Advertisement

Stress Corrosion Assessment and Mitigation in Buried Pipelines

By Dennis Jayasinghe | Reviewed by Raghvendra GopalCheckmark
Published: August 31, 2022
Key Takeaways

Properly assessing stress corrosion cracking is the first step, deciding which mitigation strategy is the next. Here's what you need to know. 

Stress Corrosion Cracking (SCC) is often the predominant failure in high–pressure gas transmission pipelines. Long-term operation of pipelines could lead to degradation of mechanical properties of the steel, including a significant reduction of brittle fracture resistance and resistance to SCC. Regulatory requirements for impact toughness of oil and gas pipeline steels, disregarding steel condition, namely as-received or serviced. However, the SCC resistance of pipeline steels, which is very important for structural integrity, is often not regulated.

Advertisement

Stress corrosion cracking in pipelines begins when small cracks develop on the external surface of buried pipelines. These cracks are not visible initially, but as time passes, these individual cracks may grow and forms colonies, and many of them join together to form longer cracks.

The SCC phenomenon has four key stages:

Advertisement
  1. The initiation of stress corrosion cracks.
  2. The slow growth of cracks.
  3. The coalescence of cracks.
  4. Crack propagation and structural failure.

This process can take many years depending on the conditions of the steel, the environment and the stresses to which a pipeline is subjected. Consequently, failure as a result of SCC is relatively rare, although failures can be very costly and destructive when they do occur.


Why Conduct an SCC Assessment


SCC assessment plays a critical role in establishing pipeline integrity. Nowadays, North American regulators require pipeline owners to regularly provide SCC assessments of their pipelines. Once the SCC assessment has been completed in a section of the pipeline, that section is selected as the priority for inspection. SCC Condition Assessment requires evaluating the severity of individual SCC features and assessing the need for immediate and future pipe segment mitigation due to the presence of SCC. (Read also: 8 Tests that Help Engineers Mitigate Corrosion.)

Key data sources available for SCC condition assessment are:
  1. Field investigations at pipeline excavation locations.
  2. SCC pressure testing.
  3. Inline inspection for SCC.
  4. In-Service failures due to SCC.

While each data source can provide similar outputs, subtle but significant differences can affect the reliability and accuracy of the resultant condition assessment. In most cases, data from at least two sources is desirable to complement and verify against each other.

Advertisement

1. In-the-ditch inspection for SCC allows for measuring SCC colony density, interaction and individual SCC dimensions, and some pipe's material parameters such as wall thickness. When undertaking any excavation where SCC may be present, a reduction in the pipeline pressure at the excavation location must be considered. Further reductions should be undertaken if SCC is suspected within dents, gouges, buckles, or other complex stress regimes (such as geotechnical loading); additional reductions should be conducted. Commonly Wet fluorescent (WFMPI) and Black on white (BWMPI) magnetic particle inspection techniques are utilized to identify the presence and the length of surface-breaking SCC.

2. The minimum failure pressure for all SCC features within the pipe segment is more significant than the maximum pressure obtained during the test. Single SCC features that fail the pressure test can be characterized entirely concerning the failure pressure, pipe material properties, physical SCC dimensions, in-depth SCC interaction, and length directions. SCC that is most likely to fail is typically composed of several fused features with little likelihood of further coalescence. The quantity, density and location of SCC features that do not fail within a pipe segment remain unknown. If no SCC failure occurs, the determination of whether any SCC features exist within a pipe segment remains unknown. A successful SCC pressure test achieves a pressure of at least the maximum allowed operating pressure times the company-defined safety factor without incurring a failure.

3. SCC condition assessment requires specific data from inline inspection;

3.1) Measured minimum failure pressures are known within the data accuracy range, although the failure pressure may not have a well-defined minimum value for SCC deeper than 40% of wall thickness. These deeper SCC features are often annotated as "> 40%" on the ILI (In-Line Inspection) report. However, most ILI tools' detection and discrimination capability are significant for more profound and extended SCC features.

3.2) The quantity, density, and location of the SCC features are known within the pipe segment.

3.3) Calculated individual failure pressures are known for the accuracy provided by the tool measurements (within the defect groupings and ranges within each group.

