ASME Conference Presenter Attendance Policy and Archival Proceedings

2018;():V001T00A001. doi:10.1115/IPC2018-NS1.

This online compilation of papers from the 2018 12th International Pipeline Conference (IPC2018) represents the archival version of the Conference Proceedings. According to ASME’s conference presenter attendance policy, if a paper is not presented at the Conference by an author of the paper, the paper will not be published in the official archival Proceedings, which are registered with the Library of Congress and are submitted for abstracting and indexing. The paper also will not be published in The ASME Digital Collection and may not be cited as a published paper.

Commentary by Dr. Valentin Fuster

Pipeline and Facilities Integrity: Assessment

2018;():V001T03A001. doi:10.1115/IPC2018-78014.

Accurate defect sizing is crucial for maintaining effective pipeline safety and operation. Under growing pressure from local, national and world organizations, pipeline operators demand improved magnetic flux leakage (MFL) metal-loss sizing accuracy and classification from in-line inspection (ILI) tools.

The axial MFL field response in pipeline steel near a metal-loss defect is a very complex phenomenon. Although critical for proper sizing model development, the effects of tool speed due to product flow is very difficult to model during finite element analysis (FEA) and therefore is often overlooked. However, understanding the dynamic MFL response is crucial for proper ILI tool design and the development of accurate defect sizing algorithms.

T.D. Williamson (TDW) utilizes dynamic computer simulation modeling, paired with laboratory testing, to develop the complex parametric relationships between metal loss geometry, pipeline material and ILI tool speed. The blend of simulation and physical test results allow for TDW to iterate more quickly across multiple physics variables with simulation models, while maintaining a firm footing in reality with physical test validation. Accurately simulating magnetic field responses of metal loss under dynamic conditions produces the data necessary to identify optimal magnetizer design, including optimizing sensor spacing and placement for metal-loss defect sizing and characterization.

This paper will provide an overview of advances in the use of computer simulation modeling for predicting dynamic flux leakage field response. Besides increasing accuracy, results from this work will extend specifications beyond optimal speed ranges and provide the basis for general corrosion profilometry predictions from decomposition of the full MFL signal.

Topics: Metals , Modeling , Pipelines
Commentary by Dr. Valentin Fuster
2018;():V001T03A002. doi:10.1115/IPC2018-78135.

Due to the extensive applications of large diameter/thickness and higher pressure gas transmission pipelines, and there will be an increasing need for reliable pipeline design and failure assessment that will preclude catastrophic accident. Specifically, the actual fracture toughness needs to be determined accurately. The present work innovatively correlate the material’s fracture toughness with the crack-tip geometric constraint effect by using the crack-tip plastic zone. The significant “thickness effect” impact on pipeline steel’s fracture toughness is elucidated by the proposed out-of-plane constraint factor out. The critical loads (FCi) of three groups of thin thickness specimens at fracture are recorded by the three-point bending tests performed on the single-edge notched (SENB) specimens, corresponding fracture toughness are calculated according to the ASTM E1921-97 procedure. Moreover, finite element simulation of the SENB specimens, coupled with the applications of cohesive zone model (CZM), virtual crack closure technique (VCCT), the X70 pipeline steel’s critical energy release rate (ERR) is achieved and applied to predict the FCi of arbitrary specimen thickness while crack initiates, corresponding fracture toughness KCi are obtained and compared with the experimental ones. The present research will be beneficial for the prediction of pipeline steel’s actual fracture toughness and the retrenchment of experimental costs.

Topics: Pipelines , Failure
Commentary by Dr. Valentin Fuster
2018;():V001T03A003. doi:10.1115/IPC2018-78162.

Buried steel pipelines are subjected to mechanical stress, by internal or external forces, resulting from geo-hazards, shear or external loading, and hoop stress. These conditions are key factors that can be detrimental to the integrity of the pipeline and lead to possible failures such as: coating damage, dents, buckles, cracks, and leaks.

Identifying stress concentration regions, in difficult to pig pipelines, is challenging, especially when compared to piggable pipelines. Using the Large Standoff Magnetometry (LSM) technology, an innovative screening tool, we can identify stress concentration by performing an indirect inspection. LSM technology detects inverse magnetostriction (also known as the Villari effect) “which is the change of the magnetic susceptibility of a material when subjected to mechanical stress”. Using this technology we can detect changes in the magnetic field of the pipeline which can indicate the presence of stress on the pipe wall.

LSM technology has shown significant results when correlated with additional data. For instance, LSM technology correlated with Inline Inspection (ILI) or As-Built drawings have aided in the accurate selection of digs to mitigate failures due to stress concentration. Successfully identifying digs to mitigate stress concentration is vital as it substantially reduces cost due to potential failures and avoiding unnecessary digs.

This paper will show the benefits of an integrated approach and how the correlation of inline and aboveground pipeline integrity data ensures that threats due to stress concentrations are confidently identified and mitigated. Several case studies will be presented to show how recent advancements have helped to identify and prioritize regions with Stress Corrosion Cracking (SCC), Cracks, Unknown Buried Feature, Dents, and Buckles.

Topics: Steel , Stress , Pipelines
Commentary by Dr. Valentin Fuster
2018;():V001T03A004. doi:10.1115/IPC2018-78242.

TransCanada owns and operates more than 91,500km of natural gas pipelines in North America and since 2014 they’ve been aggressively pursuing the assessment of the unpigged portion of their system. To expand the In-Line Inspection coverage in the system TransCanada identified the need to develop a bi-directional caliper tool. This development allowed TransCanada to attain both Magnetic Flux Leakage and Caliper data while reducing the overall cost of its multi-year baseline assessment program. This paper will discuss the technical features of the bi-directional caliper tool and an overview of the model used by TransCanada which drove the development of the bi-directional caliper technology and to demonstrate the advantages of utilizing unconventional In Line Inspection technology in order to obtain MFL and Caliper data.

Commentary by Dr. Valentin Fuster
2018;():V001T03A005. doi:10.1115/IPC2018-78251.

Crack or crack-like anomaly is one of the major threats to the safety and structural integrity of oil and gas pipelines. Various assessment models have been developed and used within pipeline industry to predict the burst capacity for pipelines containing longitudinally-oriented surface cracks. These models have different level of conservatism, accuracy, and precision which significantly impacts pipeline operators’ integrity mitigation decisions such as pressure restriction, excavation, and repair, and also lead to different level of safety.

This paper compares the accuracy and precision of the most commonly used crack assessment models, i.e. Modified Ln-Sec, CorLAS, API 579 Level 2 and the recent-published PRCI MAT-8 model using in-service and hydrostatic testing failure data. A total number of 12 in-service and 63 hydrostatic test pipe ruptures due to stress corrosion cracking (SCC) with actual burst pressure, material property, and detailed crack size measurements are collected, and used to derive the probabilistic characteristics of the model errors associated with each model. Compared to the burst tests conducted in the laboratory and investigated in other previous studies, the results obtained from in-service and hydrostatic test ruptures are more representative of the real boundary conditions in pipeline operation. All the assumptions and empirical correlations associated with each model are discussed in details. The analysis result suggests that CorLAS is the most accurate model with the least uncertainty (or highest precision). Mitigation activities can be optimized without compromising safety by using the most accurate and precise model.

Commentary by Dr. Valentin Fuster
2018;():V001T03A006. doi:10.1115/IPC2018-78258.

Non-contact geomagnetic anomaly detection, as one of passive non-destructive testing (NDT) techniques, can be used to locate pipeline defects, while its accuracy is affected by random noise and detection orientation. In order to extract effective geomagnetic anomaly signals of pipeline defects, a method based on empirical mode decomposition (EMD) and magnetic gradient tensor was studied. In order to filter random noise, EMD was performed to self-adaptively decompose magnetic field signals into a series of intrinsic mode functions (IMFs), and then Hurst exponent was implemented to exclude false modes; The calculation method of magnetic gradient tensor modulus (MGTM) was proposed to obtain precise defect locations according to tensor symmetry; Subsequently, the remote pipeline defect model was built based on the magnetic dipole theory, and the relationship between detection orientation and MGTM was discussed. The experimental results showed that the proposed method could realize high precision and reliable non-contact geomagnetic localization of pipeline defects.

Topics: Tensors , Pipelines
Commentary by Dr. Valentin Fuster
2018;():V001T03A007. doi:10.1115/IPC2018-78294.

At the forefront of the effort to understand and mitigate pipeline corrosion is the prediction of corrosion growth rates. It is important to understand the effect of corrosion growth estimates on integrity management decisions. An overly conservative approach results in unnecessary digs, while removing conservatism increases the potential for a missed feature to grow to a threatening size. While approaches to feature depth growth have been well-established, there has been less investigation into the growth of feature lengths. A literature review was performed on the methodologies applicable to length growth, and their performance was compared to those that only account for depth growth using a sample analysis.

For pipelines with multiple in-line inspection (ILI) runs, feature or signal matching can be used to estimate the change in feature size. These rates can be used directly on individual features, averaged across pipe joints, or compiled into a statistical distribution. Alternatively, only one ILI measurement can be used and an assumption made on the age of the defect. These approaches are more commonly applied to depth growth but could be used to predict length growth as well.

To compare the growth methodologies, the study used historical ILI measurements of a liquid pipeline to predict feature sizes and estimated burst pressures determined at the time of the latest ILI. The number of defects correctly predicted to have an insufficient burst pressure safety factor for safe operation was compared to the number of defects that were erroneously predicted to not meet this criterion, and those that were predicted to be safe but later found to not meet the safety factor requirement. The number of erroneously flagged defects was found to vary the most between methodologies. For the assessed data set, using the joint average rate based on feature box-matching was non-conservative on average. It was also found that incorporating length growth did not significantly affect the accuracy of the burst pressure predictions.

Commentary by Dr. Valentin Fuster
2018;():V001T03A008. doi:10.1115/IPC2018-78314.

Selecting the appropriate assessment method for a pipeline system requires an understanding of the pipeline segment, the potential threats to the pipeline segment, and the various assessment methods and technologies available along with their performance capabilities. Each assessment method has its own set of advantages and disadvantages depending on the pipeline and threat being assessed.

In most cases, the assessment of a pipeline segment using one method is sufficient for the management of that threat or threats. However, for high risk pipelines (driven by likelihood, consequence, or both), this paper explores the potential benefits of leveraging one or more assessment methods by examining a number of scenarios with a specific focus on the management of cracks within a pipeline segment. It looks at the benefits of multiple assessment methods employed at the same intervals but in varying order.

Topics: Pipelines , Risk
Commentary by Dr. Valentin Fuster
2018;():V001T03A009. doi:10.1115/IPC2018-78346.

The integrity of aging assets like gas pipelines are managed by a variety of inspection and validation methods. In the particular case of gas pipelines and their susceptibility to cracking, an ultrasonic inspection methodology has been introduced over the last decade, which is based on an electromagnetic acoustic transducer (EMAT). Meanwhile, a high resolution implementation of the technology has been utilized on in-line inspection (ILI) tools from 10″ to 48″ in diameter. Williams Gas Pipelines have utilized this inspection technology successfully on several pipelines, therefore an overview will be given about this experience. Secondly a case study will be presented, in which a post hydrostatic test ILI service was used to gain additional relevant safety and integrity information from the ILI inspection and to better understand the actual capabilities of a hydrostatic test. The approach taken is in accordance with API 1163 and in consideration of API 1176. As part of this approach the performance of the ILI tool was confirmed based on a set of full scale tests conducted at the PRCI ILI test facility. The results were used to increase the statistical confidence in the capabilities of the technology.

Commentary by Dr. Valentin Fuster
2018;():V001T03A010. doi:10.1115/IPC2018-78465.

The instrumented indentation technique (IIT) is a novel method for evaluating mechanical properties such as tensile properties, toughness and residual stress by analyzing the indentation load-depth curve measured during indentation. It can be applied directly on small-scale and localized sections in industrial structures and structural components since specimen preparation is very easy and the experimental procedure is nondestructive. We introduce the principles for measuring mechanical properties with IIT: tensile properties by using a representative stress and strain approach, residual stress by analyzing the stress-free and stressed-state indentation curves, and fracture toughness of metals based on a ductile or brittle model according to the fracture behavior of the material. The experimental results from IIT were verified by comparing results from conventional methods such as uniaxial tensile testing for tensile properties, mechanical saw-cutting and hole-drilling methods for residual stress, and CTOD test for fracture toughness.

Commentary by Dr. Valentin Fuster
2018;():V001T03A011. doi:10.1115/IPC2018-78466.

Axial Strain Inline Inspection has transitioned from an experimental to commercial technology that will develop significantly as the industry requires. Axial strain tool measures total elastic longitudinal strain on a pipeline including: imposed strains due to manufacturing; construction/cold bending; backfilling; and loading associated with abnormal forces such as ground movement and settlement. The technology is based on magnetostriction, which measures the permeability and magnetic induction of ferromagnetic materials. Magnetostriction is well understood, but the application of the technology to active pipelines is relatively recent. Currently, Inertial Measurement Unit (IMU) inline inspections (ILI) effectively identify areas of localized bending strains and can be used for monitoring of pipeline movements run to run, but they do not detect axial strain associated with either tensile or compressive loading. Currently, axial strain modules are mounted behind Magnetic Flux Leakage (MFL) platforms and have either 4 or 8 probes that provide circumferential readings typically at 0.5 to 1 m intervals. Data is either considered “trend” or “calibrated” depending on whether representative test samples are available. Interpretations are provided by the vendor in the form of Axial Strain Variation which is the averaged value of a set of readings with the hoop strain component removed. Additionally, data from each probe is analyzed to establish the maximum and minimal longitudinal strains (εmax/εmin) with locations around the circumference of the pipeline. Given the potential complexity of locked-in strains, simple calculations using sinusoidal bending relationships do not apply. Therefore, curve fitting analysis is required to determine the circumferential strains. This paper includes operational learnings from the analyses of data from eight (8) Axial Strain ILI runs within variable terrain on some natural gas transmission and gathering pipelines in British Columbia by verifying strains due to known abnormal loading as well as identifying previously unknown features (landslides, in particular). In addition, sources of error, data anomalies, current limitations and potential improvements of the technology are discussed.

Topics: Inspection
Commentary by Dr. Valentin Fuster
2018;():V001T03A012. doi:10.1115/IPC2018-78488.

Improvements in in-line inspection (ILI) technology have led to an increase in the probability of detection and ability to characterize geometric features such as wrinkles, the assessment of which was introduced into CSA Z662, “Oil & Gas Pipeline Systems”, in the 2015 version.

The CSA wrinkle acceptance limits are based predominantly on fatigue assessment criteria; part of the assessment procedure is confirmation that wrinkles are free from associated cracking. In practice, this often restricts the assessment to wrinkles that have already been investigated in-field and where the absence of cracking has been confirmed by non-destructive examination (NDE).

This paper describes the assessment of a series of wrinkles that exceeded the CSA height criteria, reported by ILI within field bends in an insulated liquid pipeline. Strain-based assessment, supported by in-field investigations, was used to investigate the likelihood of associated cracking.

Utilizing the high resolution caliper ILI tool data, three-dimensional profiles of the wrinkles were generated. Previous work that compared “tool-measured” with “field-measured” profiles identified that caliper tool measurements can underestimate the true depth and profile of wrinkles, this effect is more pronounced for particularly sharp wrinkles. The wrinkle profiles were therefore adjusted based on the historical field-tool correlation. Strain profiles were then calculated using the guidance within ASME B31.8 Appendix R. It was identified that the majority of the wrinkles exceeded the 6% strain limit commonly applied to dents.

