Stress-corrosion cracking (SCC) of buried pipelines is one of several identified integrity threats for pipeline systems. The Pipeline and Hazardous Materials Safety Administration, formerly Research and Special Programs Administration (RSPA), Office of Pipeline Safety (OPS) recently commissioned a review of the pipeline industry's experience with SCC to establish a baseline of the collective knowledge and best practices to successfully mange the SCC threat.
This article summarizes significant findings from the review.1
Early experience
The first known case of SCC was identified in 1965 following a gas transmission pipeline rupture near Natchitoches, La. Before that incident, SCC on buried pipelines was previously unknown; multiple agencies and organizations performed extensive examinations before the Natchitoches failure attributed to SCC.
Another gas transmission pipeline failure was attributed to SCC in 1966. Initially, incidents identified as SCC were limited to gas transmission pipelines installed in heavy clay soils along the US Gulf Coast. Subsequent industry experience has revealed that SCC can occur in a variety of soils and climates on any continent with a significant pipeline network.
Until recently, more pipeline failures involving SCC were reported for natural gas pipelines than for hazardous liquid pipelines. In 2003, three failures involving hazardous liquid pipelines were attributed to SCC. In addition, subsequent assessments of other hazardous liquid pipelines have revealed indications of SCC not previously identified.
Recent revisions of Title 49 Code of Federal Regulations (CFR) Parts 192 and 195 incorporate Integrity Management Rules that address threats to pipeline integrity.23 OPS issued an advisory bulletin to owners and operators of gas and hazardous liquid pipelines, stressing that the threat of SCC should be considered when developing and implementing Integrity Management Plans.4
Incident statistics indicate SCC contributes to fewer uncontrolled releases of gas and hazardous liquids than other known threats to pipeline integrity, such as third-party damage and external corrosion. Regulators are seeking methods to determine and monitor the relative frequency of SCC and develop new technologies that will assist in the identification and reduction of SCC-related threats to pipeline safety.
In December 2003, RSPA-OPS and the National Association of Pipeline Safety Representatives (NAPSR) cosponsored an SCC workshop in Houston. The workshop brought together multiple pipeline industry trade associations (e.g., American Petroleum Institute, Association of Oil Pipelines, Interstate Natural Gas Association of America, American Gas Association, and NACE International)5 to discuss increased regulatory concern regarding the SCC threat to pipeline safety and to provide industry a forum for the discussion of SCC phenomena in both gas and hazardous liquid pipelines.
One of the topics discussed at the SCC workshop was the OPS contract with Michael Baker Jr. Inc., Moon Township, Pa., to prepare a comprehensive report regarding the state of the pipeline industry's collective knowledge about SCC in buried pipelines.
To prepare the report, Baker subcontracted portions of the review to multiple consulting and testing organizations with extensive SCC experience. In addition, Baker interviewed pipeline operators and other groups with known experience in SCC to ensure an industry-wide perspective. OPS also posted the draft report on its web site for 30 days of public review and solicited comments, which were considered in the final report.
SCC basics
SCC in a buried pipeline is the result of interaction between a corrosive environment and stress on the surface of line pipe to form a crack or cracks at the surface that may eventually propagate through the pipe wall. Fig. 1 shows an example of a rupture attributed to SCC.
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The environment causing SCC typically includes a relatively small volume of fluid trapped between a disbonded coating and the pipe surface. Groundwater composition influences the environment causing SCC, but the chemical composition of the trapped fluid may be altered by the interaction of cathodic protection with the fluid and the pipe surface.
Earlier examples of SCC, which is commonly called "classic" or high-pH SCC, were associated with water containing carbonates and bicarbonates at a pH of approximately 9-11. Another type of SCC, which is commonly called low pH or, more appropriately, near-neutral pH SCC, has been associated with water containing dissolved carbon dioxide (CO2) at a pH of about 6-8.
Table 1 summarizes characteristics of the two types of SCC in buried pipelines.6 7
Environmentally assisted cracking, such as SCC in buried pipelines, requires the presence of at least a minimum level of stress to promote cracking. This minimum stress level is labeled as the "threshold stress."
