Slope Movement Inspection Using Axial Strain Data Across Multiple Lines and Repeat Inspections

Axial strain inspection using the AXISS™ is an established tool in the pipeline operator’s toolbox to assess pipeline geotechnical threats and other strain related events. Consequently, there is a large database of axial strain data for several different pipelines operating in different environments and from multiple inspections at the same geographical locations. The Cheecham slope, located south east of Fort McMurray, Alberta, is a known geohazard site crossed by six individual pipelines. The lines were constructed between 1999 and 2013 and have a size range of 10” to 36”. Five out of the six lines, 12” to 36”, have been inspected using the axial strain tool. The pipelines inspected cover a range of characteristics including, different vintages, pipe diameters and positions in the ROW. These differences, and the ILI runs provide an insight into the effect of a landslide event on the strain response of these pipelines. Axial strain measurement of the multiple pipelines in the Cheecham slope’s ROW allows: i) a direct comparison between lines ii) evaluation of the strain profile across the slope iii) assessment of the magnitude of the axial strain in terms of pipe characteristics e.g. pipe vintage and mechanical properties. More importantly, the axial strain data may provide an additional tool to assess the effectiveness of strain mitigation steps carried out over the years. An increase in the frequency of axial strain ILI runs resulted in additional data being available and more importantly data from run to run inspections spread over months or sometime years. A single run captures the strain at the time of inspection but run to run inspections provide an additional comparative tool to evaluate and monitor pipeline movement. Two out of the five lines inspected have run to run axial strain data. This paper takes the Cheecham slope as a case study to discuss the benefits of run comparison of ILI axial strain data either by comparing strain values of repeated runs for a single line or by the cross comparison of strain responses of different lines in the same ROW. The paper aims to demonstrate how run to run analysis of ILI axial strain data can be implemented as part of geohazard risk management program to asses strain risk profiles of these locations and to assess the effectiveness of strain mitigation programs previously undertaken by operators.

The Story of the Dent-Gouge Fracture Model

Once upon a time the dent-gouge fracture model was developed by the then British Gas Corporation to estimate the burst pressure of a dent and gouge subject to internal pressure. The dent-gouge fracture model is based on a two-dimensional representation of a dent and gouge; it assumes an infinitely long, longitudinally-orientated gouge (a crack) at the base of infinitely long, longitudinally-orientated dent. The model was calibrated using the results of 109 ring tests and 23 vessel tests conducted by the British Gas Corporation; a dent was introduced and then a slot was machined in the base of the dent (all at zero pressure). It is a semi-empirical model. Part 12 of API 579-1/ASME FFS-1 2016 quotes the original dent-gouge fracture model. A number of variations on the theme of the original dent-gouge fracture model have been developed. The variants have not significantly improved the accuracy of the original model, as is demonstrated by comparing the variants against the results of burst tests on rings and vessels containing a dent and gouge (or notch) reported in the published literature. The dent-gouge fracture model is deconstructed in order to illustrate its component parts. The deconstruction clearly identifies the parts of the model that could be improved. It also highlights where semi-empiricism is embedded in the model. The effect of changes to the original model is illustrated using the results of the full-scale tests. The difficulties introduced by the scatter in the full-scale tests are discussed, noting that a number of different methods have been used to introduce the dent and gouge (or notch) into the ring or vessel. A factor of safety is proposed. Pointers are given to how the dent-gouge fracture model might be improved or replaced. The need for a dent-gouge model is also considered, in the context of the guidance given in API Recommended Practice 1160 and ASME B31.8S.

Dent Screening Criteria Based on Dent Restraint, Pipe Geometry and Operating Pressure

A safety advisory (2010-01), issued by the National Energy Board (NEB) in June 2010, referenced two incidents which were a result of a fatigue crack failure that occurred within shallow dents [1]. The dents in both instances were less than 6% (of the OD). Currently, there is no consensus on how shallow dents or shallow dents with stress concentrators, as called by the ILI tool, are assessed and acted upon. BMT Canada Ltd. (BMT) was contracted by the Canadian Energy Pipeline Association (CEPA) to develop a definition for shallow dents, and two levels of screening method for the integrity assessment of shallow restrained dents and unrestrained dents. These two levels are known as CEPA Level 0 and CEPA Level 0.5 dent integrity assessment techniques that may be applied without finite element modelling or detailed calculations. The BMT dent assessment finite element (FE) modeling method was used to develop an extensive database of dents for different pipe geometries (OD/t), indenter shapes, pipe grades, and indentation depths. The results of the FE modelling were used to develop trends for the stress magnification factors (KM) across the range of pipes and dents modelled. These trends are used as the basis for the Level 0 and Level 0.5 dent screening and assessment approaches that can be used for both unrestrained dents and shallow restrained dents. The results show that for low OD/t pipe geometry and/or low spectrum severity indicator (SSI) [2] dent fatigue life may not pose an integrity threat. These dent screening approached have been adopted in the API Recommended Practice 1183 Dent Assessment and Management, that is currently under development.

