Corrosion of underground natural gas and liquid petroleum pipelines occurs in a variety of forms and requires specialized mitigation methods to detect and control. First identified in the 1960s, stress corrosion cracking (SCC) is a form of corrosion that results in clusters or colonies of cracks on the external surface of the affected pipeline.
According to the federal Pipeline & Hazardous Materials Safety Administration (PHMSA), the majority of pipeline incidents caused by SCC are found on natural gas pipelines rather than hazardous liquid pipelines. However, SCC can manifest itself wherever the right combination of factors exists.
On behalf of Pipeline & Gas Journal, NACE International invited NACE Fellow and external SCC expert John Beavers to answer questions on the causes of SCC, the technologies needed to detect and address this form of corrosion, and new developments to improve the performance and safety of pipelines susceptible to SCC.
Beavers, corporate vice president and director of Incident Investigation at DNV GL, acknowledges the input of DNV GL Vice President of Technology Oliver Moghissi, NACE past president, in the development and review of these comments.
NACE: Why does SCC occur on pipelines?
Beavers: Three conditions are necessary for external SCC on underground pipelines (like other forms of SCC) to occur: (1) a susceptible metal, (2) a tensile stress of sufficient magnitude, and (3) a potent environment at the metal surface. The carbon steels used to manufacture line pipe are susceptible to SCC in a number of environments, including two that develop beneath disbonded coatings underground.
Tensile stresses on underground pipelines originate from a number of sources, including residual stresses from pipe manufacturing and construction, internal operating pressure, damage to the pipeline, such as that caused by from dents and mechanical damage, and land movement. These stresses can be in the hoop direction (e.g., from the internal pressure), resulting in axial cracks in the axial direction axial (e.g., from land movement), resulting in circumferential cracks; or both directions (e.g., the combined stresses or from dents), resulting in cracks at other orientations.
The majority of underground pipelines are externally coated and cathodically protected to mitigate corrosion. A potent environment must have access to the metal surface for SCC to occur. Accordingly, an intact, well-bonded coating will mitigate all forms of external corrosion, including SCC. The first step in the development of a potent environment at the pipeline surface is the disbondment of the coating, typically at defects, referred to as holidays, in the coating.
There are two forms of external SCC on underground pipelines – high pH SCC and near-neutral pH SCC – which are associated with two different environments that develop at the pipe surface within these disbonded areas. Both environments are associated with the presence of carbon dioxide in the soil, typically from decay of organic matter. High pH SCC is most commonly associated with coal tar coatings, and the environment that develops at the pipe surface has a pH of 9-10.
The cathodic protection (CP) causes the pH of the electrolyte beneath the disbonded coating to increase and the carbon dioxide dissolves in the elevated pH electrolyte, resulting in a potent high pH-cracking environment containing carbonate and bicarbonate. Near-neutral pH SCC is most commonly associated with tape and asphalt coatings.
The environment that develops at the pipe surface in this case has a pH of 6-8 as a result of shielding of the CP current or inadequate CP. Carbon dioxide dissolves in the near-neutral pH electrolyte, resulting in a second type of potent cracking environment, containing bicarbonate and carbonic acid.
NACE: What are the risks associated with SCC?
Beavers: External SCC on underground pipelines typically forms in clusters or colonies. Individual cracks can interlink to produce flaws of sufficient size to cause ruptures. SCC may cause leaks in the absence of significant interlinking or at lower operating pressures. Leaks and ruptures of natural gas and liquid petroleum pipelines pose a threat to life, property and the environment. In general, liquid petroleum pipelines pose a greater environmental threat, while natural gas pipelines pose a greater threat to life and property, especially when the natural gas ignites.
NACE: Are some pipelines more at risk than others? If so, which ones and why?
Beavers: Risk is defined as the probability that an event will occur multiplied by the consequences of the event. The consequences of a failure of a petroleum pipeline increase with an increase in the diameter or operating pressure of the pipeline and with proximity to high-consequence areas.
There are a number of factors that affect the probability that external SCC will initiate, propagate or result in a rupture. These include the internal pressure, wall thickness, diameter, coating type, pipeline age, operating temperature, distance downstream of a pump or compressor station and a host of other factors that are summarized in Table 1 of NACE SP0204-2008.1.
