In contrast to the straightforward and conservative calculations typically found in design codes for new fabrications or constructions, flaw assessment involves more sophisticated evaluations. Generally, flaws that result in metal loss or changes in local geometry can lead to high local stresses, causing failures in the form of plastic collapse, while crack-like flaws may initiate and propagate fractures. A typical flaw assessment incorporates multiple material property parameters and facility operation parameters to determine safe operating conditions. These advanced methods can more accurately assess whether a structure is fit for its intended service or if specific fabrication defects or in-service deterioration jeopardize its integrity. In addition to API 579-1/ASME FFS-1, which is widely used for flaw assessments, various industry standards and procedures are available depending on the types of flaws being evaluated.

Dents in pipelines can be assessed based on the severity of local deformation. Typical assessment methods include Code /Standard-based procedures and case-specific finite element analyses.

US DOT regulations (49 CFR Parts 192 and 195) outline dent repair and remediation criteria that consider factors such as dent depth, location (top or bottom side), pressure cycling (liquid or gas), and interaction with secondary features (welds, corrosion, cracks). Additional reference standards for dent assessment are provided by ASME B31.4, ASME B31.8, CSA Z662, and API 1160. Equivalent regulatory standards are also found in other countries, such as CSA Z662 in Canada, EN 1549 for gas pipelines and EN 14161 for liquid pipelines in Europe, as well as AS 2885 in Australia. Notably, the U.S. standards tend to be more explicit and prescriptive compared to those in other nations.

While Code /Standard-based criteria are straightforward to apply, they may not adequately address higher-risk dent features and can sometimes be overly conservative or, in some cases, not conservative enough. Finite Element Analysis (FEA) can be utilized for case-specific level three assessments.

At CCPGE, we have developed a comprehensive process that combines our experience with industry best practices to identify critical dents that may be overlooked by simply relying on Code /Standard-based criteria or ILI calls. Proactively identifying and remediating critical dents before incidents occur is highly beneficial for both operators and the public.

Below is an example of a level 3 FEA for pipeline dent assessments. This analysis provides valuable insights into equivalent plastic strain (PEEQ) and stress distribution, which are crucial for predicting crack initiation and assessing fatigue life of the dent.

Dent Assessment Using 3D FEA

Depending on the type of a corrosion feature, different methods can be used for assessment. Various methods for assessing corrosion that exist for use, including B31G, modified B31G, RSTRENG, DNV-RP-F101, etc. A number of conclusions on the behaviour of corrosion defects from various authors in the oil and gas industry are listed below:

• The longitudinal extent of a corroded area is the most important length parameter for the burst strength under internal pressure loading. The circumferential extent has a small influence on the burst strength, but the effect is sufficiently small to not need considering. However, the circumferential extent must be considered if external axial and/or bending loads are present.
• External loads reduce the burst pressure compared to the case of an end-capped pressure vessel (axial stress equal to half the hoop stress). The effect of tensile external loads is generally small, whilst compressive loads can cause a significant reduction in the burst pressure.
• No difference between the behaviour of internal and external corrosion has been noted in full scale tests or finite element analyses (but noting that pipelines are thin walled geometries).
• Short defects (typically less than 3t in length) of any depth record high burst pressures, typically above the pressure required to yield the uncorroded pipe.
• In modern, tough, line pipe steel the flow stress for smooth corrosion defects is the ultimate tensile strength of the material.
• The effect of toughness of a sharp defect is more significant than that on a blunt defect.

Pipeline gouge assessment involves evaluating the severity and impact of gouges or mechanical damage on the structural integrity of a pipeline. Here's a brief description of the process:

• Identification: The first step in gouge assessment is identifying the presence of gouges or mechanical damage on the pipeline surface. This may involve visual inspection, non-destructive testing (NDT) techniques such as ultrasonic testing (UT) or magnetic particle inspection (MPI), or inline inspection tools such as smart pigs.
• Characterization: Once gouges are identified, they are characterized based on parameters such as depth, length, width, orientation, and location along the pipeline. This information helps assess the severity and potential impact of the gouges on the pipeline's structural integrity.
• Severity Assessment: Gouges are evaluated to determine their severity and the extent of damage to the pipeline wall. Factors such as the depth of the gouge, proximity to welds or other features, and the presence of internal or external pressure are considered in assessing the severity of the gouge.
• Risk Analysis: The assessed gouges are then analyzed to determine their potential risk to the pipeline's structural integrity, safety, and operability. This may involve considering factors such as the pipeline's operating conditions, the material properties of the pipeline, and the likelihood of further damage or failure.
• Mitigation Measures: Based on the gouge assessment results, appropriate mitigation measures are recommended to address any identified risks or concerns. This may include repair techniques such as welding, sleeving, or installing protective coatings to reinforce the affected area and prevent further damage.
• Monitoring and Follow-Up: After mitigation measures are implemented, the gouged area is monitored periodically to ensure the effectiveness of the repairs and assess any changes in the condition of the pipeline over time. This may involve regular inspections, inline inspections, or ongoing risk assessments.

Preventing SCC corrosion often involves a combination of material selection, design considerations, and maintenance practices. Protective coatings, corrosion inhibitors, and cathodic protection systems may be employed to mitigate the risk of SCC corrosion in susceptible environments. Additionally, stress relief treatments, such as post-weld heat treatment or shot peening, may be used to reduce residual stresses in components and minimize their susceptibility to SCC corrosion. Regular inspection and monitoring are essential for detecting early signs of SCC corrosion and implementing corrective measures to prevent catastrophic failures.

At CCPGE, the SCC assessment is performed as per Guideline of CEPA.

Pipeline crack assessment is a critical process to ensure the integrity and safety of pipelines. It involves the application of fracture mechanics and the associated data requirements and defect sizing. In addition to the crack assessment, a crack management program for a system requires more to complete. Typically a crack management program includes the following points:

• Detection and Sizing: In-line inspection (ILI) tools are commonly used to detect and size crack-like anomalies. These can include weld anomalies, stress corrosion cracking (SCC), and pipe body cracks.
• Estimation of Stress: Stress normal to the crack is one essential factors for the crack to grow. In addition to the pipe internal pressure, ground condition and the pipe longitudinal stress estimation is required for some cases.
• Failure Modes: Cracks can fail through flow-stress or toughness-controlled modes. Flow-stress controlled failures behave similarly to metal loss, while toughness-controlled failures occur when the crack driving force exceeds the material’s resistance.
• Fracture Models: Selecting an appropriate fracture model is crucial. Models like NG-18, API 579, and BS 7910 are used to predict failure pressures and critical flaw sizes. More rigorous models may require fitness-for-service software.
• Material Mechanical Properties: Assessments require material properties, including toughness. These values can be obtained from material lab testing or industry databases
• Regulatory Requirements: For gas pipelines, regulations like 49 CFR 192.710 mandate regular assessments for crack threats. Methods must be suitable for the identified threats and may include hydrostatic testing or ILI.
• Management Strategies: Managing crack threats often involves hydrostatic testing or regular ILI. Operators need to identify critical anomalies, determine response times, and decide if pressure restrictions are necessary.