4. SCC failure inspection data available for an SCC condition assessment can be summarized as follows:

4.1) Single SCC features that fail can be characterized entirely as to the failure pressure, pipe material properties, physical SCC dimensions, and interaction.

4.2) A minimum failure pressure for SCC features can be calculated for the remaining pipe segment by assuming that the most severe feature has failed; however, this pressure is typically at or below the operating pressure.

4.3) The quantity, density, and location of SCC features that do not fail within a pipe segment remains unknown.

Probably the largest source of uncertainty is the assumed crack growth rate. However, errors also can be introduced from the calculations of the crack sizes. To be conservative, it is important not to underestimate the size of the most significant surviving flaw and not to overestimate the size of a critical flaw at operating pressure.

SCC Condition Assessment Methodologies

External corrosion direct assessment (ECDA) methodology is mentioned in the NACE International standard practice SP05021 for integrity assessment of external corrosion threats on buried pipelines. This methodology can be used in combination or separately with NACE SP02042 on stress corrosion cracking (SCC) direct assessment methodology.

The NACE ECDA protocol is a four-step process:

  1. Pre-Assessment—pipeline’s physical characteristics, operating history, and prior inspections are documented.
  2. Indirect Inspection—Conducting complementary aboveground field surveys like direct current voltage gradient (DCVG), close interval potential (CIP), pipeline current mapping, and soil resistivity measurements are conducted.
  3. Direct Examination- pipe is verified for the aboveground survey results and physical inspection of the pipe coating, pipe surface, and soil electrolytes.
  4. Post Assessment—results gathered in steps 1, 2, and 3 are integrated for an overall integrity assessment, validation of the external ECDA process, and determination of the interval period to repeat the ECDA process.

Condition Assessment of SCC Severity

The severity of individual SCC features is defined by the calculated failure pressure of that feature. The minimum SCC failure pressure for a pipe segment can be directly determined from the failure pressure of an SCC feature failing during an SCC pressure test or in-service failure.

In addition, failure pressures can be calculated from measurements obtained at an excavation of the pipeline where SCC has been documented or from SCC ILI data where features have been identified.


SCC in Association with Other Features

The accuracy of the failure pressure calculation is dependent on the accuracy of the calculation of stress, which influences the SCC feature. For SCC interacting with other integrity defects, the interacting defect should be considered the primary integrity threat and managed with the appropriate detection and mitigation methods for this defect. However, the discovery of SCC within these features may require an increase in the risk of the interacting feature.


SCC Failure Pressure Calculations

There are several analytical models available for determining SCC failure pressures. These methods rely on the relationship between the applied stress, the material properties, and the resultant tolerable SCC size.

Some analytical models allow for a determination of the mode of failure for the SCC feature, that being a leak or a rupture. At pressures associated with both normal operation and higher pressures for SCC pressure testing, the metal ligament joining the tip of the SCC feature (in the depth direction) and the inner pipe wall will typically fail in a ductile manner, momentarily creating a through-the-wall feature.

Axial propagation of the resultant leak may or may not occur, depending on the axial length of the leak, the applied stress, and the toughness of the steel. However, axial propagation is typical of SCC features of the generation of pipe where SCC has been identified, resulting in a rupture as the normal mode of failure.


SCC Mitigation Methods

There are many SCC prevention methods available in the industry. However, the current article highlights the most popular methods.

1.Coatings

Inadequate coating performance is the central contributor to pipeline SCC susceptibility. The pipeline company should emphasize developing coating procedures so that future coating failure susceptibility, especially disbondment, is minimized. When selecting the appropriate coating material, a balance between performance properties and application constraints must be considered. The pipeline company must know the exposure conditions the pipeline coating will face and the practical challenges when applying a coating intended for long-term performance. Coatings should possess the following performance characteristics:

  • Adhesion/Resistance

Materials with good adhesive properties are less likely to be affected by the mechanical action of soils, which expand and contract during periods of wet/dry or freeze/thaw cycles. Further, materials with good adhesive properties will be better able to resist the effects of water vapor transmission through the coating.

  • Low Water Permeability

Water vapor transmission into the coating may result in coating disbondment where less than optimal coating adhesion is present.