In a nutshell, the operating hoop stress of a pipeline is probably the single most important factor affecting the probability of a failure. The hoop stress is determined by the combination of the operating pressure, wall thickness and pipe diameter, and it affects the likelihood of SCC initiation, the SCC crack growth rate and the likelihood of a rupture.
Coating type, and the associated surface preparation, also has a significant impact on the probability of an SCC failure. Fusion-bonded epoxy (FBE)-coated pipelines are generally considered to be immune to external SCC, according to Part A3.3.2 of ASME B31.8S.2. While this is not absolutely true, the probability of failure of an FBE-coated pipeline is so low that other integrity risks will almost always be greater. At the other extreme, older vintage polyethylene tape-coated pipelines have a relatively high probability of experiencing near-neutral pH SCC.
Pipeline age is another important parameter affecting the likelihood of a pipeline failure as a result of external SCC. Time is required for the coating to degrade, the potent cracking environment to develop, the SCC colonies to initiate and the cracks to either grow through the wall or interlink to create a critical flaw size for rupture. According to Part A3.3.2 of ASME B31.8S, pipelines that are less than 10 years old are not considered susceptible to SCC.
Elevated operating temperatures have a significant impact on high-pH SCC, increasing the likelihood that SCC will initiate and increasing the SCC propagation rate. Elevated operating temperatures also increase the rate of coating degradation for both forms of SCC.
Finally, the likelihood of SCC failures has been correlated with proximity downstream of a compressor or pump station. This is generally believed to be a result of maximum and cyclic pressures, as well as operating temperatures being generally higher near compressor or pump stations.
This results in higher maximum and cyclic stresses, as well as higher rates of coating degradation, in addition to the other detrimental factors associated with high-pH SCC. Further discussion of the other factors affecting the probability of an external SCC failure are given in SP0204-2008 and NACE Publication 35103.3
NACE: Can you describe materials, techniques and technologies used to prevent or mitigate SCC in pipelines?
Beavers: For new pipelines, the most effective method to prevent SCC is to select a high-quality coating, such as FBE, that is well adhered to the pipe surface and does not shield the CP current. The field girth-weld coatings should have equally good properties. With these coatings, a white or near white surface preparation should be used that enhances coating adhesion and imparts compressive residual stresses in the pipe surface. These stresses minimize or prevent SCC initiation.
For existing pipelines, an effective integrity management program can be implemented to manage the threat of SCC. For discrete locations requiring mitigation, the affected pipe can be repaired or replaced, or periodically hydrostatically tested to confirm the integrity. For long pipeline sections requiring mitigation, the affected pipe can be placed in a program involving periodic inline inspection (ILI) or hydrostatic testing. Alternatively, the entire section can be replaced.
In some cases, pipeline operation also can be modified to mitigate SCC. For example, in cases where high pH SCC is a threat on a gas transmission pipeline, this can be mitigated, to some extent, by installing after-coolers in the compressor stations to reduce pipeline operating temperatures.
In the case of near-neutral pH SCC of liquid petroleum pipelines, cyclic pressure fluctuations can be reduced to reduce the driving force for crack propagation. In other situations, effective control of CP potentials can be effective in mitigation for both forms of SCC.
NACE: What is included in a typical pipeline-integrity management program to assess susceptibility of pipelines to SCC?
Beavers: Integrity management programs designed to address the threat of external SCC generally include one or more of the follow three techniques: hydrostatic testing, direct assessment and ILI. These are used to manage other time-dependent threats, and the SCC threat can be included in an overall risk management program. In this way, all of the threats can be prioritized to optimize risk-mitigation activities, such as gaining the highest risk reduction at lowest cost. In this way, we don’t overwork an SCC problem that has little impact on total risk, or we better understand the impact of a previously under-recognized SCC threat.
Directly following the initial SCC failures of gas transmission pipelines in the 1960s, hydrostatic testing was the primary tool used to confirm the integrity of the affected pipelines and prevent additional failures. While hydrostatic testing has been effective in reducing service failures, it has a number of limitations. Very few, if any, SCC flaws are removed and the pipeline must be taken out of service for testing. Large, subcritical flaws remain in the pipeline and these can grow to failure, resulting in the necessity for frequent retesting.
The first recommended practice for SCC direct assessment (SCCDA) was issued in 2004 (NACE RP0204-2004; now SP0204-2008), although elements of SCCDA have been used in the industry since the first discoveries of SCC in the 1960s. The SCCDA process consists of four steps.