One field bend containing multiple wrinkles was subsequently excavated in order to gather detailed profile information and to inspect for cracking. Upon excavation, the wrinkles were not visually apparent, but their presence was confirmed following removal of the insulating coating. Profile information was subsequently recorded using laser scanning technology. In addition, NDE confirmed the absence of cracking, despite the fact that the majority of wrinkles were associated with strain levels that exceeded the CSA limiting value, 6%. The laser scan data were then compared with the adjusted “tool-measured” profiles. It was observed that the adjusted measurements based on the ILI tool data were conservative, and in some cases excessively so. The caliper measurements were optimized by identifying a factor that could be systematically applied to the “tool-measured” wrinkle profiles, which provided consistency with the profiles measured by the laser scan, thereby improving the accuracy of the dimensions and strain estimation of the remaining (non-excavated) wrinkles.

Finally, a S-N based fatigue assessment was performed using operational cyclic pressure data and estimates of the stress concentration factors associated with the wrinkles. The calculated fatigue lives exceeded the expected operational life of the pipeline.

Topics: Inspection , Stress
Commentary by Dr. Valentin Fuster
2018;():V001T03A013. doi:10.1115/IPC2018-78522.

Hydrostatic testing is a costly, operationally-impactful method of verifying seam integrity in low frequency electric resistance welded (LF-ERW) line pipe. Pipeline operators seek an alternative seam assessment method that provides a sufficiently conservative integrity assessment without the potentially negative impacts of hydrostatic testing. As in-line inspection (ILI) and field nondestructive evaluation (NDE) improve, pipelines that have been historically hydrostatic tested can now use ILI to ensure operational integrity. The improved ILI technology assessed in this work is an enhanced ultrasonic crack ILI tool with higher circumferential resolution and finer axial sample intervals. Magnetic ILI data from previous assessments is used to assist in anomaly identification. In addition to utilizing NDE technologies such as phased array, the emerging full matrix capture (FMC) imaging method that quantifies the size, position, and orientation of seam weld anomalies was examined. This paper discusses the work performed to ensure the efficacy of the improved ILI and NDE methods to accurately detect and quantify all anomalies that could possibly fail a hydrostatic test. An early step in the process was removing three sections of pipe from service for technology calibration and assessment. Each spool was examined with ILI technology in a pump-through facility, inspected using many NDE methods and then destructively tested. These results were communicated to ILI analysts and used to calibrate and improve the interpretation of the inspection results. Then the pipeline was inspected as part of the scheduled integrity assessment. Using field evaluation of anomalies detected by ILI, pipes were selected for removal from service to examine destructively. This paper presents the inspection and destructive testing results in addition to prognosis for the use of the ILI in lieu of hydrostatic testing for LF-ERW pipe.

Commentary by Dr. Valentin Fuster
2018;():V001T03A014. doi:10.1115/IPC2018-78547.

Due to external interference, pipelines used for onshore as well as offshore operations can present dent and gouge defects. As such defects can seriously impair facilities’ integrity and performance, it is necessary to evaluate the strains in the vicinity of these defects. The development of non-destructive approaches to assess defects severity remains an issue in the pipeline industry. In the present study, micro-hardness - strain relationships are established for three steel grades of pipeline materials: API X52 modern, API X52 vintage and API X63 vintage. The micro-hardness – strain correlations of the three pipe materials are analyzed in order to verify if they can be described by a master curve. For that purpose, Notched Tensile (NT) tests are performed in Longitudinal (L) and Transverse (T) directions for each grade in order to reach high strain values (up to 70%). The relationship proposed by Tabor was improved with the introduction of three new parameters that allow considering actual material behavior.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2018;():V001T03A015. doi:10.1115/IPC2018-78554.

The Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a Notice of Proposed Rulemaking (NPRM)1 on April 8, 2016 that is expected to have an impact on the pipeline industry’s approach to crack growth analyses. Specifically, the NPRM defines values for pipe toughness that should be used in analyzing crack anomalies that are subjected to fatigue growth for instances in which known or measured pipe toughness values are not available. Pipeline Operators conduct these types of analyses to derive remaining life values which can in turn be utilized to establish pipeline integrity reassessment intervals. Thus, the impacts of this NPRM are felt by all pipeline operators who own assets in which cracking is considered a threat. The goal of this paper is to quantify the effects of using the NPRM defined toughness values in pressure test assessments for scenarios where pipe toughness values are unavailable.

Commentary by Dr. Valentin Fuster
2018;():V001T03A016. doi:10.1115/IPC2018-78573.

Ultrasonic crack inspection services have become a standard solution for pipeline integrity programs, especially for liquid pipelines. ILI tools provide reliable and accurate data for assessment of axial and circumferential cracking defects to derive educated decisions on the integrity and maintenance of the asset. This technology inspects common media such as crude and light oils, water, diesel, benzene, or similar. Running tools in mediums used for commercial operations does not affect the throughput of the line. Crude and light oils, water, diesel, benzene etc. have relatively constant ultrasonic characteristics with varying pressures and temperatures and are very suitable for ultrasonic inspections, therefore called common media within the context of this paper.

If the medium in the pipeline does not fall within the common media, the situation changes. These media are called challenges media. Especially for liquefied natural gases (LNG) or liquefied petroleum gases (LPG) where temperature and pressure have a significant impact on the ultrasonic characteristics of speed of sound, density, and attenuation. LNGs and LPGs typically contain high amounts of propane, butane, and some other higher order alkanes. Due to the high variability of these components to external boundary conditions, inline inspections in these type of pipelines are usually performed by replacing the medium with a more feasible one, e.g. water or diesel. This causes significant impact to productivity and throughput and increases costs and efforts.

The authors will present the work performed to overcome and solve this workaround and run an ultrasonic crack inspection tool in LNG. This paper highlights the challenging aspects considered to successfully perform inline inspections in LNGs. We will present a standardized and systematic approach to overcome limitations of the technology in such media. Starting with the challenges and ideas for enhancement of the service, the paper will discuss the design of the experiment, the experiment itself, the results, and present the conclusions that resulted in the tool development and the analysis procedure. Finally, the authors will present the application of the enhanced service in a customer pipeline, including ILI preparation, execution, analysis, and in-the-ditch verifications.

The structured and systematic approach allows the inspection company to perform successful and reliable crack detection inspections in LNG lines. This includes axial and circumferential cracking threats.

Commentary by Dr. Valentin Fuster
2018;():V001T03A017. doi:10.1115/IPC2018-78594.

Mexico’s Energy Reform has opened up various interesting and unique opportunities for energy infrastructure. A CO2 pipeline project that was recently completed in southern Mexico provides a perfect example of how to breathe new life to deteriorated pipeline infrastructure — infrastructure that would have typically been written off. By coupling a unique pipeline inspection method with a novel lining system, two 28-kilometer (17 mile) pipelines were rehabilitated in record time and in a cost-effective manner. The project consisted of two 12 and 18-inch (300 and 450 millimeters) CO2 transport pipelines that had been out of service for 22 years and that are a central component for a high-profile fertilizer project. Replacing these deteriorated assets with a new transport pipeline was not an option due to time, environmental, permitting and budgetary constraints. The rehabilitated system had to offer a minimum 25-year service life required by the owner.

To put this aging infrastructure back into service, it was essential to assess the condition of the pipelines with a high level of accuracy and precision which would allow for the rehabilitation of the pipeline and installation of an interactive liner to extend the system’s serviceable life for a minimum of 25 years. The challenge, however, was that these pipelines were non-piggable by traditional methods.

By using a tethered MFL and Caliper ILI solution, the pipelines were each inspected in 13 separate sections with the level of detail necessary to assess the condition and suitability of the rehabilitation strategy selected for the project. Fast-track scheduling constraints required 24-hour data analysis turnaround of reports identifying and discriminating areas of modest and significant corrosion as well as deformations including areas of significant weld slag which could complicate the installation of the liners.

Once high-quality data was available, pinpoint repairs were possible with a combination of carbon fiber reinforcement and steel pipe replacement. Afterwards, the pipelines were internally lined with a patented process that effectively provides a double containment system. A grooved liner and the host steel pipe create an annular space that is pressurized with air and remotely monitored. The system is able to detect even a small pressure drop in the annulus that would occur in case the integrity is breached, or a pinhole develops in the steel pipe. With the grooved liner, external repairs can be conducted while the line continues to operate without interrupting CO2 service to the plant.

By applying these novel solutions, the rehabilitated pipelines will transport carbon dioxide to a revitalized fertilizer plant in a safe and efficient manner for the next 25 years.

Commentary by Dr. Valentin Fuster
2018;():V001T03A018. doi:10.1115/IPC2018-78601.

TransCanada was faced with a significant challenge to inspect a 941 km NPS 48 pipeline. The options for the inline inspection (ILI) were multiple segments which would cause an increased cost with new pigging facilities required and a delay to the ILI schedule or attempt to pig the longest natural gas pipeline section in North America. The extraordinary proposal would require a massive 48″ combination Magnetic Flux Leakage (MFL) tool to traverse a high-speed gas pipeline 941km from Burstall, Saskatchewan to Ile des Chenes, Manitoba, Canada. Given the alternative of the installation of 3 additional launcher and receiver stations and the risk to overall project schedule from extended inspection operations, TransCanada took the bold decision to perform an MFL inspection in a single pass. However, as expected, this option created a new set of challenges to guarantee first run success in one of the harshest environments for an ILI tool and in a line where the cleanliness condition was unknown. This last factor, was a critical concern as the volumes of debris that could be collected with the highly aggressive MFL tool brushes, could easily and very quickly have led to very significant debris build up during inspection that at best would likely cause degraded data leading to an unwanted re-run and at worst the possibility of a stuck pig and subsequent retrieval program. From a project perspective either occurance was considered to be mission critical — if either occurred there was no easy solution to collecting the much needed condition data of the pipeline. In July 2017, a successful VECTRA HD GEMINI inspection was completed. This paper discusses the main program risks, mitigation steps taken over and above a standard ILI run. Key considerations and actions taken relating to additional engineering and tool modifications to various components of the inspection vehicle itself will be discussed. Lastly, insight will be given into an extensive smart cleaning program developed with the ILI vendor, using a combination of mechanical cleaning associated and debris level assessment, specifically designed and tailored for the project to ensure that the pipeline was both ready for ILI and that cleaning had reached optimum for ILI so that full, high quality MFL data would be collected the first time.

Commentary by Dr. Valentin Fuster
2018;():V001T03A019. doi:10.1115/IPC2018-78642.

While In-line Inspection Magnetic Flux Leakage (MFL) tools have been used for many years to successfully manage corrosion related threats, small pinhole-sized metal-loss anomalies remain a significant concern to pipeline operators. These anomalies can grow undetected to develop leaks and cause significant consequences. The physical dimensions of these anomalies, their proximity to and/or interaction with other nearby anomalies can challenge MFL’s detection and sizing capabilities. Other factors such as tool speed, cleanliness of the line and incorrect assumptions have an impact as well. For pipeline operators to develop effective and efficient mitigation programs and to estimate risks to an asset, the underlying uncertainties in detection and sizing of pinholes need to be well understood.

By using magnetic modeling software, the MFL response of metal-loss anomalies can be determined, and the effect of a number of factors such as radial position, wall thickness, depth profile, pipe cleanliness and tool speed on MFL response and reporting accuracy can be determined. This paper investigates these factors to determine the leading causes of uncertainties involved in the detection and sizing of pinhole corrosion. The understanding of these uncertainties should lead to improvements in integrity management of pinhole for pipeline operators.

This paper first investigates the physical measurement methodology of MFL tools to understand the limitations of MFL technology. Then, comparisons of actual MFL data with field excavation results were studied, to understand the limitations of specific MFL technologies. Finally, recommendations are made on how to better use and assess MFL results.

Topics: Corrosion
Commentary by Dr. Valentin Fuster
2018;():V001T03A020. doi:10.1115/IPC2018-78655.

Large standoff magnetometry (LSM) is an emerging non-intrusive, above-ground, passive geo-magnetization flux leakage measurement technology to detect pipeline features or anomalies associated with elevated stresses. Although many promising field trial results have been reported in the past, its overall performance still has not reached sufficient consistency and reliability. This paper presents PG&E’s effort in gaining some fundamental understanding of the current LSM technology and its qualitative & quantitative performance. Specifically location accuracy of girth weld, casing end, dent and landslide damage is analyzed with references to inline inspection (ILI) and excavation data. In addition, basic physics of LSM stress quantification is examined using references of a full-scale finite element stress analysis on selected plain dents. The outcomes indicate advanced global navigation satellite system (GNSS) tool plus capability of identifying girth weld are important to achieve good anomaly location accuracy especially as LSM tends to report more indications than other inspection technologies in current practice. The LSM stress estimation and its comparison to pipe’s specified minimum yield strength (SMYS) may be only good quantitatively within magneto-elastic regime where localized stress concentration zones (SCZs) are under elastic stress loading only and without presence of residual plastic stress.

Topics: Stress , Pipelines
Commentary by Dr. Valentin Fuster
2018;():V001T03A021. doi:10.1115/IPC2018-78662.

Advances in micro-electronics and machine learning open the door to a new method of in-line pipe inspection: small free-floating smart sensors moving in the flow, capturing critical data and enabling operators to optimize pipeline performance, detect anomalies, and flag changes in pipeline condition.

The free-floating nature of these smart sensors allows for full length pipeline inspection without interrupting the operation. This makes frequent inspection possible turning it into a cost-efficient data driven solution. The alternative requires significant capital to modify the pipeline system to accommodate traditional ILI. Furthermore, traditional ILI methods are a one off costly and labor extensive measurement executed once every 5 to 10 years, where these free-floating sensors allow for high frequency, low cost measurements.

Frequent inspection allows for early detection of changes in the pipeline condition such as deposit formation and metal loss as well as timely detection and localization of leaks or similar hazardous conditions. The free-floating nature, combined with the capability to detect pipeline elements such as flanges and welds, permits accurate localization without the need for external markers.

An alternative to the free-floating deployment, the sensor device can also be attached to an off-the-shelf cleaning pig. This solution is especially suited for gas lines and allows for screening of the pipeline condition while cleaning the pipeline with limited extra effort from the operator.

The paper will demonstrate the outcome of over ten validation projects that have been conducted during the course of 2017 using an implementation of this technology in a golf ball-sized (1.5 inch diameter), robust and chemically inert integrated sensor system called Piper™. The Piper™ is equipped with a comprehensive set of sensors, consisting of a 3-axial accelerometer, gyroscope and magnetometer, a combined pressure and temperature sensor, and an advanced system for acoustic leak detection.

Topics that will be addressed include the advantage of using a free-floating integrated device, the capability of reconstructing positioning, the ability to locate and quantify leaks, and the ability to locate pipeline elements such as welds and flanges, and changes in wall thickness. In the Piper™ pig combination, the detectability of bends including the angle and radius of curvature will also be demonstrated.

Topics: Sensors , Inspection
Commentary by Dr. Valentin Fuster
2018;():V001T03A022. doi:10.1115/IPC2018-78722.