The total stress that can contribute to SCC in pipelines includes the stress applied by pressure, residual stresses from line pipe manufacture and installation, and stresses imposed by external forces such as soil movement. Increments of stress above the threshold stress may reduce the time to initiate first cracks and increase the rate of crack growth.
SCC is most often found in clusters of parallel cracks called colonies or families (Fig. 2). A cluster of SCC may contain a relative few to hundreds of cracks. Cracks are most often longitudinal, but circumferential cracks have occurred as a result of longitudinal or bending stresses.
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Individual cracks are typically semielliptical. Initiation and growth of SCC causes concentration of stresses near the crack tips. Stresses concentrated near the crack tips can cause cracks to extend or grow both through the wall and along the surface.
Growth of individual cracks in a cluster can lead to interaction of stresses at crack tips that are generally aligned and relatively close. Cracks that interact may link to form longer cracks.
Conditions that favor initiation of multiple aligned cracks that eventually link tend to cause ruptures. Conditions that favor growth of individual cracks through the wall, rather than linking of cracks, tend to cause leaks.
SCC occurrences
Earlier incidents of classic SCC in gas transmission pipelines were generally located downstream from compressor stations and were associated with coating damage caused by the combination of excessive temperature and soil stresses. Disbonded coating tends to sag and stretch due to stresses induced by soil movement, and may crack along the top of the pipeline.
Soil moisture that penetrates damaged coating can accumulate in the void between the pipe wall and disbonded coating, where it may eventually provide either the high or near-neutral pH environment conducive to SCC.
Earlier incidents identified as near-neutral pH SCC were generally located under spiral-wrap tape coatings. Spiral-wrap tape coating forms "tents" where the tape overlaps the previous wrap or passes over a longitudinal or helical seam in line pipe.
Spiral-wrap tape may also "wrinkle" where tape passes over a field bend or other irregular contour. Groundwater that penetrates tape coating at the overlap or damage may accumulate in nearby tents and wrinkles. Asphalt enamel coating can disbond around the circumference of a pipeline while remaining relatively intact. Groundwater accumulating under disbonded tape or asphalt coating may eventually provide an environment conducive to SCC.
The circumferential stress in pipelines designed with a maximum allowable operating pressure (MAOP) of 72% of specified minimum yield strength (SMYS) typically exceeds the threshold stress for SCC in buried pipelines. Pipelines designed with a MAOP of 30% of SMYS are not likely to experience SCC, unless the external stresses are significant.
Conditions that may contribute to SCC
SCC may occur when the environment in contact with a pipe surface is one that promotes SCC and when the combined residual, pressure, and external stresses are above the stress threshold level.
Disbonded but relatively intact external coating may also shield the pipe surface from cathodic protection, but current flow through the liquid may elevate the native pH of the ground water into the cracking range for classic SCC.
External pipeline coatings may disbond as a result of application errors, excessive temperature, soil stresses, and the nature of the coating system. Application of external coating over a contaminated pipe surface is an installation error that has contributed to disbonding.
Heat from gas compression can cause premature degradation of coal tar and asphalt coatings downstream from compressor stations and can render the coatings more susceptible to soil stresses. Spiral-wrap tape coating may not adhere to the surface adjacent to contour irregularities, such as longitudinal seams and bends.
SCC may occur when the environment in contact with a pipe surface is one that promotes SCC and the combined residual pressure and external stresses are above the threshold stress. SCC may become inactive for extended periods when the environment or stresses shift outside the cracking window but can reactivate if conditions return to the cracking window.
The effective rate of crack extension is a function of the active growth rate and the proportion of the time that a crack is active. Multiple variables influence the proportion of time that a crack in a pipeline is active, making estimation of the effective growth rate extremely difficult.
Extensive testing of line pipe with and without SCC has attempted to identify physical, chemical, or microstructural attributes, such as manufacturer, vintage, pipe type, grade, wall thickness, actual strength, chemical composition, and rolling practice, that are correlated with susceptibility to SCC. As yet, no cost-effective method to produce line pipe immune to SCC has been identified.
SCC detection
Because not all pipeline segments with disbonded coating have suffered SCC, discrimination of locations with and without SCC is critical to assessing pipeline integrity. While some SCC may be visible to the unaided eye, visual examination alone is insufficient to reliably detect SCC.