Failure Pressure Prediction of Cracks in Corrosion Defects Using XFEM

Coating and cathodic protection degradation can result in the generation of several types of flaws in pipelines. With the increasing number of aging pipelines, such defects can constitute serious concerns for pipeline integrity. When flaws are detected in pipelines, it is extremely important to have an accurate assessment of the associated failure pressure, which would inform the appropriate remediation decision of repairing or replacing the defected pipelines in a timely manner. Cracks-in-corrosion (CIC) represent a class of defect, for which there are no agreed upon method of assessment, with no existing analytical or numerical models to predict their failure pressures. This paper aims to create a set of validated numerical finite element analysis models that are suitable for accurately predicting the failure pressure of 3D cracks-in-corrosion defects using the eXtended Finite Element Method (XFEM) technique. The XFEM for this study was performed using the commercially available software package, ABAQUS Version 6.19. Five burst tests of API 5L X60 specimens with different defect depths (varying from 52% to 66%) that are available in the literature were used to calibrate the XFEM damage parameters (the maximum principal strain and the fracture energy). These parameters were varied until a reasonable match between the numerical results and the experimental measurements was achieved. Symmetry was used to reduce the computation time. A longitudinally oriented CIC defect was placed at the exterior of the pipe. The profile of the corroded area was assumed to be semi-elliptical. The pressure was monotonically increased in the XFEM model until the crack or damage reached the inner surface of the pipe. The results showed that the extended finite element predictions were in good agreement with the experimental data, with an average error of 5.87%, which was less conservative than the reported finite element method predictions with an average error of 17.4%. Six more CIC models with the same pipe dimension but different crack depths were constructed, in order to investigate the relationship between crack depth and the failure pressure. It was found that the failure pressure decreased with increasing crack depth; when the crack depth exceeded 75% of the total defect depth, the CIC defect could be treated as crack-only defects, since the failure pressure for the CIC model approaches that for the crack-only model for ratios of the crack depth to the total defect depth of 0.75 and 1. The versatility of several existing analytical methods (RSTRENG, LPC and CorLAS) in predicting the failure pressure was also discussed. For the corrosion-only defects, the LPC method predicted the closest failure pressure to that obtained using XFEM (3.5% difference). CorLAS method provided accurate results for crack-only defects with 7% difference. The extended finite element method (XFEM) was found to be very effective in predicting the failure pressure. In addition, compared to the traditional Finite Element Method (FEM) which requires extremely fine meshes and is impractical in modelling a moving crack, the XFEM is computationally efficient while providing accurate predictions.

A Pressure Reduction to Prevent a Time-Delayed Failure in a Damaged Pipeline

A time-delayed failure due to stress-activated creep (cold-creep) is a failure that occurs under a constant load and with no growth due corrosion, fatigue or some other environmentally assisted time-dependent degradation mechanism. A time-delayed failure is prevented by reducing the pressure. ASME B31.4 and B31.8 recommend a 20 percent reduction, to 80 percent of the pressure at the time of damage or discovery. T/PM/P/11 Management Procedure for Inspection, assessment and repair of damaged (non-leaking) steel pipelines, an internal procedure used by National Grid, specifies a 15 percent reduction. The guidance in ASME B31.4 and B31.8, and in T/PM/P/11, is directly or indirectly based on the results of tests on the long term stability of defects conducted by the Battelle Memorial Institute and British Gas Corporation in the 1960s and 70s. The line pipe steels were Grades X52 or X60, and the full-size equivalent Charpy V-notch impact energy (where reported) did not exceed 35 J. The tests indicated that the threshold for a time-delayed failure was approximately 85–95% SAPF (straightaway-pressure-to-failure). The strength and toughness of line pipe steels has significantly increased over the decades due to developments in steel-making and processing. The question then is whether an empirical threshold based on tests on lower strength and lower toughness steels is applicable to higher strength and higher toughness steels. In the Tripartite Project, the Australian Pipelines and Gas Association (APGA), the European Pipeline Research Group (EPRG) and the Pipeline Research Council International (PRCI) collaborated in conducting full-scale six step-load-hold tests on higher strength and higher toughness steels. Companion papers present the other aspects of this multi-year project. An empirical threshold for a time-delayed failure is estimated using the results of the six step-load-hold tests. That estimate is also informed by the other published small and full-scale tests (on lower strength and lower toughness steels). The Ductile Flaw Growth Model is used to infer the effect of strength and toughness on the threshold for a time-delayed failure. A 15 percent pressure reduction, to 85 percent of the pressure at the time of damage (or of the maximum pressure that has occurred since the time of damage), is considered to be sufficient to prevent a time-delayed failure due to stress-activated creep in lower and higher toughness, in lower and higher strength, and in older and newer line pipe steels.