Pipeline operators rely extensively on in-line inspection (ILI) systems and other forms of non-destructive examination (NDE) as the basis for meeting the continual assessment requirements to evaluate pipeline integrity. The verification of ILI prediction accuracy involves correlating ILI data to direct inspection/assessment information using traditional NDE methods such as Ultrasonic Testing (UT), Phased Array Ultrasonic Testing (PAUT), and Electromagnetic Testing (ET). Substantial effort has been taken to establish and consider measurement tolerances for ILI systems, but not as much attention has been placed on understanding the tolerances of NDE technologies. Through studies conducted by Pipeline Research Council International, Inc. (PRCI) these NDE methods have been shown to have inconsistencies and inaccuracies in sizing and characterizing pipe wall and weld seam crack-like anomalies. Effectively managing the uncertainty in NDE measurements and selection of the appropriate technologies for anomaly verification is as important to continuous improvement in pipeline integrity management programs as ILI tool tolerance.

A primary goal for pipeline operators is to develop field-ready NDE methods for full volumetric characterization of pipeline anomalies. The inability of traditional NDE methods to accurately provide a three-dimensional (3D) image of a pipe wall features in the field leads to critical decisions being made based on imprecise tools, with layers of conservatism being included in the analysis for both NDE and ILI measurements. The lack of precision often leads to conservative and therefore excessive repair digs, unnecessary pipe replacements, and in some cases hydrostatic pressure testing of the pipeline to verify the system integrity.

This paper presents the results of a research project that includes comparative analysis of seam anomaly characterization data from an ILI system, traditional NDE inspection, Computed Tomography (CT), and metallurgical results. CT is the only current method that has shown consistency in providing accurate 3D profile measurements of an anomaly comparable to destructive testing and direct measurement of anomaly characteristics. The CT results presented in this paper represent the potential for field ready inspection capabilities as the data were obtained from full circumference measurement of pipe samples rather than plate samples, which have typically been studied in prior analysis of CT methods. Obtaining accurate data on anomaly dimensions is critical to understanding and improving the application of ILI and NDE data to drive integrity decisions. Improved results in the field will lead to improved decision-making to protect the environment and public safety.

Commentary by Dr. Valentin Fuster
2018;():V001T03A023. doi:10.1115/IPC2018-78750.

In the last 10 years, technical and economical efforts have been made to improve pipeline integrity management. Those efforts focus on developing “searching tools”, capable of identifying pipe mechanical damage due to slow landslides.

We identified two main tools: geohazard mapping and inline inspection (OCP is using caliper with inertial navigation system INS). The INS system generates a substantial amount of information about pipe’s geometry and deformation, reported as pitch, yaw and distance cover for each run. Since the caliper has been used for years, the pipeline’s path of evolution over the years is already available.

The INS data was merged with pipeline field inspections to develop an assessment tool based on Machine Learning Technology.

This tool was applied to the complete path of the pipeline, analyzing each girth weld, thus obtaining a so called “criticality level” for each weld. Two models were evaluated, which differ on the size of the vicinity considered for each girth weld: 250m and 500m. The highest precision model was found with 250m, which already has allowed improvements in field inspections.

This paper will describe this technique, capable of improving OCP’s pipeline integrity management.

Commentary by Dr. Valentin Fuster
2018;():V001T03A024. doi:10.1115/IPC2018-78762.

Environmentally assisted cracking (EAC), more specifically, stress corrosion cracking (SCC) has been a pipeline integrity concern since the 1960s. However, there were not many options for pipeline operators to effectively manage this threat on gas and liquid pipelines. SCC and other crack type defects have become a threat which is more widely understood and can be appropriately managed through in-line inspection (ILI). The two primary technologies for crack detection, developed in the 1990s and early 2000s respectively, are ultrasonic (UT) and electromagnetic acoustic transducer (EMAT). Although EMAT was originally developed to find SCC on gas pipelines, it has proven equally valuable for crack inspections on liquid pipelines.

A case study with a gas and natural gas liquid (NGL) operator, ONEOK Inc. (ONEOK) demonstrates the effectiveness of using EMAT ILI to evaluate the potential threat of crack and crack-like defects on a 48 mile (77.2 km), liquid butane pipeline. By utilizing both 10-inch (254 mm) multiple datasets (MDS) technology and 10-inch (254 mm) EMAT ILI tools, ONEOK proved the effectiveness of ILI to identify critical and sub-critical crack and crack-like defects on their pipeline.

This paper will present on the findings from the two technologies and illustrate the approaches taken by the operator to mitigate crack type defects on this pipeline.

Commentary by Dr. Valentin Fuster

Pipeline and Facilities Integrity: Evaluation and Repair

2018;():V001T03A025. doi:10.1115/IPC2018-78018.

It is generally accepted that hot induction bending (HIB) results in a decrease in strength and an increase in fracture toughness in bend area, heat affected zone (HAZ) and weld metal (WM). As the result, Post bend heat treatment (PBHT) is not considered to be a requirement and could be waived for saving money and time. This research work raises the concern that factual verification of proper microstructure and no localized brittle zone is vitally necessary prior to waving PBHT.

Evaluation of the steel microstructure and mechanical properties as the result of various pipe chemistries during pipe bending has been verified in this experimental work. It is emphasized that knowledge and control of prior steel pipe chemistry, control of temperature, cooling rate and bending speed assures the reliability and repeatability of induction bends, especially in critical environments such as low temperature application.

In the present work, qualitative and quantitative microstructural analysis, hardness and impact test performed and evaluated on samples from X70 line pipe with 3 different steel chemistries. The samples prepared from different locations on body, weld and HAZ in the as received and as bent condition. It was found that the final microstructure and mechanical properties in the as bent condition is dependent on the chemistry, steel cleanliness and microstructural uniformity. It was observed that small localized brittle zone with traces of upper Bainite and Martensite islands could be transformed in the microstructure with rich chemistry containing non-homogenous central segregation. It is concluded that factual verification of proper microstructure with no localized hard zone is required prior to waving PBHT.

Commentary by Dr. Valentin Fuster
2018;():V001T03A026. doi:10.1115/IPC2018-78118.

This paper establishes a dynamic Bayesian network to model the growth of corrosion defects on energy pipelines. The integrated model characterizes the growth of defect depth by a homogeneous gamma process and considers the biases and random errors associated with the in-line inspection (ILI) tools. The distributions of the mean value and coefficient of variation of the annual growth of defect depth are learned from multiple ILI data using the parameter learning technique of Bayesian networks. With the same technique, the distributions of the biases and standard deviation of random errors associated with ILI tools are learned from ILI data and their corresponding field measurements. An example with real corrosion management data is used to illustrate the process of developing the model structure, learning model parameters and predicting the corrosion growth and time-dependent failure probability. The results indicate that the model can in general predict the growth of corrosion defects with reasonable accuracy and the ILI-reported and field-measured depth can be used to update the time-dependent failure probability in a near-real-time manner. In comparison with existing growth models, the graphical feature of Bayesian networks makes it more intuitive and transparent to users. The employment of parameter learning provides a semi-automated and convenient approach to elicit the probabilistic information from ILI and field measurement data. The above advantages will facilitate the application of the model in the practice of corrosion management in pipeline industry.

Commentary by Dr. Valentin Fuster
2018;():V001T03A027. doi:10.1115/IPC2018-78189.

Imaging techniques using full matrix capture (FMC) ultrasonic NDE are well suited for in-service examination of electric resistance welded (ERW) pipe seams. We have been involved in developing an imagine technique since 2013 and presented results from Phase I at IPC in 2016 showing the system capable of detecting seam weld and SCC flaws and determining their orientation. The advantages over other methods such as phased array (PA) is the ability to image the flaw surface in addition to the flaw tip and corners where the flaw intersects the pipeline surface. This improves the ability to determine flaw orientation for discrimination of different types or crack-like features. The system produces UT images by overlaying multiple modes using reflections off the ID and OD pipe surface for ultrasonic illumination of the weld area from different directions. Using multiple modes produces a reflection off features regardless of flaw orientation from at least one of the modes. A complementary mode can then be used to size each feature by detecting the tips or ends of the feature from lower amplitude diffraction signals. Phase I used a model which assumed a cylindrical pipe shape. Real world use of this technique found limitations when pipe deviated from the assumed cylindrical shape such as severe offset plate edges, flat spots which can be the result of poor crimping adjacent the seam weld, or thickening of the seam caused by post weld heat treatment.

In Phase II a need for reduced sizing error led to improved calibration and more advanced processing. To compensate for the non-perfect nature of real pipe, a new adaptive IWEX technique was developed to improve focusing and alignment of the various modes using the actual geometry to construct better focusing laws. First the OD and ID surfaces are imaged and the resulting surfaces are used to construct focusing laws which adapt to changes in the OD and ID surfaces. Results are better aligned UT images with the ability to image complex flaws with changes in orientation, and the ability to discriminate complex flaws from multiple small flaws in the pipe. Results show improvements in pipe with the greatest improvements in pipe with the largest deviations from a cylindrical shape.

Commentary by Dr. Valentin Fuster
2018;():V001T03A028. doi:10.1115/IPC2018-78284.

Corrosion anomalies which reduce the strength of the pipeline must be mitigated appropriately. When corrosion defects have varying morphologies it is not always simple to determine the point at which the corrosion region becomes a safety concern, particularly for complex corrosion areas where multiple corrosion anomalies may interact with one another. Therefore, understanding how various anomalies may interact is important to determining the overall remaining strength of a pipeline under pressure. Many criteria for this spacing and how to apply the rules are recommended in the literature and have been studied either as the focus or periphery by several more, but no single criterion is provided as regulation. The task is left to the pipeline operator to choose the interaction rule for what is defined as ‘closely spaced corrosion.’ The method by which the failure pressure is calculated should be considered as varying levels of conservatism are inherent in these assessments.

Recommendations for interaction guidelines have been determined by either empirical or analytical approaches. The empirical approaches may be limited when an insufficient number and variety of pipes can be burst tested. Many analytical approaches are based upon relationships of remaining wall and simple corrosion morphologies which may not be applicable to real world corrosion. The source of the corrosion anomaly data is an important variable when selecting and applying interaction rules. In-line inspections (ILI) are the most common methods by which to obtain corrosion anomaly data, but each technology has an inherent measurement error and bias which should be considered. This paper will go into detail on each of the items discussed, present the current state of research into this subject in the industry, and will present a general recommendation for selection of an interaction criterion for corrosion features reported by ILI.

Topics: Corrosion
Commentary by Dr. Valentin Fuster
2018;():V001T03A029. doi:10.1115/IPC2018-78316.

In accidental scenarios on subsea pipeline systems, like the collision of two adjacent subsea risers, accidental loads are commonly considered as stationary loads; stationary loads refer to loads that act only normal to the pipe at one location. Hence, the potential considerable effects of moving (sliding) accidental loads are neglected; the term moving load refers to the location with respect to time. Accordingly, recent works for ship hull structures show that the structural resistance mobilized against the moving loads is significantly lower than against the stationary loads of similar magnitude; when the loads incite plastic damage. As such, it is reasonable to study the effects of lateral motion of accidental loads on the response of subsea pipelines. This paper implements finite element analyses to investigate the load carrying capacity of a cylindrical shell subject to moving loads; LS-Dyna software package with explicit time-integration scheme is employed in numerical simulations; only crumpling deformation of the cylinders are studied. This research demonstrates that the capacity of a cylindrical shell subject to a moving load, causing plastic damage, is considerably less than its capacity under a stationary load of similar magnitude.

Commentary by Dr. Valentin Fuster
2018;():V001T03A030. doi:10.1115/IPC2018-78338.

The failure of a corroded pipe is generally controlled by the depth and the longitudinal extent of the metal loss area subjected to hoop stress. However, the failure of metal loss due to its circumferential extent under longitudinal stress is possible if significant longitudinal stress exists in the pipe or the metal loss has considerable circumferential extent and depth. If such circumstances exist, it is prudent to conduct a complementary analysis of pipe integrity to assess the potential for circumferential as well longitudinal failure. Most existing approaches for assessing circumferential metal loss, such as Miller’s equations, were derived by assuming the metal loss to be centered at the extreme stress position around the pipe circumference, i.e., the center of the metal loss is centered at the location of the maximum bending stress in the pipe. The assessment may be over-conservative if the metal loss area deviates from the extreme position related to the bending plane. Described in this paper is a new approach to assess the potential for circumferential failure of metal loss centered at an arbitrary angle from the location of maximum bending stress. The approach results in the same failure stress as existing models when the metal loss is centered at the location of maximum bending stress. The failure stress increases when the metal loss deviates from the location of maximum bending stress and reaches the maximum value when the metal loss is centered at the neutral axis. The equations of the model developed in this paper can be easily implemented into a spreadsheet tool for routine integrity assessment. Other considerations related to the assessment of circumferential metal loss are also discussed, including non-uniform corrosion, negligible corrosion, and the interaction of multiple corrosion areas in the same pipe cross section. The model developed in this paper can also be used to determine the cutoff line for plastic collapse in a failure assessment diagram (FAD) based approach for assessing circumferential cracks, such as API 1104 Appendix A and API 579.

Commentary by Dr. Valentin Fuster
2018;():V001T03A031. doi:10.1115/IPC2018-78521.

This paper describes a novel technique for the detection of cracks in pipelines. The proposed in-line inspection technique has the ability to detect crack features at random angles in the pipeline, such as axial, circumferential, and any angle in between. This ability is novel to the current ILI technology offering and will also add value by detecting cracks in deformed pipes (i.e. in dents), and cracks associated with the girth weld (mid weld cracks, rapid cooling cracks and cracks parallel to the weld). Furthermore, the technology is suitable for detection of cracks in spiral welded pipes, both parallel to the spiral weld as well as perpendicular to the weld. Integrity issues around most features described above are not addressed with ILI tools, often forcing operators to perform hydrostatic tests to ensure pipeline safety.

The technology described here is based on the use of wideband ultrasound inline inspection tools that are already in operation. They are designed for the inspection of structures operating in challenging environments such as offshore pipelines. Adjustments to the front-end analog system and data collection from a grid of transducers allow the tools to detect cracks in any orientation in the line. Description of changes to the test set-up are presented as well as the theoretical background behind crack detection.

Historical development of the technology will be presented, such as early laboratory testing and proof of concept. The proof of concept data will be compared to the theoretical predictions. A detailed set of results are presented. These are from tests that were performed on samples sourced from North America and Europe which contain SCC features. Results from ongoing testing will be presented, which involved large-scale testing on SCC features in gas-filled pipe spools.

Commentary by Dr. Valentin Fuster
2018;():V001T03A032. doi:10.1115/IPC2018-78538.

In-ditch/in-service characterization of pipelines using nondestructive evaluation (NDE) can provide valuable data for confirming operating pressure and qualifying pipelines for transporting natural gas of different quality or gas mixture, as well as for determining repair criteria for integrity management programs. This is especially relevant for vintage pipelines that may not have material test reports (MTR) available, and for aging infrastructure that have been subjected to suspected or unknown integrity threats. However, measurement of material fracture toughness currently requires the removal of large samples for laboratory testing, such as compact tension (CT) fracture testing or Charpy impact testing. The present work introduces a new concept, the Nondestructive Toughness Tester (NDTT), that provides a NDE solution for measuring the fracture toughness of pipeline steel in a superficial layer of material (∼0.005 inches). The NDTT uses a specially designed wedge-shaped stylus to generate a Mode I tensile loading that results in a ductile fracture response. NDTT tests are performed in multiple orientations on 8 different pipeline steel samples covering 3 different grades to compare the NDTT material response with the fracture toughness measurements from laboratory CT specimens. Analysis of these results indicate that the height of a fractured ligament that remains on the sample surface after NDTT testing exhibits a linear relationship with traditional CT J-integral measurements normalized by its yield strength. This type of behavior is analogous to the crack-tip-opening-displacement (CTOD) calculated through elastic-plastic fracture mechanics. Tests conducted on the pipe outer diameter and in the longitudinal direction near the pipe mid-wall indicate that the NDTT can measure differences in fracture toughness for different crack orientations. Furthermore, the results show that outer diameter tests provide a conservative estimate of the overall steel fracture toughness. These observations indicate that the NDTT is a viable method for assessing toughness properties of steel materials. Additional research is required to further refine the implementation of the NDTT concept and understand the relationship with laboratory test results on pipe cutouts, but the progress is already a significant step towards obtaining additional material toughness data for integrity management.