Both magnetic particle testing (MT) and dye-penetrant testing (PT) will reveal SCC when the pipe surface is properly prepared, but MT may be more cost effective when electric power to energize a magnetizing yoke is available.
MT with the particles suspended in a liquid is more sensitive for detection of SCC than MT with dry powder, but both methods can be useful. A significant portion of detected classic SCC has been located on the lower third of pipelines.
Properly applying magnetic particles to the lower third of a pipeline requires training and practice to develop the necessary skills. Technicians assigned to inspection of pipelines for SCC should be trained on pipe sections containing SCC that were removed from a pipeline and should have demonstrated their ability to detect SCC in all positions.
Accommodating the physical needs of inspectors, such as providing sufficient clearance, surface preparation, pumping water from excavations, etc., is also critical to conducting reliable inspection efforts of the lower portion of a pipeline to detect SCC.
Vendors of inline inspection (ILI) services began developing tools for detection of SCC in the early 1970s in response to initial SCC failures. This development has been a challenging and costly endeavor. Reportedly, the ILI tools that use ultrasonic testing in hazardous liquid pipelines in which the transported fluid couples the transducers to the pipe wall are generally satisfactory for detecting SCC.
In contrast, operators of gas transmission pipelines that have run ILI tools to detect SCC have stated that the tools do not adequately discriminate between SCC and other imperfections not injurious to pipeline integrity. Excavation of all ILI indications in a gas pipeline for direct examination—to identify a relatively few that are SCC—may be costly.
It seems likely that widespread application of ILI for detection of SCC in gas transmission pipelines will require significant advancement in ILI technology.
Root cause of leaks, ruptures
Even extensive SCC may not be nearly as apparent to the untrained and unaided eye as external corrosion or mechanical damage. SCC of sufficient severity to cause a leak or rupture may not be apparent without direct examination of the pipe by someone familiar with identification of SCC.
Because inexperienced persons may not recognize SCC, leaks and ruptures resulting from this phenomenon may have gone unrecognized and unreported.
Field examination of the pipe surface around each leak or rupture associated with disbonded coating using MT or PT could be a cost-effective method to determine if SCC was a contributing factor. If the precise cause of a pipeline rupture is not readily apparent during field examination, a laboratory familiar with all the causes of pipeline failures should examine appropriate samples. Prudent operators should have a plan for systematic examination of leaks and ruptures to determine the root cause with some certainty.8
Prudent management of the SCC threat
Compliance with the OPS advisory recommending pipeline owners and operators consider the SCC threat requires systematic and defensible procedures that are appropriate for the pipeline system of interest. The OPS advisory refers to Appendix A3 "Stress Corrosion Cracking Threat" of ASME B31.8S, Managing System Integrity of Gas Pipelines, which lists these data elements for screening pipeline segments for the potential for SCC:
- Age of pipe.
- Operating stress level (% SMYS).
- Operating temperature.
- Distance of the segment from a compressor station.
- Coating type.
Whereas procedures can and should be tailored appropriately for each pipeline system, pipeline systems could be classified in three general categories for management of SCC:
- No known SCC occurrence in the pipeline system.
- SCC detected in the pipeline system by ILI or direct examination.
- Hydrostatic test or in-service failures due to SCC in pipeline system.
Prudent management of SCC in a pipeline system that has experienced no known occurrences of SCC in the system might include the following actions:
- Basic SCC awareness training of all staff and field employees responsible for operation and maintenance of the pipeline system.
- MT or PT of bare pipe surfaces exposed for examination performed by a nondestructive evaluation (NDE) technician trained in detection of SCC of buried pipelines.
- Documentation of each examination for SCC, including location, observations, and findings.
The above actions would improve the probability of identifying the presence of SCC before a service leak or rupture. Prudent management of SCC in a pipeline system that has experienced one or more confirmed incidents of SCC might include each of the above actions, plus:
- Systematic identification and examination of other potential locations of SCC based upon the observation of conditions associated with the confirmed SCC incidents.
- Scheduled hydrostatic testing or ILI of valve sections that have experienced multiple confirmed incidents of SCC.