Composite Sleeve Repair in the North American Regulatory Environment

Composite sleeve repairs have been used in the pipeline industry for the last 25+ years. Fiberglass sleeves (e.g., Clock Spring®) were initially introduced in the market and are still being used as a proven pipeline repair method. For the last 15+ years, new composite materials have been introduced in the industry to provide a wider variety of repair options depending on the type of imperfections being repaired. Regulations in the U.S.A. and Canada share some requirements regarding design, installation, testing, and assessment of composite sleeve repairs. The U.S. Department of Transportation (DOT) through the Pipeline and Hazardous Materials Safety Administration (PHMSA) recommends the use of repair methods consistent with industry standards. The 2019 version of the Canadian CSA Z662 Oil and Gas Pipeline Standard includes requirements for testing and qualification according to the American Society of Mechanical Engineers (ASME) regulation PCC-2 or ISO/TS 24817, and requirements for conducting an engineering assessment to determine the subsequent maximum stress on the pipe sleeve. This paper compares the regulatory requirements for pipeline composite sleeve repairs in the U.S.A. and Canada; it describes some of the options for composite sleeve repair, and reviews engineering assessments of methodologies for composite sleeve repair.

Concerted, Computing-Intense Novel MFL Approach Ensuring Reliability and Reducing the Need for Dig Verification

Magnetic Flux Leakage (MFL) is a robust technology with high data coverage. Decades of continuous sizing improvement allowed for industry-accepted sizing reliability. The continuous optimization of sizing processes ensures accurate results in categorizing metal loss features. However, the identified selection of critical anomalies is not always optimal; sometimes anomalies are dug up too early or unnecessarily, this can be caused by the feature type in the field (true metal loss shape) being incorrectly identified which affects sizing and tolerance. In addition, there is the possibility for incorrectly identifying feature types causing false under-calls. Today, complex empirical formulas together with multifaceted lookup tables fed by pull tests, synthetic data, dig verifications, machine learning, artificial intelligence and last but not least human expertise translate MFL signals into metal loss assessments with high levels of success. Nevertheless, two important principal elements are limiting the possible MFL sizing optimization. One is the empirical character of the signal interpretation. The other is the implicitly induced data and result simplification. The reason to go this principal route for many years is simple: it is methodologically impossible to calculate the metal source geometry directly from the signals. In addition, the pure number of possible relevant geometries is so large that simplification is necessary and inevitable. Moreover, the second methodological reason is the ambiguity of the signal, which defines the target of metal loss sizing as the most probable solution. However, even under the best conditions, the most probable one is not necessarily the correct one. This paper describes a novel, fundamentally different approach as a basic alternative to the common MFL-analysis approach described above. A calculation process is presented, which overcomes the empirical nature of traditional approaches by using a result optimization method that relies on intense computing and avoids any simplification. Additionally, the strategy to overcome MFL ambiguity will be shown. Together with the operator, detailed blind-test examples demonstrate the enormous level of detail, repeatability and accuracy of this groundbreaking technological method with the potential to reduce tool tolerance, increase sizing accuracy, increase growth rate accuracy, and help optimize the dig program to target critical features with greater confidence.