Commentary by Dr. Valentin Fuster
2018;():V001T03A033. doi:10.1115/IPC2018-78577.

In-Line inspection (ILI) tools consisting of combined sensor technologies provide a unique opportunity for operators to understand the conditions of pipelines. There is also an additional opportunity to contrast and validate individual sensing techniques against each other when their functionalities and purposes overlap.

By using multi-technologies ILI measurements for strain, a pipeline operator can gain further insight into the pipeline strain behavior at any point along the length of the inspection. This paper establishes the relationship between ILI axial strain measurement tool data and conventional geometric strain data obtained from inertial measurement unit (IMU) based on data collected during in-service inspection of a 12″ liquid pipeline.

Within any pipeline section, the tool configuration with circumferentially spaced strain sensors allows the use of appropriate analysis techniques to decompose the longitudinal strain into its primary components (axial, bending and out of roundness).

The axial strain measurement tool sensing system provides an indirect measurement of bending strain that can be compared to the geometric measurement of bending strain determined from the pipeline trajectory as determined from the IMU analysis. Flexural bending strain resulting from horizontal directional drilling (HDD) is investigated in this paper. Convergences and divergences between the measurement techniques are presented.

Data available from different strain technologies mounted on ILI tools offers an opportunity to conduct a comparative study and to provide a better understanding of a pipeline’s strain condition. This paper will present the framework for understanding the different strain measurement technologies and an investigation into the pipeline prior strain history (effects from fabrication, hydrostatic testing and external loads) and their corresponding impact on the material state at the time of inspection.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2018;():V001T03A034. doi:10.1115/IPC2018-78636.

Pipeline in-line-inspections (ILI) are used to assess and track the integrity of pipelines, aiding in identifying a variety of features such as: metal loss, dents, out-of-roundness, cracks, etc. The presence of these features can negatively affect the operation, integrity, and remaining life of a pipeline. Proper interpretation of the impacts these features may have on a pipeline are crucial to maintaining the integrity of a pipeline. Several codes and publications exist to assess the severity of these features under known operating conditions, either through empirical formulations or more detailed analysis, in order to aid the operator in determining a corrective action plan. These empirical formulations are generally applicable to assess a singular defect but require a more detailed assessment to evaluate combined defects (i.e. dent in a bend). These detailed assessments typically require a higher level numerical simulation, such as Finite Element Analysis (FEA). This detailed FEA can be quite costly and time consuming to evaluate each set of combined features in a given ILI run. Thus, engineering judgement is critical in determining a worst-case scenario of a given feature set in order to prioritize assessment and corrective action.

This study aims to assess dent features (many associated with metal loss) occurring in a pipe bend to determine a worst-case scenario for prioritization of a given feature listing. FEA was used to simulate a field bend of a given radius and angle in order to account for residual stresses in the pipe bend. A rigid indenter was used to form a dent of the approximate length, width, and depth from the ILI data. Separate models were evaluated considering the dent occurring in the intrados, extrados, and neutral axis of the pipe bend to evaluate the worst-case scenario for further assessment. The resulting stresses in the pipe bend-dent geometry, under proper loading were compared to the same dent scenario in a straight pipe segment to develop a stress concentration factor (SCF). This SCF was used in the API 579-1/ASME FFS-1 Fitness for Service (API 579) [1] methodology to determine the impact on the remaining life of the combined features.

Commentary by Dr. Valentin Fuster
2018;():V001T03A035. doi:10.1115/IPC2018-78704.

In the pipeline industry, a widely accepted methodology for integrity crack management involves running ultrasonic In-Line Inspection (ILI) technologies. After an ILI tool run is completed, the performance of the tool is typically validated by excavating the pipeline and conducting in-the-ditch investigations. Ultrasonic Non-Destructive Evaluation (NDE) techniques are used in the field to characterize and measure crack-like features. These in-the-ditch measurements are compared back to ILI results in order to validate tool performance and drive continuous technology improvements. Since validation of the ILI tool relies on NDE measurements, acquiring accurate and representative data in the field is a critical step in this integrity crack management approach. Achieving an accurate field inspection comes with its challenges, some of which relate to complex long seam weld conditions present in older vintage pipelines including: weld misalignment, weld trim issues, and dense populations of manufacturing anomalies. In order to better understand the challenges associated with complex long seam weld conditions, an evaluation and comparison of the performance of NDE technologies currently available was conducted.

In this study, a portion of a Canadian pipeline with complex long seam weld conditions was cut-out and removed from service. Multiple NDE crack inspection technologies and methods from three different vendors were used to assess the condition of the long seam weld. Conventional Ultrasonic Testing (UT), Phased Array Ultrasonic Testing (PAUT), Time of Flight Diffraction (TOFD), and variations of Full Matrix Capture Ultrasonic Testing (FMCUT) were used to assess the long seam weld and their results were compared. The performance of all NDE technologies is baselined by comparing them with destructive examination of sections of the long seam weld. The newer NDE assessment methodologies were shown to be consistently more accurate in characterizing long seam features.

Commentary by Dr. Valentin Fuster

Pipeline and Facilities Integrity: Facility Integrity

2018;():V001T03A036. doi:10.1115/IPC2018-78176.

Vibration related issues can be a challenging part of pipeline integrity management, because they are frequently difficult to predict, diagnose, and remediate. Often, vibrational issues are not even considered until pipe movement is observed or failures occur. A wide variety of vibration problems are associated with pumps and compressors, and piping at pumping stations are often susceptible to vibration related issues. Excessive piping vibration may result in leaks at connections and flanges, and fatigue failures can occur, leading to leaks that present safety and environmental concerns.

The energy responsible for pipeline vibration is usually provided by rotating or reciprocating pumping equipment, and is transmitted to the piping either by direct mechanical contact, pressure pulsations, or turbulence in the pumped fluid. Vibration problems usually occur when a mechanical natural frequency of the piping system, an acoustic natural frequency of the contained fluid, or both, is excited by the driving force.

In this paper, a brief overview of vibration issues that occur in pipeline facilities is presented. Next, a selection of case studies is provided to illustrate some of the types of vibration induced failures that have been observed at pipeline facilities, and how they were addressed and resolved. These examples provide some insight into how to potentially avoid such issues, or if they occur, how to identify and mitigate them.

Commentary by Dr. Valentin Fuster
2018;():V001T03A037. doi:10.1115/IPC2018-78224.

Throughout North America there are many crude oil storage tank facilities — also called terminals — serving as hubs, transfer points and storage. Safety precautions such as pre-service integrity testing, cathodic protection, primary and secondary containment measures, and grounding techniques have been utilized to assure safety as a top priority. These tanks undergo an in-service API 653 external inspection at least every 5 years, and are taken out of service to undergo an API 653 internal/external inspection at least every 30 years [1], [2], [3]. For these aboveground storage tanks, the bottom plate is the most vulnerable area to corrosion [4] and is also the most challenge area to inspect visually. Both sides (product-side and soil-side) of the tank bottom plate are prone to high rates of corrosion in comparison to other components such as the roof and shell [5]. Corrosion generally starts with coating defects such as air or water ingress to underling layers and exposing the steel to uncontrolled environmental factors.

Internal inspection can be performed using ultrasonic measures to calculate the sheet thickness, however, external inspection is impossible without having access to the tank bottom. This paper will introduce a novel inspection method for external monitoring of the surface of the tank bottom plate in real-time. The proposed technique proactively approaches the problem by predicting the corrosion before it occurs. In this technique an array of microwave-based sensors operating at ISM band (2.57 GHz) are introduced for defect prediction. The array is composed of equally-distant and identical microwave spiral ring resonators (SRR) [6] that are electromagnetically coupled to a transmission line. All resonances created by the array elements merge in one band-stop frequency response with very high isolation. Once the sensors’ environment is altered by any defects such as an air breach, liquid ingress [7] or corrosion initiated, a resonance shift will occur indicating coating risks. To prove the concept, an initial prototype for small tanks of 3–5 ft. diameter is investigated. Two-port system data illustrates that in case of a coating defect, the frequency profile accordingly changes and provides a signature. The obtained data is used to predict possible corrosion in timely manner. The proposed sensor array enables external monitoring of tank bottoms surface where visual inspection is impossible while the tank is in-service.

Commentary by Dr. Valentin Fuster
2018;():V001T03A038. doi:10.1115/IPC2018-78379.

Integrity reliability science plays a major role in the integrity management of transmission piping, which is piping that traverses long distances across the continent, at high pressures, and can experience high pressure cycling. This science can be applied to non-transmission piping such as lateral piping, which traverses between a transmission line and a facility, or between two facilities, at lower pressures and with lower pressure cycling. Laterals are susceptible to the same threats as transmission lines (internal corrosion, external corrosion, cracking, geotechnical hazards, etc.). However, due to their operation, laterals are only highly susceptible to internal and external corrosion. While site specific conditions may result in a high susceptibility of a geotechnical hazard, this threat is outside of the scope of this paper. On transmission piping, corrosion is generally managed with In-Line Inspection (ILI), Non-Destructive Examination (NDE), and corresponding repairs (e.g. sleeving) to assess and mitigate. With laterals, there can be limited ILI and NDE data. As such, the data used in the quantitative reliability framework for these threats is not available and this creates a gap in the process. This paper addresses this gap through the application of semi-quantitative reliability analysis for internal and external corrosion on laterals along with a risk-based integrity decision making framework. The proposed approach is designed to enable pipeline and facility operators to make effective decisions around lateral integrity programs given the available data, and to better understand the limitations of integrity decision making. Moreover, the paper expands the discussion around the difference between risk-informed and risk-based integrity decision making in order to provide a guideline for optimal and safe integrity management programs considering different criteria. Case studies that include limited or no ILI or NDE information are used to demonstrate the application of semi-quantitative and quantitative reliability assessment of laterals along with the exploration of challenges in calibrating the two assessment methods to provide an example of how reliability science can be applied to laterals and how this can be used in effective decision making given such limitations.

Topics: Pipes , Decision making , Risk
Commentary by Dr. Valentin Fuster
2018;():V001T03A039. doi:10.1115/IPC2018-78421.

This paper presents the development and testing of an Electro-Magnetic Acoustic Transducer (EMAT) sensor prototype to detect and quantify longitudinal cracks in small diameter and difficult to inspect or unpiggable gas pipelines. The development of the system was a collaborative and jointly-funded work between Quest Integrated, Gas Technology Institute, Operations Technology Development, and US DOT, Pipeline Hazardous Material Safety Admin (PHMSA).

The initial focus for the project was to inspect 8-inch (200 mm) diameter pipes with robotic or tethered towing, with the eventual goal of a free-swimming tool. A bench scale lab prototype has been successfully completed and tested in Phase 1 of the project in 2016. The prototype demonstrated the basic approach of a EMAT tool for crack detection and sizing that could be packaged into a single module, had reasonable flaw depth sensitivity, was bidirectional, and could negotiate a 1.5 D bend.

Phase 2 focused on identifying and solving additional implementation issues, developing a more hardened tool for field pull testing, improving flaw sizing, and the necessary internal electronics and processing algorithms. The prototype recently developed in Phase 2 was tested in an extended length of 8-inch diameter steel pipe with pre-set and controlled longitudinal cracks. The results demonstrated the applicability of the integrated prototype in locating and sizing multiple flaws in the axial direction.

This paper discusses the EMAT sensor development and results of the laboratory testing program.

Commentary by Dr. Valentin Fuster
2018;():V001T03A040. doi:10.1115/IPC2018-78425.

This work proposes an assessment procedure for the determination of the remaining strength in pressure vessels with pitting type metal loss, trough the developed of integrity diagrams according to the pitting density, pitting depths and the internal pressure of the component using Finite Element Analysis simulations.

The simulations results indicate that the pitting density and depths according to the Gumbel Max Distribution, are the main factors that determine the mechanical integrity of the component; where 45% damaged area by pitting generates a stress concentration that multiplies at least ten times the stress compared with components without defects, since these variables present a synergistic behavior in the stress state.

The proposed assessment procedure facilitates the evaluation of the components that present pitting corrosion damage, due to the geometric and population effect of the pitting is considered in the finite element simulation.

Commentary by Dr. Valentin Fuster
2018;():V001T03A041. doi:10.1115/IPC2018-78544.

A comprehensive metallurgical investigation of multiple, externally-initiated, in-service leaks on an above-ground, oil emulsion (multiphase) pipeline concluded that the crack-initiating mechanism was stress corrosion cracking (SCC). A technical root cause analysis (RCA) was performed, utilizing faults trees, to evaluate the potential contributors to the SCC from the time of construction through the identification of the first in-service leak. This paper outlines the RCA findings and current understating of the primary contributors given that SCC on above-ground, insulated carbon steel pipelines has not previously been reported.

Commentary by Dr. Valentin Fuster

Pipeline and Facilities Integrity: Integrity Management Plan (IMP) Administration

2018;():V001T03A042. doi:10.1115/IPC2018-78116.

The regional gas transmission network of Gasunie Transport Services in the Netherlands consists of roughly 3000 km pipelines, 3000 valve stations, 75 pressure regulating and metering stations and 1100 gas receiving stations. Because the majority of these stations was built in the period 1960–1980, questions have arisen regarding their remaining technical lifetime and which measures should be taken to comply with future safety and transport standards. In the Gasunie Network Improvement Program (GNIP), these stations are replaced completely, prioritized on their expected condition.

By supplementing the GNIP Verification Project (GVP) to the GNIP, a “Plan-Do-Check-Act” circle was introduced to identify improvements from executing the GNIP. In the GVP, lifetime critical parts of the replaced stations are inspected by specialized companies, in-situ as well as in their laboratories, to assess their actual condition. The lessons learned and results from the GVP have led to adjustments in the replacement program in terms of both scope and pace.

This paper gives a general overview of the GNIP and the GVP. The results of the GVP are then presented with a focus on the condition of gas delivery stations, particularly the condition of components that are not or poorly accessible during normal operation, such as headers and wall crossings. The actions taken by Gasunie to adjust the GNIP based on the GVP outcomes will be discussed.

Commentary by Dr. Valentin Fuster
2018;():V001T03A043. doi:10.1115/IPC2018-78130.