Prudent management of SCC in a pipeline system that has experienced one or more hydrostatic testing or in-service leaks or ruptures attributed to SCC might include each of the above actions, plus:
- Temporary pressure reduction followed by spike hydrotest or ILI of each valve section that experienced hydrostatic testing or in-service failure (leak or rupture) before return to service.
- Periodic reexamination of valve sections that have experienced confirmed incidents of SCC at an interval selected to avoid in-service failure.
Pipeline owners and operators may elect to implement additional measures to identify and mitigate SCC in their systems. These measures may depend upon a variety of conditions, such as the anticipated consequences of in-service rupture due to SCC.
Likewise, OPS may elect to impose additional measures to manage SCC depending upon the specific circumstances, especially those involving leaks and ruptures associated with SCC.
Design, construction to avoid SCC
Based on current understanding of SCC, the most cost-effective mitigation of SCC, as well as external corrosion, is to ensure integrity of the external coating for the life of the pipeline. This requires, at a minimum:
- Systematic selection of coating systems for both the pipe and joints with known resistance to disbonding and other degradation in the expected service conditions.
- Detailed specification of the coating material, surface preparation, and coating application parameters, ensuring the anticipated quality of the selected coating systems.
- Diligent quality control during surface preparation and coating application, as well as during transportation, stringing, joining, and lowering.
- Sufficient padding of the pipeline with backfill that will not damage the coating during the useful life of the pipeline.
- Operation of the cathodic protection system in a manner that avoids premature degradation of the coating.
Industry needs
Employees of pipeline systems that have experienced SCC failures should be made aware of the SCC threat, but employees of pipeline operators that have never identified SCC in their system are less likely to consider SCC a risk. The pipeline industry could benefit from industry-wide SCC awareness training of pipeline employees, especially for those field employees responsible for operation and maintenance of gas and hazardous liquid pipelines.
A web-based, self-training course, including multiple levels of detail for different levels of opportunity to observe SCC, could become an effective tool for increasing SCC awareness across the industry. An industry group or groups should consider developing an SCC-awareness training tool that could be made available to pipeline operators through sponsorship or on a cost-recovery basis.
The technical information necessary for creating SCC awareness training should be available from pipeline operators who have experienced SCC, and multiple organizations are experienced developers of web-based training tools.
Reliable NDE of a pipeline for SCC requires that each technician be trained specifically for SCC detection, in addition to basic training and qualification in MT or PT. Pipeline operators that have discovered multiple examples of SCC can employ samples containing SCC for training and qualification of technicians in detection of SCC.
Pipeline operators that have not encountered SCC or commercial inspection services may not have suitable samples for technician training and qualification. Once again, an industry group should consider organizing one or more training centers equipped with samples of both types of SCC for training and qualification of NDE technicians in detection of SCC in pipelines.
Despite substantial investment in research and development since the first recognized SCC pipeline failure in 1965, the pipeline industry still needs additional tools for reliable and cost-effective management of the SCC threat to pipeline integrity. Future research results must influence day-to-day SCC management activities to be of enduring value to the industry and public.
For example, the pipeline industry and its regulators could benefit from an aggressive investment in technology for more reliable and cost-effective detection of SCC in buried pipelines. Improved ILI technology for gas pipelines could be a goal of investment in SCC management technology. More cost-effective SCC direct-assessment technology, especially for identification of disbonded coating, could improve identification of pipeline segments that are likely to suffer SCC.
A significant number of operators who have experienced SCC rely only on grinding of cracks to determine their depth. A reliable NDE method to expedite determination of the deepest depth of cracks in an SCC colony could speed assessment of SCC severity when it is found. Selecting an appropriate interval for periodic reassessment of a pipeline segment suspected of containing SCC requires an estimate for both the likely depth of existing cracks and their anticipated growth rate.
Estimates of the crack growth rate for SCC in buried pipelines exist but may not be applicable to all situations. In situ measurement of crack growth rates is more challenging than in laboratory tests, but more reliable in situ growth rates could be useful when selecting reassessment intervals.
A standard industry protocol for data collection during direct examination of pipeline segments for SCC could facilitate evolution of efficiently designed databases to aid in the identification of segments with significant threat of SCC. Conditions of operator participation in such a database would require the data never to be traceable to a specific pipeline segment or operator and that an operator must contribute data to access the database.