  • Effective Electrical Insulation

Coatings that provide good electrical insulation perform well if coating adhesion is good. However, if the coating disbonds, and therefore shields the CP current, isolated corrosion cells form, which causes high levels of localized corrosion.

  • Abrasion and Impact Resistance

Pipe contact with mechanical equipment or rocks could create coating damage. Good abrasion and impact resistance will minimize this damage.

  • Temperature Effects/Sufficiently Ductile

Coatings must remain sufficiently ductile to resist cracking in the range of temperatures expected to be encountered during pipe bending, handling, installation, and the pipeline's operational life.

  • Retention of Mechanical/Physical Properties

Over time, a coating's properties (like tensile, hardness, elongation) may change while in service. For example, polyethylene tapes have been observed to stretch over time, and old FBE (Fusion Bonded Epoxy) coatings have been known to become brittle.

If the coating selection contains the characteristics mentioned above, the reliability of the pipeline increases dramatically.


2. Cathodic Protection

Cathodic protection criteria and procedures should conform to applicable regulations and cathodic protection standards in NACE Standard RPO169 or the Canadian Gas Association (CGA) Recommended Practice OCC-1. These recommended practices guide applying adequate levels of CP, which can prevent the formation of transgranular SCC. (Read also: The Basics of Cathodic Protection.)

The recommended polarized or "off" potential range for the operation of cathodic protection systems is between -850 mV and -1100 mV. It is recommended to avoid potentials more negative than -1100 mV because they may promote hydrogen generation. Hydrogen can lead to hydrogen embrittlement of the pipe material, blistering and ultimately shielding the coating materials.

The 100 mV shift criterion, outlined in both NACE Standard RP0169 and the CGA Recommended Practice OCC-1, may promote potential in the cracking range for high-pH SCC. Therefore, this criterion should be applied with caution when associated with high-pH SCC conducive environments

Pipe-to-soil potentials will be measured with a Cu/CuSO4 half-cell electrode (or alternative with the appropriate potential adjustment). The CP currents will instantaneously be interrupted on the protected structure. All measurements must be free of induced AC or DC interference from nearby foreign structures or foreign CP systems.

Seasonal variations can also influence ground conductivity by variation in soil moisture content. The corrosion personnel charged with adjusting and monitoring individual CP systems should modify these potential criteria to account for these variables.


3. Hydrostatic Retesting

Through operating experience and research, hydrostatic retesting has shown to be a very effective means of safely removing near-critical axial defects, such as SCC, from both natural gas and liquid hydrocarbon pipelines. Usually, pipeline companies use hydrostatic retesting for a variety of reasons, including:

  1. To qualify a section of the Pipeline for higher maximum operating pressures.
  2. To qualify a section of Pipeline for a change of service.
  3. To confirm the integrity of a section of the Pipeline from potential time-dependent threats such as corrosion (both external and internal), SCC, construction damage, and manufacturing defects.

Since pipeline integrity is much more likely to be affected by longitudinally oriented defects than by circumferentially oriented defects, hydrostatic testing is one of the best ways to demonstrate the integrity of a pipeline. End-users need to examine their specific situation when developing a hydrostatic retest procedure. The following factors should be considered when developing a hydrostatic retest procedure:

  1. Test appropriateness.
  2. Level of safety factor to establish in the pipeline segment.
  3. Test pressure level.
  4. Actual yield strength test.
  5. Mill defects and test pressure.
  6. Retest frequency.
  7. Safety and safety factors.

4. Repairs

Repairs play a crucial role in the mitigation of SCC defects. Pipe or pipelines containing SCC defects can be repaired using one or more of the acceptable repair methods given in the CSA Z662 code.

  • Grinding and Buffing

SCC cracks should not be removed by grinding on a high-pressure pipe. Only 'buffing' using softback discs should be carried out on high-pressure pipelines. Strong consideration should be given to determining a safe pressure before applying any crack removal process. If grinding or buffing results in a localized metal loss that exceeds the limits specified in the code, a permanent repair should be made.

  • Sleeves

This repair can be made with either a pressure-containment or reinforcement sleeve. Pressure-containment repair sleeves are designed to retain the pressure of the pipeline fluid in the event of a failure of the parent pipe under the sleeve, or the parent pipe is "tapped" so that the sleeve becomes pressure-containing and the defects no longer grow on the parent steel.