In this paper, three-dimensional finite element models are developed to simulate full-scale burst tests of corroded pipes containing multiple naturally occurring corrosion anomalies. Both the von Mises and Tresca yield criteria and associated flow rules are employed in finite element analysis (FEA). For the Tresca criterion, the corresponding constitutive model subroutine is developed and incorporated in the FEA. The accuracy of FEA is investigated by comparing the burst pressures observed in the tests and corresponding burst pressures predicted using FEA. The implications of using the von Mises and Tresca criteria for the accuracy of the predicted burst pressure are investigated. Sensitivity analyses are also carried out to investigate the impact on the predicted burst pressure due to the mesh density in the corroded region, characterization of the geometry of the corrosion cluster and different types of element (e.g. solid and shell elements) used in FEA. The results suggest that the Tresca criterion always underestimates the burst pressure and the von Mises yield criterion predicts the burst pressure accurately.

This study demonstrates the feasibility of using high-fidelity FEA and the Tresca yield criterion to simulate full-scale burst tests of corroded pipes and therefore establish a large database of burst pressure capacities of corroded pipes that can be used to develop an accurate, practical burst pressure capacity model amenable to the pipeline integrity management practice.

Commentary by Dr. Valentin Fuster
2018;():V001T03A044. doi:10.1115/IPC2018-78132.

Hydrostatic pressure testing is the most widely accepted approach to verify the integrity of assets used for the transportation of natural gas. It is required by Federal Regulations 49 CFR §192 to substantiate the intended maximum allowable operating pressure (MAOP) of new gas transmission pipelines. The Pipeline and Hazardous Materials Safety Administration (PHMSA) Notice of Proposed Rulemaking (NPRM) with Docket No. PHMSA-2011-0023 [1], proposes an additional requirement for MAOP verification of existing pipelines that: i) do not have reliable, traceable, verifiable, or complete records of a pressure test; or ii) were grandfathered into present service via 49 CFR §192.619(c). To meet this requirement, the NPRM proposes that an Engineering Critical Assessment (ECA) can be considered as an alternative to pressure testing if the operator establishes and develops an inline inspection (ILI) program. The ECA must analyze cracks or crack-like defects remaining or that could remain in the pipe, and must perform both predicted failure pressure (PFP) and crack growth calculations using established fracture mechanics techniques. For assets that cannot be assessed by ILI, however, the implementation of an ECA is hindered by the lack of defect size information.

This work documents a statistical approach to determine the most probable PFP and remaining life for assets that cannot be assessed by ILI. The first step is to infer a distribution of initial defect size accumulated through multiple ILI and in-ditch programs. The initial defect size distribution is established according to the as-identified seam type, e.g. low-frequency electric resistance weld (LF-ERW), high-frequency electric resistance weld (HF-ERW), flash weld (FW), single submerged arc weld (SSAW), or seamless (SMLS). The second step is to perform fracture mechanics assessment to generate a probabilistic distribution of PFPs for the asset. In conjunction with the defect size distribution, inputs into the calculation also include the variations of mechanical strength and toughness properties informed by the operator’s materials verification program. Corresponding to a target reliability level, a nominal PFP is selected through its statistical distribution. Subsequently applying the appropriate class location factor to the nominal PFP gives the operator a basis to verify their current MAOP. The last step is to perform probabilistic fatigue life calculations to derive the remaining life distribution, which drives reassessment intervals and integrity management decisions for the asset. This paper will present some case studies as a demonstration of the methodology developed and details of calculation and establishment of database.

Commentary by Dr. Valentin Fuster
2018;():V001T03A045. doi:10.1115/IPC2018-78158.

As part of a major pipeline expansion, two deactivated 24″ diameter pipeline segments with a combined length of 192 kilometres will be assessed and upgraded to operational status. These line segments include a 42 kilometre section within the North Thompson valley of British Columbia, and a 150 kilometre segment through the Rocky Mountains of Alberta and British Columbia.

Reactivating the lines to operational condition is a multi-staged process, which will be partially guided by a National Energy Board Condition requiring the issuance of a certificate from an independent certifying body that the system is fit for service and meets all applicable requirements of CSA Z662, Oil and Gas Pipeline Systems. This certificate must be unconditional and remain in effect for a period of 5 years.

The need for unconditional certification of fitness for service drives the need for a comprehensive assessment of the pipeline condition using a broad slate of inline inspection technologies. Tools were selected for the assessment of deformations, metal loss, manufacturing anomalies and cracking. The lines were maintained with a low pressure nitrogen blanket for between 9 and 13 years prior to the start of the reactivation work and it was therefore not possible to run the tools using service fluid.

Several options were considered for propelling the inline inspection tools including nitrogen, compressed air and water slugs in compressed nitrogen or air. Each method has advantages and disadvantages and modelling was carried out to simulate the transport of the tools through each segment. The modelling needed to account for pipe elevation changes, wall thickness changes, valves, tool drive friction, acceptable tool velocity, and the pressure of the drive medium in the pipeline.

The modelling focused on the following constraints:

i. Ensure ILI data quality

ii. Ensure safety considering the potential presence of defects in the lines

iii. Minimize risk

iv. Minimize overall cost

These constraints guided a flow modelling/feasibility study for inspecting the lines with the 4 tools. The objective of the study was to determine the optimum configuration of propellant, inspection tools, and line segmentation while ensuring a safe, economical operation resulting in optimal data collection.

The paper will provide some background on the line segments being reactivated and pressure limitations that were adopted for ILI runs. The majority of the content will focus on the determination of tool drive technique, how simulation occurred and how the actual execution of the runs compared. Details regarding the challenges and troubleshooting required to successfully complete the integrity surveys will also be discussed in depth.

Commentary by Dr. Valentin Fuster
2018;():V001T03A046. doi:10.1115/IPC2018-78159.

The Pipeline and Hazardous Materials Safety Administration (PHMSA) Notice of Proposed Rulemaking (NPRM), with Docket No. PHMSA-2011-0023, substantially revises 49 CFR Part 191 and 192. Notable among these changes was the addition of §192.607, verification of pipeline material. This section calls for the verification of material properties of pipe and fittings located in either high consequence areas, class 3, or class 4 locations where traceable, verifiable, and complete records do not exist. Material properties include grade (yield strength, YS, and ultimate tensile strength, UTS) and chemical composition. The proposed regulations include an independent third-party validation for non-destructive testing (NDT) methods to determine material strength and require an accuracy of within ±10% of an actual strength value.

Among the NDT technologies currently available to pipeline operators to estimate material strength is instrumented indentation testing (IIT). IIT is based on the principal that there exists a relationship between the indentation response of a material and its stress-strain curve. The indentation response is measured during the IIT process whereby an indenter is sequentially forced into the material during testing. The link between the indentation response and the material stress-strain curve is established often through the use of iterative Finite Element Analysis (FEA). The IIT vendor’s proprietary software performs this calculation, converting force-displacement measurements into an estimate of YS and UTS.

In this study we extracted force-displacement data from IIT performed using FEA on an idealized steel. This data was then coupled with literature algorithms developed at Seoul National University (Kwon et al.). Parametric sensitivity analysis was then performed on estimated YS with respect to the algorithm parameters. Preliminary results indicate that while variations in the indenter constant, ω, used to estimate surface deformation do not significantly alter the predicted UTS or YS, the sensitivity to deviations in the empirical constant, Ψ, relating normal load to representative stress was more pronounced due to an effect on the calculated power-law constant, K.

PHMSA’s NPRM accuracy requirements for NDT to establish yield and tensile strength should be driven by a rigorous understanding of material inhomogeneities, uncertainties in actual tensile strength determination, experimental uncertainty, and modeling uncertainties. The analysis performed in this paper provides part of this rigorous framework to establish realistic accuracy requirements for NDT that must drive federal rulemaking. In addition, this research highlights the need for pipeline operators to establish controls on the algorithms adopted by commercial NDT vendors.

Commentary by Dr. Valentin Fuster
2018;():V001T03A047. doi:10.1115/IPC2018-78255.

This article presents a complete set of calculations (referred to as Model) PG&E developed to monitor, assess and approve strength tests on insitu (pipelines currently in service) gas transmission pipelines. How the Model is used in the field, 2017 test results, and process improvements that resulted from the implementation of the model are also discussed.

In compliance with CPUC directives, the Code of Federal Regulations[1] and PG&E’s internal standards, PGE has performed strength tests on approximately 1,100 miles of insitu pipelines from 2011 through 2017. The model was specifically designed to assess the strength test of a closed section of gas pipeline for both leaks and ruptures.

The model was originally designed for strength tests using water as the test medium and updated to accommodate nitrogen as a test medium. A future enhancement will be to incorporate a blend of Nitrogen and Helium as the test medium. The model plots the pressure-temperature and pressure-volume curves over the test duration (field test measurements) and compares them to the theoretically calculated curves. The curves are used to determine if the change in pressure is due to temperature influence or leakage. When water is the test medium, the model calculates the net corrected medium volume change from start to end of the static test period. When nitrogen is the test medium, the model calculates and analyzes net mass change of the medium by considering nitrogen under both the real gas state and the ideal gas state.

By calculating restrained (buried) pipeline section and unrestrained (exposed) pipeline section separately, the model gains more accuracy. Accurate temperature measurements play a critical role in the model.

The model makes it possible for engineers to monitor, analyze and direct strength tests with real-time test data. The model is also used to evaluate the pipeline fill condition on the day prior to the actual test, which resulted in fewer test restarts due to incomplete fill or temperature stabilization issues. An additional benefit is the tests were typically completed earlier in the day. The model is utilized on all PG&E insitu pipeline strength projects today. Authors also provide improvement suggestions of this model in future application.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2018;():V001T03A048. doi:10.1115/IPC2018-78364.

Effective integrity management of a corroded pipeline requires a significant quantity of data. Common data sources include in-line inspection (ILI), process monitoring, or external surveys. The key challenge for an integrity engineer is to leverage the data to understand the level of corrosion activity along the pipeline route, and make optimal decisions on future repair, mitigation and monitoring. This practice of gaining business insights from historical datasets is often referred to as ‘data analytics’.

In this paper, a single application of data analytics is investigated — that of improving the estimation of corrosion growth rates (CGRs) from ILI data. When two or more sets of ILI data are available for the same pipeline, a process known as ‘box matching’ is typically used to estimate CGRs. Corresponding feature ‘boxes’ are linked between the two ILIs and a population of CGRs is generated based on changes in reported depth. While this is a well-established technique, there are uncertainties related to ILI sizing, detection limitations, and data censoring. Great care is required if these uncertain CGRs are used to predict future pipeline integrity.

A superior technique is ‘signal matching’, which involves the direct alignment, normalization and comparison of magnetic flux leakage (MFL) signals. This delivers CGRs with a higher accuracy than box matching. However, signal matching is not always feasible (e.g. when conducting a cross-vendor or cross-technology comparison). When box matching is the only option for a pipeline, there is great value in understanding how the box matching CGRs can be improved in order to more closely resemble those from signal matching. This limits the extent to which uncertainties are propagated into any subsequent analyses, such as repair plan generation or remaining life assessment.

Given their relative accuracy, signal matching CGRs can be utilized as a ‘ground truth’ against which box matching results can be validated. This is analogous to the ILI verification process, where in-field measurements (e.g. with laser scan) are used to validate feature depths reported by an ILI. By extension, a model to estimate CGRs following a box matching analysis can be trained with CGRs from a signal matching analysis, using supervised machine learning. The outcome is an enhanced output from box matching, which more closely resembles the true state of corrosion growth in a pipeline.

Through testing on real pipeline data, it is shown that this new technique has the potential to improve pipeline integrity management decisions and support economical, safe and compliant operation.

Commentary by Dr. Valentin Fuster
2018;():V001T03A049. doi:10.1115/IPC2018-78376.

Pipeline operators’ utmost priority is to achieve high safety measures during the lifecycle of pipelines including effective management of integrity threats during excavation and repair processes. A single incident pertaining to a mechanical damage in a gas pipeline has been reported previously which resulted in one fatality and one injury during investigation. Some operators have reported leaking cracks while investigating rock induced dents. Excavation under full operating pressure can lead to changes in boundary conditions and unexpected loads, resulting in failure, injuries, or fatalities. In the meantime, lowering operating pressure during excavation can have a significant impact on production and operational availability. The situation poses two conflicting objectives; namely, maximizing safety and maximizing operational availability. Current pipeline regulations require that operators have to ensure safe working conditions by depressurizing the line to a level that will not cause a failure during the repair process. However, there are no detailed guidelines on how an operator should determine a safe excavation pressure (SEP) level, which could lead to engineering judgment and subjectivity in determining such safety level. While the pipeline industry relies on well-defined fitness for purpose analyses for threats such as crack and corrosion, there is a gap in defining a fitness for purpose for dents and dents associated with stress riser features in order to set an SEP. Stress and strain based assessment of dents can be used in this matter; however, it requires advanced techniques to account for geometric and material nonlinearity. Additionally, loading and unloading scenarios during excavation (e.g. removal of indenter, overburden pressure, etc.) drive a change in the boundary conditions of the pipe that could lead to leakage. Nevertheless, crack initiation or presence within a dent should be considered, which requires the incorporation of crack geometry and application of fracture mechanics in assessing a safe excavation pressure. Recently, there have been advancements in stress and strain based finite element analysis (FEA) of dents coupled with structural reliability analysis that can be utilized to assess SEP. This paper presents a reliability-based approach to determine a safe excavation pressure for dented liquid pipelines. The approach employs nonlinear FEA to model dents interacting with crack features coupled with uncertainties associated with pipe properties and in-line-inspection information. A fracture mechanics-based limit state is formulated to estimate the probability of failure of dents associated with cracks at different levels of operating pressure during excavation. The application of the developed approach is demonstrated through examples within limited scope. Recommended enhancements and future developments of the proposed approach are also discussed.

Topics: Pressure , Pipelines
Commentary by Dr. Valentin Fuster
2018;():V001T03A050. doi:10.1115/IPC2018-78413.

The National Energy Board’s (NEB or the Board) top priorities are the safety of people and protection of the environment. NEB-regulated pipelines have a very good safety record; however, the NEB noticed an increased trend in some types of incidents. Therefore, after considerable stakeholder consultation, in March 2012 the NEB started requiring NEB-regulated companies to report annually on new pipeline performance measures. These performance measures were developed and introduced to promote continual improvement in the management of pipelines by allowing companies to compare their results with industry aggregate numbers. In addition, these metric results allow the NEB to both evaluate and demonstrate that pipeline companies are effective in managing pipeline safety and protection of the environment.

The NEB requires all regulated companies to report on incidents, such as releases of substances and serious injuries. Pipeline performance measures data provides the Board additional information such as lagging and leading indicators. These lagging indicators provide an historical view of company performance while the leading indicators provide forward looking data of potential future events. The NEB is of the view that an amalgamation of leading, lagging and qualitative measures can provide an overview of company effectiveness in meeting foundational management system program objectives.

This paper examines four years of reported integrity related performance and integrity inspection data to evaluate trends in activities taken by companies to maintain safe pipelines. This paper will briefly discuss the challenges encountered when developing the measures, obtaining consistent data and evaluation of the data to identify trends.

The paper will conclude by summarizing select results of the integrity performance measures and integrity inspection information data and discuss any potential future actions related to the pipeline performance integrity measures.

Commentary by Dr. Valentin Fuster
2018;():V001T03A051. doi:10.1115/IPC2018-78423.

A pipeline integrity management program is greatly affected by integrity planning methods and inline inspection (ILI) tool performance. In integrity management program planning, inspection and maintenance activities are in common practice, determined from risk and integrity assessment practices with the objective to reduce risk and effectively exceed a reliability target for the safe operation of the pipeline. An efficient and effective integrity planning method can address the most significant risk and optimize the operational and maintenance costs.