The Pipeline Performance Tracking System (PPTS), sponsored by the API Operators Technical Committee, was identified as a possible platform for capture of SCC-related data for hazardous liquid pipelines.
Finally, the pipeline industry could benefit from periodic assessments of the state of knowledge for management of the SCC threat to pipeline integrity, including tracking of progress and identification of high-value opportunities for funding research and development. For example, the report to OPS relied heavily upon previous periodic assessments of the state of SCC knowledge,9-11 and periodic reviews at 3-5 year intervals could continue the progress.
Perhaps one of the industry groups that cosponsored the SCC workshop could volunteer to develop a scorecard to track progress on each of the needs identified above and issue an annual report. If multiple industry groups or a combination of groups would adopt one of the identified needs for tracking, the effort and responsibility for tracking SCC progress could be shared across the industry.
While the referenced SCC study is a good start, industry and the regulators need to enhance the development of techniques for detection and monitoring through cooperative research and development. SCC is a threat to pipelines as shown by the failure history, but we have not determined the extent or probabilities associated with SCC conditions and more work is necessary.
References
1. Delivery Order DTRS56-02-D-70036, TTO Number 8, Stress Corrosion Cracking Study, January 2005.
2. 49 CFR Part 192 Subpart O – Pipeline Integrity Management.
3. 49 CFR Part 195 § 195.452 Pipeline Integrity Management.
4. Advisory Bulletin (ADB-03-05), http://ops.dot.gov/regs/adv/AdvisoryBulletin100103.htm.
5. http://primis.phmsa.dot.gov/ gasimp/mtg_120203.htm
6. Stress Corrosion Cracking on Canadian Oil and Gas Pipelines, Report of the Inquiry, National Energy Board, MH-2-95, December 1996.
7 The CEPA Report on Circumferential Stress Corrosion Cracking. Submitted to the National Energy Board, Canadian Energy Pipeline Association, December 1997.
8. McHaney, J.H., Greenslate, R.N., Lebsack, D.B., and Eckert, R.B., "Advanced Planning Advised to Manage Pipe Failure Investigations," Pipe Line & Gas Industry, January 1999, pp. 83-90.
9. National Energy Board, "Stress Corrosion Cracking on Canadian Oil and Gas Pipelines, Report of the Inquiry," MH-2-95, December 1996.
10. Hall, R.J., and McMahon, M.C., "Stress Corrosion Cracking Study," US Department of Transportation, Research and Special Programs Administration, Office of Pipeline Safety, May 1999.
11. NACE International, "External Stress Corrosion Cracking of Underground Pipelines," Publication 35103, Item Number 24221, October 2003.
- The Pipeline and Hazardous Materials Safety Administration's (formerly the Research and Special Programs Administration) Office of Pipeline Safety (OPS) final report documenting this SCC review is available for public access on the OPS web site (http://ops.dot.gov).
The authors
Paul Carson (PCARSON@ mbakercorp.com) is a pipeline consultant for Michael Baker Jr. Inc., Anchorage. He has more than 15 years' engineering experience in energy-related industries, focused on pipeline design and operations. Carson holds a BS in civil engineering from Washington State University and is a licensed professional engineer in Alaska.
Bruce E. Hansen is a senior engineer for the Office of Pipeline Safety (OPS), Washington, DC, currently working on program development for implementation of integrity management regulations. He has worked for OPS for 16 years as inspector, state liaison, risk management, and demonstration project developer. Hansen spent 4 years in Alaska as a member of the Joint Pipeline Office. Previously, he worked for Panhandle Eastern Pipeline Co. for 8 years. He holds a BS in civil engineering from the University of Missouri, an MS in engineering management from the University of Dayton, and an MBA from Rockhurst College, Kansas City, Mo.
Jim McHaney is an integrity management consultant for Michael Baker Jr. Inc., Houston. He has 34 years' metallurgical engineering and integrity management experience in energy-related industries, including work with drilling and production, upstream processing, pipeline transportation, and petrochemical plants. McHaney has provided material and integrity-related technology to major capital projects from design through commissioning, and to operations from start-up through abandonment. He holds a BS and MS in metallurgical engineering from the University of Texas at El Paso and is a licensed professional engineer in Texas.