  • Steel Reinforcement Sleeves

Applying structural reinforcement sleeves for permanently repairing SCC is restricted to either full compression reinforcing sleeves or after SCC that has been completely removed through buffing. If the buffing repair of SCC results in a metal loss in excess of that permitted by the CSA Z662, the metal loss defect can be permanently repaired by installing a reinforcing sleeve. An

The exception is that the reinforcement sleeve is restricted to repair the metal loss of less than 80%. Reinforcement sleeves should be used after an engineering assessment.

  • Composite Reinforcement Sleeves

Applying a composite reinforcement sleeve for repairing SCC is restricted to reinforcing SCC that has been entirely removed by buffing. For SCC colonies where the buffing repair has resulted in a metal loss in excess of that permitted by CSA Z662, a permanent repair can be achieved by installing a composite reinforcement sleeve. Similar to the steel reinforcement sleeves, the composite reinforcement sleeves prevent failure of the defect through the partial transfer of the hoop stress to the sleeve material and provide restraint of localized bulging in the defect area.

A detailed engineering assessment of the defect and sleeve repair must precede the installation of the composite reinforcement sleeve to ensure that the strength of the repair will be equivalent to that of the original carrier pipe. In strict accordance with the manufacturer's specifications, only trained technicians should install the composite reinforcement sleeve.

  • Repair by pipe replacement

Selective pipe replacement is one of many options available in mitigating SCC on a given segment of the Pipeline, or portion thereof, determined to be susceptible to SCC. Pipe replacement, although highly effective, is very costly and requires a service interruption for installation. The effectiveness of a pipe replacement depends on establishing an adequate replacement distance to ensure the entire affected pipe has been replaced.

Evaluating potential pipe replacement locations can be based on two possible scenarios. The first scenario is that a company has detected SCC at an investigation site and has determined that a pipe replacement is the most suitable means of repair. The second scenario is that the company has identified discrete portions of a pipeline segment or segments that may be susceptible to SCC in their assessment. Under this scenario, they may have subsequently determined a pipe replacement program in such areas would be the most effective method of addressing the situation..

Determining the appropriate length of pipe replacement at a given location depends on the basis for the replacement. If the pipe replacement is to repair SCC detected at an investigation site, then the length of the replacement should be to ensure the removal of SCC colonies at that specific site.

As a material of construction, carbon steels are most susceptible to hot nitrate, hydroxide, and carbonate or bicarbonate solutions. High-strength steels are also susceptible to hydrogen sulphides.

Auestnitic stainless steel are normally susceptible to hot, concentrated chloride solutions and chlorine-contaminated steam. (Read also: Chloride Stress Corrosion Cracking of Auestnitic Stainless Steel.)

However, duplex steels, which have a blend of austenitic and ferritic metallurgical composition, can withstand higher temperatures before any SCC initiation occurs. This makes duplex stainless steels an excellent choice for use in high-temperature processes when there is risk of SCC.

Ideally, SCC should be considered right from the design phase, which includes choice of materials, environmental controls and stress reduction and elimination.

When the likelihood for SCC is high, designers must carefully design piping systems so as to minimize stress concentration. The impact of any corrosive solutions used shall also be considered.

Advertisement

Share This Article

  • Facebook
  • LinkedIn
  • Twitter
Advertisement

Written by Dennis Jayasinghe | Principal/Chief Technical Officer, Corr-Met Inspection & Consulting Inc.

Profile Picture of Dennis Jayasinghe

Dennis Jayasinghe is a Senior Corrosion Engineer with over 15 years of combined experience in industry and research. Dennis brings substantial experience in corrosion failure analysis, corrosion mitigation and monitoring methods, corrosion inspection, design improvement against corrosion, corrosion risk assessment, development of corrosion management programs, and proper material selection for a specific environment. Additionally, he is an expert in solving quality-related issues of steel, stainless steel and galvanizing. After holding senior engineering positions in various manufacturing companies in Canada, he established CorrMet Inspection & Consulting, where he served as Principal. Dennis is a registered and active professional engineer in Alberta and Saskatchewan provinces in Canada and a full NACE member.

Related Articles

Go back to top