In this paper, a method is presented for analyzing the impact of ILI tool accuracy on integrity planning for pipelines for fatigue cracks. Crack inspection and threat of fatigue cracking was used as the working case for the analysis although the approach could potentially be used for any pipeline threat type. The proposed method is based on the use of a Monte Carlo simulation framework, where initial crack defect size and ILI measurement errors are considered as key random variables.

The integrity (severity) assessment of the crack population scenarios used the CorLAS™ burst pressure model, and the Paris’ law crack growth model based on API 579. The subsequent pipeline reliability assessments also considered single and multiple cracks scenarios. Using a reliability / probability of failure (PoF) approach, the impact of ILI tool accuracy and initial crack size on when to set reinspection and reassessment intervals was investigated.

Furthermore, integrity program cost scenarios for pipeline integrity programs with multiple cracks was also evaluated with respect to different (crack) populations, pipe conditions and ILI accuracies. A sensitivity analysis was performed considering different inspection costs, maintenance costs and relative crack severity for pipelines with financial metrics. Various scenarios were discussed regarding maintenance and inspection planning and a “total cost rate” for different situations. The proposed method can support integrity management program planning by linking risks with integrity plan costs associated with ILI accuracies, and optimal re-assessment intervals.

Topics: Inspection , Pipelines
Commentary by Dr. Valentin Fuster
2018;():V001T03A052. doi:10.1115/IPC2018-78427.

Pacific Gas and Electric Company owns and operates an extensive network of over 10,700 km (6,700 miles) of gas transmission pipelines, much of which is under 16″ diameter and operates at less than 27.5 bar (400 psig), making them difficult to inspect with free swimming in-line inspection (ILI) tools. Additionally, many piggable pipeline sections are multi-diameter and have numerous 1.5D fittings, some of these in back to back configuration, requiring tools that are not currently available. Following several failed attempts to inspect PG&E’s 12″ × 16″ pipelines in 2015 using existing ILI tools, and after working to modify a 12″ × 18″ tool for lower pressure service in 2016, PG&E and ROSEN decided to collaboratively develop new, specially designed, 12″ × 16″ geometry and axial MFL tools.

The goal of this project was to develop tools that could meet both the PG&E pipeline passage requirements and allow for an acceptable speed profile. The need to inspect a total of 16 pipeline sections in the long-term ILI Upgrade Plan, in this size range, justified the investment in these new tools. The service provider embarked on a new ILI tool design process including design, manufacturing, fabrication and testing at their facilities in Germany. Through this process, a number of unique ILI tool design features to lower tool drag and improve ease of collapsibility were implemented, resulting in a tool that far exceeds existing industry capabilities. To confirm the tools’ capabilities before their first use in a live gas transmission pipeline, pump testing in water, as well as in compressed air, was performed. In late 2017, using these tools, PG&E inspected two previously unpiggable 12″ × 16″ low-pressure pipelines successfully. In this paper, the process of developing these tools will be discussed. The test program will be reviewed comparing findings under controlled conditions in water and compressed air with pig run behavior in the live pipelines. The analysis also provides an assessment of the operating conditions that are deemed necessary for the inspection tool to gather a good quality data set.

Topics: Pressure , Pipelines
Commentary by Dr. Valentin Fuster
2018;():V001T03A053. doi:10.1115/IPC2018-78604.

The pipeline industry has been using Inline Inspection (ILI) since the 1970s. High resolution tools have been available for inspecting corrosion from about the 1980s and related ILI-based programs have been evolving. In this study incident rate data from the last 30 to 40 years of experience was examined and trended.

Corrosion related incident rates have reduced where ILI programs have been implemented. Significant changes in programs have shown related incident reductions or positive trends. Throughout this time there have been a few post-ILI incidents and by taking a closer look at these incidents and learning from the findings the ILI-based assessments and programs were further improved.

In this study, all of the post-ILI corrosion related ruptures on the TransCanada system have been closely examined and trended. The effects of program changes and related changes to performance indicators have been examined. Some significant industry failures, where data is publicly available, have also been examined. These failures have been analyzed and trended to understand significant commonalities between these failures.

Data was analyzed with the intention of learning from them and applying this learning to avoid similar failures in the future. By understanding the uncertainties, technology limitations, and limits of applicability as well as the types of programs used and where these have not identified probable failures practical solutions were derived. All of the failures have been examined (as allowed by the data available) to find approaches which would have proactively identified these events, so that similar events can be avoided in the future.

ILI tools generate a wealth of information and appropriate use of this information has shown to be effective in managing pipelines. However, it is also important to understand the limitations of technologies, learn from the failures, and acknowledge uncertainties so that undesirable events can be avoided.

Topics: Failure
Commentary by Dr. Valentin Fuster
2018;():V001T03A054. doi:10.1115/IPC2018-78635.

The project “Development of an Industry Test Facility and Qualification Processes for in-line inspection (ILI) technology Evaluation and Enhancements” aims to expand knowledge of ILI technology performance and identify gaps where new technology is needed. Additionally, this project also aims to provide ILI technology developers, researchers and pipeline operators a continuing resource for accessing test samples with a range of pipeline integrity threats and vintages; and inline technology test facilities at the Technology Development Center (TDC) of Pipeline Research Council International, Inc. (PRCI), a PRCI managed facility available for future industry and PHMSA research projects.

An ILI pull test facility was designed and constructed as part of this project based on industry state-of-the-art and opportunities for capability improvement. The major ILI technology providers, together with pipeline operator team members, reviewed the TDC sample inventory and developed a series of ILI performance tests illustrating one of multiple possible research objectives, culminating in 16-inch and 24-inch nominal diameter test strings. The ILI technology providers proposed appropriate inspection tools based on the types of the integrity threats in the test strings, a series of pull tests of the provided ILI tools were performed, and the technology providers delivered reports of integrity anomaly location and dimensions for performance evaluation.

Quantitative measures of detection and sizing performance were confidentially disclosed to the individual ILI technology providers. For instances where ILI predictions were outside of claimed performance, the vendors were given a limited sample of actual defect data to enable re-analysis, thus demonstrating the potential for improved integrity assessment with validation measurements.

In this paper, an evaluation of the ILI data obtained from repeated pull-through testing on the 16 and 24-inch pipeline strings at the TDC is performed. The resulting data was aligned, analyzed, and compared to truth data and the findings of the evaluation are presented.

Commentary by Dr. Valentin Fuster
2018;():V001T03A055. doi:10.1115/IPC2018-78646.

Colonial pipeline’s asset data management team maintains large volumes of data, CAD facility drawings, and historical records. Organizing and encapsulating this data has been a historical challenge. Frequent requests for data relevant to individual projects was time-consuming and laborious. Colonial Scout was designed to be a simple self-help tool that allows employees to locate data quickly. Further, it was constructed to provide a one-stop shop for accessing Colonial data in its most current and up to date forms. Design of the Colonial Scout application took approximately six months to complete. The final result is an intuitive web map application connected to a versioned enterprise geodatabase. Within the application, relevant tools interact with live data, providing immediate access to Colonial’s most up to date information. Integration with FME server, adept document management and Esri’s ArcGIS enterprise have advanced colonial scout’s efficiency in locating data. These software products enhance colonial scout’s power as a help-yourself product for accessing current information through means of helpful data visualization. Colonial Scout is the go to source for alignment sheets, CAD drawings, property and easement records, locating tank assets, and Colonial’s 5,500 miles of pipeline assets. Users also have the ability to download data in a variety of file formats for project specific analysis and reports. Colonial Scout has significantly reduced the number of work orders related to searching for data, drawings and records. Employees are better informed by acquiring the latest information and no longer rely on outdated paper hardcopies. Colonial Scout is an innovative and expandable solution for Colonial’s ever-growing data needs.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2018;():V001T03A056. doi:10.1115/IPC2018-78717.

In the majority of liquid pipelines, the pump station discharge pressure ranges are much greater than the pressure ranges experienced at the suction end of the downstream pump station. Consequently, the cyclic pressure induced fatigue damage accumulation rate is greater at the discharge end than at the suction end of a given pipeline segment. In completing an integrity assessment of a fatigue susceptible feature, assuming that the pump station discharge cyclic pressure profile applies to all features in the line segment is conservative. This conservative assumption can lead to un-necessary repairs, unintentional damage from over-prescribed maintenance, or inefficient decisions regarding maintenance action prioritization.

The following paper presents the results of a Canadian Energy Pipeline Association (CEPA) initiative to develop a simple approach to define the cyclic pressure history at any point in a liquid pipeline segment based on the bounding discharge and suction pump station Supervisory Control and Data Acquisition (SCADA) pressure time history data. The approach was developed based on collected operating pipeline SCADA pressure time history data for line segments with intermediate measurement points which could be used to validate the developed model. The pressure time histories for all the locations were analyzed using a Rainflow cycle counting technique to develop pressure range spectra (i.e. histograms of pressure range events) and the cyclic pressure severity of each of the time histories was characterized by the Spectrum Severity Indicator (SSI). The SSI represents the number of annual 90MPa hoop stress cycles required to accumulate the same fatigue damage as the actual pressure spectrums.

The technique presented in this paper illustrates how to infer the pressure range spectra or SSI at intermediate locations. The technique is shown to be a significant improvement (i.e. higher location specific accuracy) than either applying the discharge pressure spectrum or applying a linear interpolation between discharge and suction conditions in fatigue life assessments.

The liquid pipeline cyclic pressure characterization technique presented in this paper will permit integrity assessment or severity ranking of features along a pipeline to be based on an accurate local pressure profile rather than an upper bound. This understanding will help to improve the accuracy of defect loading, one of the three main pillars in integrity assessment (i.e., loading, geometry, materials) for defects susceptible to cyclic loading (e.g., cracking, mechanical damage).

Topics: Pressure , Pipelines
Commentary by Dr. Valentin Fuster
2018;():V001T03A057. doi:10.1115/IPC2018-78751.

Environmental-assisted cracks in pipeline steels usually undergo the following three sequential stages prior to the failure:

• Stage 1 – crack initiation and early stage crack growth, in which cracks initiate at imperfections but grow slowly depth-wise with time. Crack length may be seen to increase either because of merging with new small cracks in the vicinity of an existing crack or faster crack growth at the crack tip. Some cracks pose little threat to pipeline steel integrity if they remain dormant.

• Stage 2 – Increased crack growth rate where crack growth can be dictated by mechanical driving forces and crack growth rate increases with time.

• Stage 3 – The final stage of crack growth where crack growth rate is very high. Typical crack management programs mitigate cracks prior to entering Stage III.

It is of great importance that pipeline steels with Stage II cracks are detected, monitored, and managed to ensure operational pipeline integrity. Although a range of crack in-line inspection and detection techniques with varied detection limits are available, it is not clear how their detection limits match the threshold geometrical dimensions of Stage 2-cracks. This investigation is aimed to define critical geometrical dimensions of cracks that are considered to be Stage 2 cracks. The determination of critical geometrical dimensions of Stage 2 cracks was made with a consideration of a wide range of situations including pipeline operating conditions, susceptible environments for crack growth, metallurgical, fabrication and construction conditions of pipeline steels. A comparison of the threshold geometrical dimensions of Stage 2 cracks with the crack detection limits of modern crack inspection and detection techniques are made at the end of the paper.

Commentary by Dr. Valentin Fuster
2018;():V001T03A058. doi:10.1115/IPC2018-78770.

In-line inspection (ILI) systems continue to improve in the detection and characterization of cracks in pipelines, and are relied on substantially by pipeline operators to support Integrity Management Programs for continual assessment of conditions on operating pipelines that are susceptible to cracking as an integrity threat. Recent experience for some forms of cracking have shown that integration of data from multiple ILI systems can improve detection and characterization (depth sizing, crack orientation, and crack feature profile) performance. This paper will describe the approach taken by a liquids pipeline operator to integrate data from multiple ILI systems, namely Ultrasonic axial (UC) and circumferential (UCc) crack detection and Magnetic Flux Leakage (MFL) technologies, to improve detection and characterization of cracks and crack fields on a 42 miles long, 12-inch OD liquid pipeline with a 38-year operating history. ILI data has indicated a large number of crack features, including 4000+ crack features reported by UC, 1000+ crack features by UCc, and 2500+ metal loss features reported by MFL. Initial excavations demonstrated a unique pattern of blended circumferential-, oblique- and axial-orientated cracks along the entire extent of the 42-mile pipeline, requiring advanced methods of data integration and analysis. Applying individual technologies and their analysis approaches showed limitations in performance for identification and characterization of these blended features. The outcome of the study was the development of a feature classification approach to classify the cracks with respect to their orientation, and rank them based on the depth sizing by using multiple datasets.

Several sections of the 42-mile pipeline were cut-out and subjected to detailed examination using multiple non-destructive examination (NDE) methods and destructive testing to confirm the crack depths and profiles. These data were used as the basis for confirming the ILI tool performance and providing confirmation on the improvements made to crack detection and sizing through the data integration process.

Commentary by Dr. Valentin Fuster

Pipeline and Facilities Integrity: Prevention, Monitoring, and Growth Modeling

2018;():V001T03A059. doi:10.1115/IPC2018-78233.

Pipeline integrity decisions are highly sensitive to the assessment model. A less accurate and less precise model can conservatively trigger many unnecessary actions such as excavations without providing additional safety. Therefore, a more accurate and precise model will reduce excavations and provide higher assurance of safety. This is akin to using a more precise surgical tool such as a laser for cutting out a brain tumor where you can cut closer to the edge and be assured of cutting out more of the tumor (safer) and yet cut less of the surrounding brain tissue (less conservative).

This paper presents a novel model for assessing large metal-loss corrosion based on in-line inspection (ILI) or field measurement. The model described in this paper utilized an unconventional approach, namely multiple plausible profiles (P2), to idealize the shape of the corrosion, and therefore is referred to as P2 model. In contrast, all existing models use one single profile for characterizing corrosion profile, e.g. RSTRENG utilizes a single worst-case river bottom profile to characterize the shape of corrosion.

The P2 model has been initially validated using fourteen (14) full scale specimen-based hydrostatic tests on pipes containing real large corrosion features. Validation results showed that the P2 model is safe, but less conservative and more precise than RSTRENG. The magnitude of reduction in conservatism depends on the corrosion morphology. On average, the P2 model achieves 15% reduction in model bias and 44% reduction in standard deviation of model error. Further validation was provided using the testing data published by PRCI and PETROBRAS. Another set of burst tests are being conducted by TransCanada as part of the continuous validation of P2 model.

The effectiveness of the P2 model was demonstrated through two case studies (denoted by Case study 1 and 2). Case Study 1 included 170 external metal-loss corrosion features that were excavated from different pipeline sections, and have field-measurements using laser scan tool. Case Study 2 included 154 ILI-reported external metal-loss corrosion features with RSTRENG calculated rupture-pressure-ratio (RPR) of less than or equal to 1.25 (i.e. RPR ≤ 1.25); hence, these features were classified as immediate features. The Case Studies showed that the use of the P2 model resulted in 80% less number of ILI-reported features requiring immediate action (i.e., RPR ≤ 1.25) and 89% less number of excavated features requiring repair (e.g., sleeve or cut-out) compared to the respective number of features identified by RSTRENG-based assessment. The reduction in the number of features requiring excavation or repair is highly morphology-dependent with the highest reduction achievable for pipeline containing long and wide corrosion clusters (e.g., tape-coated pipeline). However, the P2 model is applicable to all clusters regardless of the number of individual corrosion anomalies associated with the cluster.

