropriate ILI technologies;
    [cir] More stringent repair criteria targeted at CUI or corrosion 
under disbonded coatings for insulated and buried pipelines;
    [cir] Usage of a leak detection system with instrumentation and 
associated calculations to monitor line pack (the total volume of 
liquid present in a pipeline section) along all portions of the 
pipeline when it is operating or shut down; and
    [cir] Valve spacing to limit any possible spill volumes with 
remotely operated valves and pressure monitoring at the valves.
    (3) Advanced ILI data analysis techniques to account for the 
potential growth of CUI, including interaction criteria for anomaly 
assessment.
    (4) ILI data, subsequent analysis of the data, and pipeline 
excavations that:
     Confirm the accuracy of the ILI data to characterize the 
extent and depth of the external corrosion and ILI tolerances and unity 
charts;
     Follow the ILI guidelines of API Standard 1163, ``In-Line 
Inspection Systems Qualification Standard'' 2nd edition, April 2013, 
(API Std. 1163) for ILI assessments;
     Use additional or more frequent reassessment intervals and 
confirmations when the insulated and buried pipeline external coating, 
shields the pipeline from CP, retains moisture on insulated coating 
systems, and operates at higher operating temperatures; and
     Assess and mitigate operational and environmental 
conditions in shielded and insulated coatings that lead to excessive 
corrosion growth rates, pipe steel cracking, and all other threats.
    In addition to the above, an operator's operating and maintenance 
processes and procedures should be reviewed and updated at least 
annually, unless operational inspections for integrity warrant shorter 
review periods.

    Issued in Washington, DC, on June 15, 2016, under authority 
delegated in 49 CFR 1.97.
Alan K. Mayberry,
Acting Associate Administrator for Pipeline Safety.
[FR Doc. 2016-14651 Filed 6-20-16; 8:45 am]
 BILLING CODE 4910-60-W