In-Service Cracking/Leak at Bottom-Side Repaired Dent

Pipeline operators are often faced with excavating deformations caused by bottom-side indenters (e.g., rock dents). These dents are typically constrained by the rock, but during excavation, after the rock is removed, the dent is no longer constrained. Many operators have felt that it is prudent to perform in-the-ditch (ITD) non-destructive examination (NDE) techniques, such as liquid penetrant testing (LPT) and magnetic particle inspection (MPI), to determine if external cracking is present so that an appropriate repair method can be selected. Unfortunately, these external surface NDE methods do not identify the presence of internal cracking. Recent research [1], along with metallurgical analyses of cracks at bottom-side dents, demonstrates that the fatigue behavior of constrained dents is different than that of unconstrained dents, and that identifying the correct crack mechanism can be difficult. The paper discusses cracking mechanisms (e.g., stress corrosion cracking, fatigue, etc.) at bottom-side dents, ITD crack identification methods, differences between constrained and non-constrained dents, repair methods for dents, and presents a case study that uses NDE (MPI, unconventional LPT, and laser scanning) and destructive techniques (metallography, fractography, and hardness testing) to determine the metallurgical cause of a failure. The case study involves a pre-formed composite sleeve system that was used to repair dents in which correct installation procedures were followed but ultimately resulted in a delayed in-service failure. In hindsight, if ITD NDE methods were chosen based on our current knowledge of recent research, the operator may have been aware of the presence of cracking and selected a different repair method, and therefore would have likely prevented an in-service failure. This paper provides a case study to help increase awareness regarding how to properly evaluate cracking in dents. Operators should ensure that their excavation and repair procedures are updated to reflect the most current industry knowledge to help prevent a similar failure.

Improved Semi-Quantitative Reliability-Based Method for Assessment of Pipeline Dents With Stress Risers

Dents, especially those interacting with stress risers, can pose integrity threats to pipeline systems. Regulations in Canada and the United States mandate the repair of dents based on depth and interaction with stress risers, however, there have been cases in the past where dents that have passed these criteria have ended up in loss of containment. Recent industry’s recommendations regarding dent integrity analysis are predominantly based on strain, and the dent-fatigue models have been proven to be limited in their application. Additionally, these models or methodologies are generally deterministic which may not fully account for uncertainties associated with pipe properties and in-line inspection (ILI) tool measurement. Enbridge Liquid Pipelines Inc. had previously presented a framework to support system wide dent assessment with an efficient probabilistic-based calibrated semi-quantitative analysis method for dents (SQuAD), which elicits potentially injurious features from thousands of features within a system in a reasonable analysis timeframe. This paper expands on the authors’ previous work and presents several improvements that have since been made to the SQuAD model to address the limitations in the initial version of the model. The previous version of SQuAD was strain-based and did not explicitly account for pressure-cycling induced, fatigue-based failure quantitatively. An approximate circle fitting method was adopted for estimating the dent’s radii of curvature in order to calculate strains. In the improved model, filtering techniques have been employed to reduce the noise in the ILI-reported data while preserving the dent shape. Furthermore, a simplified FEA process has been developed to calculate the stresses within a dent due to pressure cycles, thus the fatigue-based Probability of Failure (PoF) of a dent can now be estimated using S-N approach. The filtered data allows for better accuracy in quantifying the radius of curvature of dents as reported by ILI tools, which are used for calculating dent strain as recommended in the updated version of ASME B31.8, Appendix R. Finally, the feasibility of applying this improved SQuAD model is discussed from an operator’s perspective. The improvements allow the enhanced SQuAD model to be used as an effective screening tool on a system-wide basis as part of a comprehensive, reliability-based dent assessment framework.

When Metals and Microbes Meet: Preventing Microbial Corrosion in Crude Oil Transmission Pipelines

Corrosion of carbon steel infrastructure in the oil and gas industry can occur via a variety of chemical, physical, and/or microbiological mechanisms. Although microbial corrosion is known to lead to infrastructure failure in many upstream and downstream operations, predicting when and how microorganisms attack metal surfaces remains a challenge. In crude oil transmission pipelines, a kind of aggressive corrosion known as under deposit corrosion (UDC) can occur, wherein mixtures of solids (sands, clays, inorganic minerals), water, oily hydrocarbons, and microorganisms form discreet, (bio)corrosive sludges on the metal surface. To prevent UDC, operators will use physical cleaning methods (e.g., pigging) combined with chemical treatments such as biocides, corrosion inhibitors, and/or biodispersants. As such, it necessary to evaluate the efficacy of these treatments in preventing UDC by monitoring the sludge characteristics and the microorganisms that are potentially involved in the corrosion process. The efficacies of a biocide, corrosion inhibitor, and biodispersant being used to prevent microbial corrosion in a crude oil transmission pipeline were evaluated. A combination of various microbiological analyses and corrosivity tests were performed using sludge samples collected during pigging operations. The results indicated that the combined treatment using inhibitor, biocide 1 and biodispersant was the most effective in preventing metal damage, and both growth-based and Next-Generation Sequencing approaches provided value towards understanding the effects of the chemical treatments. The efficacy of a different biocide (#2) could be discriminated using these test methods. The results of this study demonstrate the importance of considering and monitoring for microbial corrosion of crucial metal infrastructure in the oil and gas industry, and the value of combining multiple lines of evidence to evaluate the performance of different chemical treatment scenarios.