Topics: Metals , Corrosion
Commentary by Dr. Valentin Fuster
2018;():V001T03A060. doi:10.1115/IPC2018-78247.

A significant amount of effort has been expended in the area of advancing pipeline dent remaining life assessment methods beginning in the late 1980s and extending to the current day. Initial research efforts were primarily empirical in nature while more recent research efforts have incorporated finite element modelling. Coupled with advancements in assessment techniques, the capabilities of advanced in-line inspection (ILI) tools have increased to a point where they can provide consistent, reliable information that is suitable for dent assessments. As a result of these advancements in assessment models and ILI tools, operators can now perform remaining life assessments using ILI data, and a multitude of remaining life assessment models are available, including solutions from the European Pipeline Research Group (EPRG), Pipeline Research Council International (PRCI), American Petroleum Institute (API), and finite-element based approaches. In addition to these remaining life assessments, many operators routinely perform strain-based assessments based on guidance from ASME B31.8. To date, there have been few studies comparing the various assessment methods on large numbers of dents, and as a result, significant questions persist as to the conservatism inherent in each method. In addition, the EPRG and PRCI methods are largely based on full-scale testing and finite-element models performed with idealized indenter shapes while actual pipeline dents typically exhibit complex shapes and interactions between multiple dents. Each model also has limitations and advantages that are discussed in this paper, such as ease of use and how pipeline geometry and weld association are considered. This paper provides a robust comparison of selected dent assessment methodologies on 220 actual dents from a 24-inch pipeline with depths ranging from 0.6–4.5% OD, and 32 dents from a 30-inch line with depths ranging from 1–2.5% OD. The assessment includes both top and bottom of line dents and investigates the influence of restraint on remaining life. The results presented in the paper are based on high-resolution ILI caliper data collected during two in-line inspections. Furthermore, the paper provides statistical comparisons between strain and remaining life methodologies and also between the various remaining life assessments. The paper also provides a comparison of the restraint parameter from the PRCI model with calculated stress concentration factors from finite-element models. The paper provides a first of its kind comparison of the various methods and discusses how the work may be extended to other pipe diameters and wall thicknesses.

Commentary by Dr. Valentin Fuster
2018;():V001T03A061. doi:10.1115/IPC2018-78293.

Spirally welded pipelines can make up significant portions of operator transmission systems, and may contain manufacturing anomalies that are susceptible to fatigue growth. Modifications to inputs of crack assessment models, such as CorLAS®, are required to account for the angle these cracks make with respect to the longitudinal pipe axis, given that these crack assessment models were developed for longitudinally orientated cracks. Two such modifications were investigated and are discussed in this paper.

One approach considered the normal stress component perpendicular to the angled crack, for which a stress transformation calculator was developed. Another approach, adapted from API 579 and BS7910 standards, used an effective crack length calculated as the longitudinal projection of the full length of an angled crack.

Failure pressures calculated using these approaches were compared to validated finite element (FE) results. For both modifications, the pressure capacity increased for angled cracks versus longitudinal cracks. The transformed normal stress approach resulted in non-conservative failure pressure predictions with respect to the FE models, whereas the modified crack length approach was conservative.

Additionally, the extended finite element method (XFEM) was used to investigate the propagation behavior of angled cracks. It was found that the general tendency was for propagation parallel to the longitudinal pipe axis; however, when considering weld residual stresses, the crack propagation would be directed toward the direction of the spiral seam.

Commentary by Dr. Valentin Fuster
2018;():V001T03A062. doi:10.1115/IPC2018-78315.

A pipeline operator set out to assess the risk of circumferential stress corrosion cracking and to develop a proactive management program, which included an in-line inspection and repair program. The first step was to screen the total pipeline inventory based on pipe properties and environmental factors to develop a susceptibility assessment. When a pipeline was found to be susceptible, an inspection plan was developed which often included ultrasonic circumferential crack detection in-line inspection and geotechnical analysis of slopes. Next, a methodology was developed to prioritize the anomalies for investigation based on the likelihood of failure using the provided in-line inspection sizing data, crack severity analysis, and correlation to potential causes of axial or bending stress, combined with a consequence assessment. Excavation programs were then developed to target the anomalies that posed the greatest threat to the pipeline system or environment.

This paper summarizes the experiences to date from the operator’s circumferential stress corrosion cracking program and describes how the pipeline properties, geotechnical program, and/or in-line inspection programs were combined to determine the susceptibility of each pipeline and develop excavation programs. In-line inspection reported crack types and sizes compared to field inspection data will be summarized, as well as how the population and severity of circumferential stress corrosion cracking found compares to the susceptible slopes found in the geotechnical program completed. Finally, how the circumferential SCC time-average growth rate distributions were calculated and were used to set future geohazard inspections, in-line inspections, or repair dates will be discussed.

Commentary by Dr. Valentin Fuster
2018;():V001T03A063. doi:10.1115/IPC2018-78392.

Oil pipelines and gas pipelines operations result in very different pressure fluctuation schemes due to different compressive properties of liquids and gases. Liquid fluids such as oil are less compressible and pressure fluctuations during oil pipelines operations are more frequent and vary over a wide range of magnitudes and frequencies, compared with those during gas pipelines operations. Despite the differences in operating conditions indicated above, both oil pipelines and gas pipelines are susceptible to stress corrosion cracking and corrosion fatigue failures. This investigation was initiated to understand the different crack growth rate behavior of pipeline steels characteristic to the type of pressure fluctuation schemes in near-neutral pH environment, that is, oil pipelines vs. gas pipelines. It was suspected that the similar range of service life between oil pipeline steels and gas pipeline steels could be attributed to a higher rate of direct dissolution at the tip of a crack during gas pipeline operation because of much higher mean pressures, despite their lower crack growth caused by corrosion fatigue. In the case of near-neutral pH stress corrosion cracking, corrosion makes minor contribution to crack growth but produces diffusible hydrogen that interacts with cyclic loading to make cracks grow. This study was performed using specimens with surface cracks, which simulated the following two environmental conditions: 1) fully exposed to the environment, 2) shielded from the environment, exposed to hydrogen only. In Case 1), the specimen surface, on which the surface cracks were made, was fully exposed to a near-neutral pH solution, allowing the occurrence of corrosion at the crack tip. In Case 2), a narrow strip of a coating was applied to prevent the cracks from direct contact with the corrosive solution; however, the cracks were affected by diffusible hydrogen which had been generated as a by-product of corrosion on the adjacent steel surface free of coatings. These specimens were mechanically loaded under different pressure schemes typical of both oil and gas pipeline operations. It has been found that crack growth caused by direct dissolution of crack tip materials is insignificant, regardless of pipeline operating conditions. A much higher crack growth rate, attributed to hydrogen embrittlement, was found under gas transmission conditions, while a higher corrosion fatigue crack growth was found under oil transmission conditions. Based on these findings, strategies on crack growth mitigation, characteristic to each type of pipeline operation are also proposed.

Commentary by Dr. Valentin Fuster
2018;():V001T03A064. doi:10.1115/IPC2018-78394.

High pH Stress Corrosion Cracking (HpHSCC) is a significant threat to the buried pipelines, which are protected through simultaneous coating and cathodic protection strategies. In the past decades, extensive research has been devoted to assessing the influence of environmental and metallurgical factors on the susceptibility to HpHSCC. With reference to mechanical factors, previous studies employed either slow strain rate or constant amplitude testing methods. However, the pressure fluctuation data extracted from pipeline operations has indicated that pipelines experience highly variable amplitude loading conditions during their service. Accordingly, an important consideration in managing HpHSCC is load interaction. Statistics show a higher probability of HpHSCC failures within the 30 km downstream from pump/compressor stations where the pipeline steels experience elevated service temperatures, with incipient higher susceptibility to HpHSCC. However, the pipeline sections within the 30 km downstream from pump/compressor stations also experience the underload-type of pressure fluctuations that feature a maximum pressure close to the design limit, frequent and large amplitudes of depressurization, resulting in low stress ratio, R (minimum stress/maximum stress), and many smaller pressure fluctuations (minor cycles) with R ratio closer to +1.0. It has been well characterized that the underload-minor-cycle-type of pressure fluctuations has the significant acceleration effect on crack growth rates in near-neutral pH (NNpH) environments. However, the effect of the underload-type of pressure schemes on HpHSCC crack growth has not been well developed. In this research work, a cathodically protected X65 steel specimen in the developed high pH solution, composed of 1N Na2CO3 and 1N NaHCO3, was subjected to different loading conditions. These loading waveforms simulate underload cycles (R = 0.5), minor cycles (R = 0.9) and variable amplitudes consisting of both underload and minor cycles, respectively. The HpHSCC test results showed that the highest and lowest crack growth rates were obtained in high and low R ratio constant amplitude loading conditions, respectively. Furthermore, an intermediate crack growth rate was obtained under variable amplitude loading condition. These results indicate that the underload cycles retard crack growth rate in high pH environments.

Commentary by Dr. Valentin Fuster
2018;():V001T03A065. doi:10.1115/IPC2018-78405.

Although stress corrosion cracking (SCC) growth is attributed to the synergistic effects of stress and corrosion, these two factors can just as easily become competing mechanisms, with stress cycles driving growth (hydrogen, the by-product of corrosion, may facilitate the growth), and corrosion working to blunt the crack tip and arrest growth. It follows that reducing the maximum pressure and cycling severity can slow down the crack growth or even stop it, and aggressive corrosion can further blunt the sharp crack tip. The Authors have observed, on a particular Polyethylene (PE) tape coated pipeline, instances where SCC has exhibited a propensity to corrode and convert into sharp edge corrosion. This is attributed to the combined effects of limited corrosion protection and low stresses. The focus of the paper is to assist operators in recognizing this phenomenon and integrate lessons learned into pipeline integrity management strategies.

Commentary by Dr. Valentin Fuster
2018;():V001T03A066. doi:10.1115/IPC2018-78408.

Standard pipe corrosion assessments are based on simplifying assumptions with respect to corrosion geometry and focus on pressure based loading. Moreover, when corrosion patches traverse girth welds, validity criteria to their assessment become impractically vague. The integrity of girth welds is additionally influenced by axial stresses, which may act in combination with hoop stress resulting from pressure. In an attempt to address these issues, the authors conducted a detailed assessment on a significant, highly irregular corrosion patch traversing a 12″ natural gas pipeline girth weld. The investigation comprises a full scale uniaxial tensile test and supporting detailed finite element (FE) analyses. Hereby, the model mesh adopts detailed geometrical characteristics resulting from a surface profile scan obtained from stereoscopic digital image correlation. The numerical model is validated based on the uniaxial tensile test, in the sense that plastic collapse and highly complex strain distributions are successfully reproduced. Finally, the FE model is used to explore axial tensile failure in presence of internal pressure.

Topics: Corrosion , Pipes
Commentary by Dr. Valentin Fuster
2018;():V001T03A067. doi:10.1115/IPC2018-78433.

Pipeline integrity management commonly leverages nondestructive inspection of pipeline defects via inline inspection (ILI) and assessment of the resultant data. Key parameters for dent analysis include the feature geometry measured by caliper tools and the presence/severity of any interacting features (such as cracks or areas of corrosion) which can be measured with a variety of technologies (such as magnetic flux leakage or ultrasonic tools). Dent profile measurements can be especially susceptible to noise due to the measurement techniques employed, signal quality, and overall tool performance. Analytical methods for strain assessment of dents can employ curve/surface fitting techniques to estimate the curvature and calculate the strain of the dent based on the fitted curve/surface. Noise in the measured profile can result in local areas of high perceived strain, which could lead to misinterpretation of a dent’s true severity, especially when using automated or purely analytical assessment methods.

A deterministic strain-based approach for evaluating the severity of dented pipelines has been presented previously which leverages multi-dimensional B-spline functions to more accurately apply the non-mandatory ASME B31.8 equations for dent assessment. The approach presented previously requires relatively smooth dent profile information to minimize the effects of signal noise. While low pass filters can effectively eliminate noise in the signal, they may also lead to loss of accuracy (e.g. excessive smoothing can reduce the depth and sharpness of a measured dent’s profile). This paper discusses how low pass filters can be optimally used to smooth the raw ILI signals to allow for analytical representation of the dent shape without underestimating its severity.

The conclusion of this venture is a detailed workflow for the analytical assessment of dented pipelines for the rapid characterization of the severity of deformation in pipelines with limited computational demand. This type of assessment allows for initial ranking and assessment of large and complex pipeline systems to select features requiring more detailed assessment or mitigation.

Topics: Algorithms , Pipelines
Commentary by Dr. Valentin Fuster
2018;():V001T03A068. doi:10.1115/IPC2018-78495.

The safety of gas transportation pipelines under fatigue loading remains an important issue. The purpose of the present study is to better evaluate the fatigue crack growth (FCG) behavior by carrying out analysis/predictions and experiments in full-size pipeline steels. A full characterization was made using several samples of an X42 grade pipeline steel, to characterize the monotonic and the fatigue behavior. Fatigue tests on full-scale pipeline steels under pressure loading were performed. The potential drop (PD) method applied to pressurized pipes makes it possible to monitor and quantify both crack initiation and crack propagation. These tests served as a basis for numerical comparison. Crack propagation of the full-size pipeline steel was simulated by finit element analysis (FEA) using an adaptive re-meshing approach implemented as part of the Z-set/Zebulon software. Simulation allows predicting fatigue crack growth life on pipes using results of tests on specimens as an input.

Commentary by Dr. Valentin Fuster
2018;():V001T03A069. doi:10.1115/IPC2018-78540.

Near-neutral pH stress corrosion cracking (NNpHSCC) continues to be a concern for existing high pressure pipelines used to transport oil and gas in Canada. Although several studies have focused on the role of pipe steel microstructure on the initiation and growth of NNpHSCC, most used specimens machined from sub-surface locations that did not preserve the original pipe surface, which is the material that ultimately exposed.

In the present work, a series of test specimens were designed to preserve the external pipe surface and allowed shallow 0.05 mm root radius surface notches with depths from 0.1, 0.2 and 0.3 mm to be machined and tested. All specimens were machined in the hoop (transverse) direction from a 1067 mm diameter, 12.5 mm thick X80 pipe. The specimens were subjected to a constant load of 95% of the specified minimum yield strength (SMYS) (equivalent to 80% of the actual pipe hoop yield strength) using proof rings for extended durations, e.g., 110, 220, 440 or 660 days. The results show that there was no apparent SCC developed on the smooth specimens with the original surface even after being tested for up to 660 days. In contrast, SCC were found to have initiated at the machined notches, irrespective of their depth after testing for 220 days. To provide further understanding of specimen design, the same SCC testing conditions were applied to smooth round-bar test specimens machined in the hoop direction of this same pipe close to the external surface and the mid-wall locations. While minor SCC initiation was found in the near surface specimens, significant SCC was observed in the specimens taken from the mid-wall location. This finding suggests that the heterogeneous or variable microstructure through the pipe wall thickness plays a critical role in SCC initiation for the X80 pipe investigated. It also suggests that careful attention must be paid to the design of test specimens as well as the location that they are removed from a test pipe in order to realistically assess the SCC susceptibility of pipe steels.

Commentary by Dr. Valentin Fuster
2018;():V001T03A070. doi:10.1115/IPC2018-78564.

