[Federal Register Volume 68, Number 195 (Wednesday, October 8, 2003)]
[Notices]
[Pages 58166-58168]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 03-25421]


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DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration


Pipeline Safety: Stress Corrosion Cracking (SCC) Threat to Gas 
and Hazardous Liquid Pipelines

AGENCY: Research and Special Programs Administration (RSPA), DOT.

ACTION: Notice; issuance of advisory bulletin.

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SUMMARY: RSPA's Office of Pipeline Safety (OPS) is issuing this 
advisory notice to owners and operators of gas and hazardous liquid 
pipelines to consider the threat from stress corrosion cracking (SCC) 
when developing and implementing Integrity Management Plans. Operators 
should determine whether their pipelines are susceptible to SCC and 
assess the impact of SCC on pipeline integrity. Based on this 
evaluation, an operator should prioritize application of additional in-
line inspection and hydrostatic testing and take actions to remediate 
problem areas.

FOR FURTHER INFORMATION CONTACT: Mike Israni, (202) 366-4571; or by e-
mail, [email protected]. This document can be viewed at the OPS 
home page at http://ops.dot.gov. General information about the RSPA/OPS 
programs may be obtained by accessing RSPA's home page at http://rspa.dot.gov.

I. Advisory Bulletin (ADB-03-05)

    To: Owners and Operators of Gas and Hazardous Liquid Pipeline 
Systems.
    Subject: Stress Corrosion Cracking (SCC) Threat to Gas and 
Hazardous Liquid Pipelines.
    Purpose: To advise owners and operators of natural gas and 
hazardous liquid pipeline systems to consider stress corrosion cracking 
as a possible safety risk on their pipeline systems and to include SCC 
assessment and remediation measures in their Integrity Management 
Plans.
    Advisory: Each owner and operator of a gas or hazardous liquid 
pipeline system should assess the risk of stress corrosion cracking 
(SCC). Pipeline owners and operators should evaluate their systems for 
the presence of risk factors for high pH (9-11) SCC or near-neutral pH 
(6-8) SCC. Criteria for high pH SCC can be found in Appendix A3.3 of 
standard ASME B31.8S. If conditions for SCC are present, a written 
inspection, examination, and evaluation plan should be prepared and 
appropriate action should be taken in accordance with Appendix A3.4 of 
standard ASME B31.8S. RSPA/OPS will soon publish a final rule on the 
integrity management program for gas transmission pipelines in high 
consequence areas that incorporates requirements for addressing SCC 
threats by referencing Appendix A3 of standard ASME B31.8S. Although 
criteria and mitigation plans for near-neutral pH (6-8) SCC are not 
addressed in this standard, NACE International (NACE) is currently 
developing a standard on Direct Assessment of Stress Corrosion 
Cracking. Also, NACE will soon issue a technical committee report, 
External Stress Corrosion Cracking of Underground Pipelines, to provide 
information on SCC for hazardous liquid pipelines.

[[Page 58167]]

    The integrity management rules for both large (65 FR 75378; 
December 1, 2000) and small (66 FR 2136; January 16, 2002) hazardous 
liquid pipelines in high consequence areas did not specifically address 
the SCC threat. By this Advisory Bulletin, we are reminding owners and 
operators of both gas and hazardous liquid pipeline systems to consider 
the stress corrosion cracking threat as a possible risk factor when 
developing and implementing Integrity Management Plans. All owners and 
operators of pipeline systems, whether or not their pipeline systems 
are subject to the Integrity Management Plan rules, should determine 
whether their pipeline system is susceptible to SCC and assess the 
impact of SCC on pipeline integrity. Based on this evaluation an 
operator should prioritize application of internal inspection, 
hydrostatic testing, or other forms of integrity verification.

SUPPLEMENTARY INFORMATION:

II. Background

    Recent incidents throughout North America and the world, including 
Australia, Russia, Saudi Arabia, and South America, have highlighted 
the threats to pipelines from SCC failures. In the United States, SCC 
failures on hazardous liquid pipelines have been very rare when 
compared with SCC occurrences on natural gas pipelines. However, three 
SCC-caused failures of hazardous liquid pipelines have occurred in 
2003. Another hazardous liquid pipeline operator has reported finding 
significant SCC defects.
    SCC is the cracking induced from the combined influence of tensile 
stress and a corrosive medium. The impact of SCC on a material usually 
falls between dry cracking and the fatigue threshold of that material. 
The required tensile stresses may result from directly applied stresses 
(pressure and overburden) or in the form of residual stresses 
(fabrication and construction). The most effective means of preventing 
SCC are to: (1) properly design the pipeline using appropriate 
materials; (2) reduce pipeline stresses; and (3) remove critical 
environmental electrolytes, such as hydroxides, chlorides, and oxygen.
    Most pipelines are buried. No matter how well these pipelines are 
designed, constructed, and protected, once in place they are subjected 
to environmental abuse, external damage, coating disbondment, inherent 
mill defects, soil movements/instability, and third party damage. SCC 
develops in pipelines due to a combination of environmental, stress 
(absolute hoop and/or tensile, fluctuating stress) and material (steel 
type, amount of inclusions, surface roughness) factors. Although the 
age of a pipeline is not indicative of the presence of SCC, it is a 
factor to consider when assessing pipelines that are subject to 
conditions that may cause crack growth.
    Two types of SCC are found on pipelines: high pH (9 to 11) SCC and 
near-neutral pH (6 to 8) SCC. Characteristics of both forms of SCC as 
summarized by experts are as follows:
    --Cracks usually oriented in longitudinal direction (cracks may 
exist at other orientations, depending on the direction of tensile 
stress).
    --Occurrence in clusters consisting of several cracks to hundreds 
of cracks.
    --Cracks tend to interlink to form long shallow flaws (cracks may 
grow to cause ruptures).
    --Fractures faces are covered with magnetite and carbonate films.
    High pH SCC was originally noted in gas transmission pipelines. It 
is typically found within 20 miles downstream of the compressor 
station. High pH SCC usually occurs in a relatively narrow cathodic 
potential range (-600 to -750 mV Cu/CuSO4) in the presence 
of a carbonate/bicarbonate environment in a pH window from 9 to 11. 
Temperatures greater than 100[deg] F are necessary for high pH SCC 
susceptibility. Other characteristics of high pH SCC according to 
experts are as follows:
    --Cracks are narrow and inter-granular and, have extensive crack 
branching.
    --Cracks are generally not associated with long seams or other 
metallurgical features.
    --Cracks are commonly found on the bottom half of a pipe.
    --Cracks are commonly associated with coal tar and asphalt 
coatings.
    For other details on high pH SCC please refer to Appendix A3 of 
standard ASME B31.8S.
    A Near-neutral pH SCC was initially noted in Canada and has been 
observed by operators in the United States. The environment primarily 
responsible for near-neutral pH SCC is groundwater containing dissolved 
CO2. The CO2 originates from the decay of organic 
matter. Cracking is exacerbated by the presence of sulfate reducing 
bacteria. This primarily occurs due to disbonded coatings, which 
normally prevent the cathodic current from reaching the pipe surface. 
There is a corrosion condition below the disbonded coating that results 
in an environment with a pH of between 6 and 8. Other characteristics 
of near-neutral pH SCC according to experts are as follows:
    --Cracks are wide (compared with high pH SCC) and trans-granular 
and have limited crack branching.
    --Cracks are frequently associated with long seams and other 
metallurgical features (dents, mechanical damage).
    --Cracks are commonly associated with tape coatings.
    Pipeline operators know the pipeline metallurgy, coating type, and 
operating pressure of each pipeline. The only remaining variable in 
determining the likelihood of SCC is soil type. RSPA/OPS has previously 
directed certain pipeline operators to evaluate and establish the 
extent of SCC susceptibility, utilize over the ditch coating surveys to 
identify locations of holidays (uncoated spots) and match them with 
high stress levels (60% or greater of specified minimum yield 
strength), and match the areas with high temperature locations. The 
areas where all factors are present are then excavated and evaluated.
    If a pipeline is susceptible to SCC, pipeline operators are 
required to quantify the life cycle of the pipeline by conducting 
fracture mechanic calculations to estimate where in the system an SCC 
rupture might occur. Appropriate in-line inspection technologies can 
help to identify SCC in a pipeline. If the pipeline cannot accommodate 
internal inspection tools, an appropriately designed hydrostatic test 
program can be effective in exposing SCC. If excavations of suspected 
SCC locations do not reveal SCC, RSPA/OPS recommends continuous 
monitoring for SCC as part of an operator's integrity management 
program for corrosion.
    Because of the randomness of SCC failures, RSPA/OPS has, in the 
past, often ordered operators to reduce operating pressure by 20% of 
the prefailure pressure to add a factor of safety and allow the 
operator to continue service. This protects the public and environment 
from other SCC failures, even if there is another crack on the pipeline 
of the same size. Based on technical studies, RSPA/OPS has often 
required the pipeline operator to perform a spike hydrostatic pressure 
test to expose other cracks and ensure a safe return to full operating 
pressure. The pipeline operator can then commence a rigorous SCC 
management program that may include in-line inspection, recoating the 
pipeline, or even replacing sections of pipe where SCC is present.
    By the end of 2003, RSPA/OPS will invite scholars and consultants 
to a public meeting to discuss research and technologies that can 
effectively identify, assess, and manage SCC.


[[Page 58168]]


    Issued in Washington, DC, on October 1, 2003.
Stacey L. Gerard,
Associate Administrator for Pipeline Safety.
[FR Doc. 03-25421 Filed 10-7-03; 8:45 am]
BILLING CODE 4910-60-P