In the first step, pre-assessment, existing information on the pipeline is collected to assess the likelihood that the pipeline is susceptible to SCC and select susceptible pipe segments and possible dig sites. In the second step, indirect inspection, additional data are collected, as deemed necessary by the pipeline operator, to aid prioritization of segments and in site selection.
The third step is direct examination, in which the pipeline is inspected for SCC at selected field dig sites. In the final, post-assessment step, the data are analyzed to determine whether SCC mitigation is required, and if so, to prioritize those actions, define the interval for the next full integrity reassessment and evaluate the effectiveness of the SCCDA approach.
A significant issue with SCCDA is that it is not capable of reliably identifying the locations of the most severe SCC on a pipeline segment. Accordingly, it is better suited, currently, as a threat evaluation tool.
ILI is the third technique used to evaluate SCC threats on operating pipelines. Integrity management with ILI tools consists of finding and sizing the cracks, assessing the effect of the cracks on integrity and repairing the cracks, if required.
The greatest challenge with the current generation of crack-detection tools is related to the accuracy of crack-sizing; specifically, crack depth measurements. Because of these sizing issues, one or more validation methods, such as confirmatory hydrostatic testing or a validation dig program, are frequently employed with ILI.
Each of the three integrity techniques (hydrostatic testing, SCCDA and ILI) has strengths and weaknesses. Accordingly, a combination of these techniques chosen according to the specific pipeline of interest generally provides the most robust integrity management program to address the threat of external SCC.
NACE: Are there new, improved assessment methods available that lead to better monitoring, detection and mitigation?
Beavers: Significant effort is being expended in the pipeline industry to improve the crack detection and sizing capabilities of ILI tools and this investment is paying dividends. The electromagnetic acoustic transducer (EMAT) technology looks promising for the detection of SCC in natural gas pipelines, but it is subject to some of the same limitations as the more conventional ultrasonic crack detection tools used for liquid pipelines.
NACE: Are there any technology gaps that should be addressed?
Beavers: Field digs are a critical component of an SCCDA program. Dig programs also are frequently employed with ILI to validate the result of the ILI tool runs. ILI validation generally consists of performing field digs, inspecting the pipe and comparing the dimensions of the cracks measured in the field with those measured by the ILI tool.
There are several methods to measure crack dimensions in the field. Crack lengths are relatively easy to measure by means of magnetic particle inspection (MPI). Crack depths, on the other hand, are more difficult to measure. This can be done by grinding the cracks in steps, with periodic MPI, until the cracks have disappeared.
This method is effective but time consuming. An alternative approach is to use in-the-ditch nondestructive inspection techniques such as ultrasonic testing (UT). Improvements in the precision and accuracy of these techniques would better ILI verification and SCCDA programs.
NACE: Are there any additional comments you would like to make?
Beavers: External SCC of underground pipelines has been the focus of my comments. However, over the past 10-15 years, it has become apparent that internal SCC, as a result of exposure to alcohols, also can pose a threat to pipelines. Both ethanol and methanol are potent SCC agents. Fuel grade ethanol (FGE) meeting ASTM standards has caused SCC of carbon steel tanks and piping in terminals where it is stored.
Experience with FGE in underground transmission pipelines is extremely limited, primarily because of the threat from internal SCC. More recently, it has become evident that methanol also can pose a threat to pipelines. Methanol is used for pressure testing of pipelines and pipeline system components in cold climates and as a drying agent, to remove water from these systems. In at least one instance, the use of methanol has resulted in internal SCC of a crude oil transmission pipeline.
1 NACE SP0204-2008, “Stress Corrosion Cracking (SCC) Direct Assessment Methodology” (Houston, TX: NACE International, 2008).
2 ASME B31.8S, “Managing System Integrity of Gas Pipelines” (New York, NY: ASME).
3 NACE Publication 35103, “External Stress Corrosion Cracking of Underground Pipelines” (Houston, TX: NACE International).
Author: John Beavers is corporate vice president and director of Incident Investigation at Det Norske Veritas (U.S.A.), Inc. (DNV GL), Dublin, OH. He has directed and contributed to numerous research and engineering programs on corrosion and cracking behavior of underground pipelines on topics including failure analyses, critical literature reviews, and laboratory and field evaluations. Beavers holds a doctorate in metallurgical engineers from the University of Illinois. He can be reached at email@example.com.