Since the late 1980’s Ultrasonic tools have been used for the detection and sizing of crack like indications. ILI service providers developed inspection technologies for liquid and gas lines that are widely used nowadays. In comparison to axial cracking, circumferential cracking is not a prevalent risk to most pipelines and therefore is not as well understood. Nevertheless, pipeline Operators observe from time to time circumferentially oriented defects, often in combination with circumferential welds or local stress/strain accumulations. These are often caused by pipeline movement, which may especially occur in mountain areas.

With the introduction of Ultrasonic circumferential crack inspection tools in the late 2000’s the knowledge has steadily increased over time. Extensive data collected from in-ditch NDE validations has provided NDT Global with an increased knowledge of the morphology of single cracking and stress corrosion cracking defects both in the axial and circumferential orientations. Field verifications have shown that not all features have the same morphology. Some of the challenges with circumferential cracking are for features that fall outside of the industry standard specifications. These types of features can exhibit characteristics such as being sloped, skewed or tilted. In 2016 NDT Global was approached by Plains Midstream Canada to complete inspections utilizing the 10″ Ultrasonic Circumferential crack inspection technology. The pipeline system spans 188km within Canada and consists of 2 segments. The pipeline traverses several elevation changes and crosses several creeks and roads. Circumferential cracking was identified during dig campaigns performed for other threats, therefore the need to inspect each pipeline segment with the Ultrasonic circumferential technology was identified.

Plains Midstream Canada and NDT Global formed a close collaboration to assess the severity of circumferential crack features in this line. This paper will discuss integrity aspects from an Operator and Vendor perspective. Challenges identified due to the morphology of the circumferential crack like indications and derived analysis rules and interpretation methodologies to optimize characterization and sizing are presented. Finally, potential opportunities to maintain the integrity of similar assets by applying some of the findings and enhance the management and decision making process are suggested.

Commentary by Dr. Valentin Fuster
2018;():V001T03A071. doi:10.1115/IPC2018-78587.

Surface cracks in pipelines under certain service conditions may grow due to fatigue, which is caused by pressure (cycles). The leak-before-break (LBB) assessment method is employed to avoid any catastrophic failure prior to a detectable leakage. In the LBB analysis, crack critical length is an essential element for determining the pipeline leak or rupture.

The common approach regarding the evaluation of LBB is to calculate the critical crack length and through-wall length under iven pressure cycling conditions. If the critical crack length is less than the through-wall length, LBB conditions could occur and be detected if leak detection capability is high. This involves complex calculations in crack fatigue growth and could result in extensive analysis if thepipeline has a large crack population.

This paper presents a simplified approach for assessing the leak-before-break of the flawed pipelines. This approach is based on industrial code API 579-1/ASME FFS-1 Fitness-For-Service. Through the investigation of effects for different parameters on crack growth, including crack initial geometry, pipeline materials, loading conditions, pipeline diameter and wall thickness, it was determined that the crack initial aspect ratio is a major factor influencing crack growth and geometry evolution. Based on these parameters, a crack fatigue growth map was developed. By comparing the behaviors of different cases, it was confirmed that the proposed method is a valid approach for the pipeline LBB analysis.

Commentary by Dr. Valentin Fuster
2018;():V001T03A072. doi:10.1115/IPC2018-78608.

In an era where pipeline safety is of paramount interest, vintage pipelines with corrosion have to be managed responsibly. Optimization of corrosion mitigation for these pipelines has a significant effect on the industry’s management systems and related costs. To help optimize the corrosion management process, reliability-based limit state design (LSD) corrosion assessment criteria have been developed for onshore pipeline as part of a joint industry project. The LSD approach is a simplified form of the reliability-based approach. It achieves risk or safety consistency within a certain tolerance, while utilizing a deterministic procedure that is easier to apply. The overall methodology and development of the criteria are described in a companion paper. This paper describes the application of the LSD corrosion criteria to real pipeline cases and evaluation of the results.

The performance of the LSD criteria, as determined by the number of corrosion repairs required, was compared to that of the CSA Z662 deterministic assessment criteria and the full probabilistic criteria used by TransCanada Pipelines Ltd. (TCPL) to determine if the criteria lead to practical solutions for real cases. The CSA criteria use safety factors that are not directly based on the risk level associated with the pipeline, while the TCPL criteria utilize pipeline-specific reliability targets. The comparison was conducted using a comprehensive set of TCPL pipeline cases that covered a wide range of diameters (NPS 6 to 42), hoop stress-to-SMYS ratios (0.4 to 0.8) and corrosion densities (0.625 to 6508 features per km). The results show that the LSD criteria perform similarly to the TCPL reliability-based criteria, and that both are generally less conservative than the CSA deterministic criteria.

The results demonstrate that the LSD criteria provide a simple and deterministic procedure that capitalizes on the benefits of more complex reliability analyses in eliminating unnecessary conservatism and focusing on the repairs required to achieve consistent safety levels for all cases. Thus, these criteria will enable operators to maximize risk reduction for the dollar spent.

Commentary by Dr. Valentin Fuster
2018;():V001T03A073. doi:10.1115/IPC2018-78616.

Pipelines passing through hilly-terrain potentially have numerous rock dents. Some of them require further in-ditch investigation. However, in-ditch experience revealed elastic rebounding and re-rounding due to internal pressure that could cause cracking on dent outside surface when rock is removed even after following the commonly used pressure reduction by industry. Such OD-surface cracking in rock dent could pose safety issues to excavation crew and immediate integrity threat due to gas release. A preliminary research was performed to determine the required safe dig pressure level for rock dent excavation and address if there is a gap between the common industry practice for pressure reduction. This research could assist pipeline operators with setting a safe dig pressure level for rock dent excavation.

The research consists of four components. First, detail review of rock dents cracking experience during excavation has been performed and identified relevant parameters that contributed to OD-cracking. Then, performed several rock dent case studies with different dent depths, indenter sizes, internal pressures and developed criterion for OD cracking using Finite Element Analysis. Thirdly, a decision chart was developed for safe rock dent excavation and presented. Finally, full-scale denting tests with internal pressure was conducted to corroborate the safe dig pressure criterion and compared against FEA results. In this paper, all above components are presented with summary of findings and recommendations for future research.

Topics: Pressure , Pipelines , Rocks
Commentary by Dr. Valentin Fuster
2018;():V001T03A074. doi:10.1115/IPC2018-78684.

The pipeline industry is currently taking several approaches to evaluate the integrity of dents, ovalities, or other geometric anomalies identified from in-line inspection (ILI). A primary threat associated with these features that operators should be concerned with is failure due to fatigue. In order to carry out a more accurate dent fatigue analysis, it is important to be able to quantify the amount of damage accumulated during the initial dent formation process and subsequent shakedown of the dent.

Dents result from permanent deformation of the pipeline which leads to accumulation of plastic strain. Whether this permanent deformation was caused during initial construction (a backhoe striking the pipeline) or in service (changing underground soil conditions), the plastic strains that are observed will result in a decrease in the pipeline’s fatigue life. Pressure cycling has the potential to accumulate additional plastic stain, thus accumulating more fatigue damage. Eventually as the pipeline continues to be cycled, no additional deformation or accumulation of plastic strain will occur; this behavior is referred to as “shakedown.”

Finite element analysis (FEA) can be utilized to quantify how much fatigue damage has been accumulated during the initial dent formation process and subsequent shakedown of the dent. When analyzing pipeline dents using FEA, importance should be placed on accurately simulating the dent forming process so that realistic plasticity effects can be captured. The process of calculating plastic stresses and strains during the dent forming process can be computationally expensive and result in numerical instabilities within the analysis.

As a result, methods for simulating the formation and shakedown of a pipeline dent are continuously being refined. However, since it is difficult to determine exactly how these geometric pipeline anomalies were formed, the applicability and accuracy of such methods contains a great amount of uncertainty and is thus expensive (both from a cost and time standpoint) for an operator to validate.

This paper will identify a new and innovative approach for using FEA to determine the amount of damage accumulated during the initial dent formation process and subsequent shakedown of the dent. This approach uses state-of-the-art FEA modeling techniques coupled with industry knowledge and experience to develop an accurate and efficient method for quantifying this damage. The knowledge gained during this analysis can be used in conjunction with a traditional rapid dent assessment methodology.

A case study will be presented which demonstrates the impact that a direct calculation of this initial damage has on representative pipeline dent assessment analysis. By undertaking this additional analysis, operators will have the potential to eliminate unnecessary digs. Additionally, operators can be more confident that their resources are being applied to the highest priority features.

Commentary by Dr. Valentin Fuster
2018;():V001T03A075. doi:10.1115/IPC2018-78691.

Probabilistic fracture mechanics (PFM) analysis can provide insights into the relative benefits of various pipeline integrity management options in reducing the probability of a pipeline failure. For example, a prior analysis (1) showed that In-Line Inspection (ILI) technology can achieve a greater level of safety, at longer reassessment intervals, than other integrity management techniques such as Hydrostatic Pressure Testing in a line subject to an aggressive Stress Corrosion Cracking (SCC) environment in relatively high toughness pipe base material.

This paper extends that study to evaluate the effects of different crack growth mechanisms, such as fatigue crack growth (FCG) in gas and liquid pipelines as well as materials with differing fracture toughness levels (i.e. Seam Welds vs. Base Metal). PFM analysis can address these growth mechanisms and toughness distributions and serve as a valuable tool for weighing the effects of different assessment techniques, repair criteria and reassessment intervals on pipeline integrity. The analysis can also be used to study the effects of probability of detection (POD) of the ILI techniques as well as enhanced repair (dig) criteria. This paper presents a series of case studies to illustrate the utility of the PFM approach for comparing integrity management options for pipelines subject to different crack growth mechanisms and fracture toughness properties.

Commentary by Dr. Valentin Fuster
2018;():V001T03A076. doi:10.1115/IPC2018-78720.

Internal pressure fluctuations during pipeline operations could contribute to crack growth in steel pipelines. These pressure fluctuations create a variable amplitude loading condition with large amplitude cycles at near-zero stress ratio, R (minimum stress / maximum stress) and small amplitude cycles (minor cycles) at near +1 R ratio which can both affect crack propagation. Mean stresses fluctuate with pressure due to fluid friction losses proportional to the distance from the pump/compressor station. A deeper understanding of mean stress sensitivity on crack growth rate in steel pipelines is sought. The aim of this research is to retard crack growth in pipelines by prescribing pressure fluctuations, thus controlling mean stress effects on imperfection growth in steel pipelines under a near neutral pH environment. This study shows that prescriptive mean load pressure fluctuations can be used to reduce crack growth rates in steel pipelines, thus expanding pipeline integrity management methods.

Commentary by Dr. Valentin Fuster
2018;():V001T03A077. doi:10.1115/IPC2018-78723.

The fracture process of energy pipelines can be described in terms of fracture initiation, stable fracture propagation and final fracture or fracture arrest. Each of these stages, and the final fracture mode (leak or rupture), are directly impacted by the tendency towards brittle or ductile behavior that line pipe steels have the capacity to exhibit. Vintage and modern low carbon steels, such as those used to manufacture energy pipelines, exhibit a temperature-dependent transition from ductile-to-brittle behavior that affects the fracture behavior. There are numerous definitions of fracture toughness in common usage, depending on the stage of the fracture process and the behavior or fracture mode being evaluated. The most commonly used definitions in engineering fracture analysis of pipelines with cracks or long-seam weld defects are related to fracture initiation, stable propagation or final fracture.

When choosing fracture toughness test data for use in engineering Fracture Mechanics-based assessments of energy pipelines, it is important to identify the stage of the fracture process and the expected fracture behavior in order to appropriately select test data that represent equivalent conditions. A mismatch between the physical fracture event being modeled and the chosen experimental fracture toughness data can result in unreliable predictions or overly conservative results. This paper presents a description of the physical fracture process, behavior and failure modes that pipelines commonly exhibit as they relate to fracture toughness testing, and their implications when evaluating cracks and cracks-like features in pipelines.

Because pipeline operators, and practitioners of engineering Fracture Mechanics analyses, are often faced with the challenge of only having Charpy fracture toughness available, this paper also presents a review of the various correlations of Charpy toughness data to fracture toughness data expressed in terms of KIC or JIC. Considerations with the selection of an appropriate correlation for determining the failure pressure of pipelines in the presence of cracks and long-seam weld anomalies will be discussed.

Commentary by Dr. Valentin Fuster
2018;():V001T03A078. doi:10.1115/IPC2018-78731.

Having sufficient depth of cover ensures pipeline protection and is a regulatory requirement. Confirming the pipeline depth of cover on dry land is generally easy and produces accurate results. However, determining the pipeline depth of cover at a river crossing can be problematic because of accessibility difficulties and the increased measurement errors from aboveground surveys.

The difficulty of determining the pipeline depth of cover at river crossings can be resolved by integrating both the aboveground survey data and the inline inspection data. By comparing both sets of data, errors from both above survey data and inline inspection data can be detected.

This paper describes watercourse management, aboveground DOC surveys, and a spreadsheet based tool developed for both the quick verification of aboveground survey results, and the calculation of the true DOC at water crossings without needing to set new GPS tie-points on both banks of the crossing and running a new ILI.

Commentary by Dr. Valentin Fuster
2018;():V001T03A079. doi:10.1115/IPC2018-78771.

This paper evaluates field ovalization measurements of NPS 24 pipe using 3D continuum finite element analyses. The combination of the soil backfill weight and loose bedding material beneath the pipe near a tie-in concentrates stresses at the location where native undisturbed soil transitions to loose backfill along the trench bottom, which increases the ovality in the pipe cross section. The analysis indicated that at burial depth, transient surface loading temporarily increases the ovality in unpressurized pipe but the ovality is reduced to near normal levels when the transient surface loading is removed. The internal pressure reduces the elastic pipe ovality. This analysis method can be useful for a cost benefit analysis between using thicker pipe, versus the additional costs, such as intervention and/or padding/compacting of soil around the pipe (with inspections).

Topics: Pipes
Commentary by Dr. Valentin Fuster
2018;():V001T03A080. doi:10.1115/IPC2018-78805.

Mechanical dents often occur in transmission pipelines, and are recognized as one of major threats to pipeline integrity because of the potential fatigue failure due to cyclic pressures. With matured in-line-inspection (ILI) technology, mechanical dents can be identified from the ILI runs. Based on ILI measured dent profiles, finite element analysis (FEA) is commonly used to simulate stresses and strains in a dent, and to predict fatigue life of the dented pipeline. However, the dent profile defined by ILI data is a purely geometric shape without residual stresses nor plastic deformation history, and is different from its actual dent that contains residual stresses/strains due to dent creation and re-rounding. As a result, the FEA results of an ILI dent may not represent those of the actual dent, and may lead to inaccurate or incorrect results.

To investigate the effect of residual stress or plastic deformation history on mechanics responses and fatigue life of an actual dent, three dent models are considered in this paper: (a) a true dent with residual stresses and dent formation history, (b) a purely geometric dent having the true dent profile with all stress/strain history removed from it, and (c) a purely geometric dent having an ILI defined dent profile with all stress/strain history removed from it. Using a three-dimensional FEA model, those three dents are simulated in the elastic-plastic conditions. The FEA results showed that the two geometric dents determine significantly different stresses and strains in comparison to those in the true dent, and overpredict the fatigue life or burst pressure of the true dent. On this basis, suggestions are made on how to use the ILI data to predict the dent fatigue life.

Commentary by Dr. Valentin Fuster

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