bluuebunny/crossref_metadata_2025 huggingface dataset:
API RP 1173 Pipeline SMS Third-Party Assessment Program: A Key Industry Tool for Evaluating and Supporting Implementation of Pipeline Safety Management Systems
Authors: Burr Alexa S. , Toth S. David , Frazier Colin M.
Published: January 2021

Since the publication of API Recommended Practice (RP) 1173: Pipeline Safety Management Systems, in July 2015, the energy pipeline trade groups in North America (American Petroleum Institute, Association of Oil Pipelines, American Gas Association, Interstate Natural Gas Association of America, and the American Public Gas Association) have worked collaboratively to develop tools and programs to assist energy pipeline operators with the development and implementation of Pipeline Safety Management System (Pipeline SMS) programs and processes. These resources include a Planning Tool, Implementation Tool and Evaluation Tool, as well as an industry-developed Maturity Model that describes a continuum of implementation levels, based on conformance to RP 1173 as well as implementation effectiveness.

These resources can be found online and are supplemented by the Pipeline SMS Third-Party Assessment Program developed by API. Applying API’s experiences with successful safety programs in other segments and with significant contributions from the Pipeline SMS Implementation Team (aforementioned trade groups and various industry operators), the Pipeline SMS Third-Party Assessment Program is designed to be a key tool to facilitate Pipeline SMS implementation and to share and benchmark information to drive improvements in safety performance. The assessments also provide the pipeline industry with an objective, third-party option to test their systems and address the conformity auditing (API RP 1173, Section 10.2.2) and performance and maturity evaluation (API RP 1173, Section 10.2.3 to 10.2.5) requirements of the recommended practice. In 2019, pilot assessments were conducted and in 2020 the Assessment Program is being implemented. Through the piloting process, significant insights were gained into the practical application of the industry Maturity Model and how the assessments can contribute to an operator’s journey improving safety performance. Aligning with the flexibility and scalability goals of RP 1173, the pilot experiences included liquids transmission and gas distribution operators with varying approaches to pipeline SMS implementation. We will discuss the lessons learned through the piloting process and how the plan-do-check-act cycle was applied to improve the processes for planning, staffing and conducting the assessments to ensure that value is being provided to the pipeline industry.

An independent assessment through the API Pipeline SMS Third-Party Assessment Program can validate internal efforts to increase maturity of programs, as well as provide operators with benchmarking data so that they can understand where other operators are in their maturity journey.
In Line Inspection in Lieu of Hydrotesting for Low Frequency ERW Pipelines: Developments and Experiences in 12 - and - 22 Inches Pipelines
Authors: LeRoy Marcus , Guajardo Rogelio , Urrea Miguel Santiago , Hennig Thomas
Published: January 2021

Pipeline operators use different approaches, often in combination, to ensure the safe operation of an asset. Historically, hydrostatic testing is the most accepted methodology for assessing critical flaws in a pipeline system, achieved by stressing the pipeline above the standard operating limits. By design, a release during this test removes a critical flaw from the system. There are significant drawbacks to this type of assessment. Such drawbacks include high costs of implementation, feature growth, previously blunt defects sharpening and system downtime. Driven by the operator (Marathon Pipe Line) to investigate alternative approaches, a consortium of (4) parties formed to develop and validate an alternative and enhanced solution.

The research and execution of the project was structured in (4) phases.

• Phase I — Determine which crack morphologies are challenging to ILI technology in terms of detection and depth determination and test initial improvements to ILI technology. This included loop testing improved crack detection ILI robots and destructive assessment with pipe samples to identify gaps in ILI technology and analysis techniques.

• Phase II — Assess vendor improved ILI technology on the operating pipelines using advanced in the ditch non-destructive evaluation (NDE) methods and destructive testing of pipe samples from the pipelines. Identify the additional improvements if necessary.

• Phase III — Implement specific improvements to ILI technology that are completed based on Phase I and II results. Validate the new ILI platform on the specific pipeline.

• Phase IV — Determination whether the new ILI platform can provide equivalent pipe seam system reliability to hydrostatic testing. A probabilistic approach will be used that would account for the expected statistical distribution of pipe properties, fatigue crack growth rates, position along the pipeline, and flaw sizes.

This paper is a summary of the research and work for this ILI In Lieu of a Hydrostatic Testing initiative.
The Study on Non-Heating Transportation of Carbon Dioxide Flooding Pipeline
Authors: Cheng Xianwen , Huang Qiyu , Li Yao , Li Yaping , Liu Xin
Published: January 2021

For most high water-cut pipelines, even if the transportation temperature drops below the gel point of crude oil, the pipeline can still operate safely. Especially when the crude oil has dissolved a certain amount of gas, its flow characteristics are significantly improved, and which can achieve non-heating transportation easily. However, the oil particles will adhere to the pipe wall (which called wall sticking), and become difficult to be swept down with the drop of temperature, which undoubtedly increases the risk of pipe blockage. In order to prevent the occurrence of pipe blockage, it is necessary to find the minimum temperature that allows non-heating transportation.

In the study of non-heating transportation, minimum transportation temperature (MTT) and wall sticking congealed oil amount (WSOA) are the most important research objectives. When the temperature is between the gel point of crude oil and MTT, the crude oil gel only forms a thin oil layer on the pipe wall, which does not affect the safe operation of the pipeline. Once the temperature drops below MTT, a large amount of congealed oil will stick to the pipe wall, reducing the inner diameter of the pipe and increasing the risk of plugging. This paper has studied the effect of carbon dioxide on non-heating transportation and found that the presence of carbon dioxide can make WSOA significantly reduced and the congealed oil becomes softer, but MTT does not change. According to the measurement of the rheological characteristics of crude oil before and after dissolving carbon dioxide, it is believed that the above experimental results may be due to the decrease in viscosity and wax appearance temperature of crude oil after dissolving gas, which hinders the precipitation and aggregation of wax crystals and inhibits the formation of crude oil gel. In addition, it is speculated that the surface of the dissolved gas crude oil is covered with a large number of bubbles. These bubbles will reduce the contact area of the crude oil and the wall surface, resulting in a decrease of WSOA. In a word, the research methods mentioned in this paper are suitable for the study of non-heating transportation of carbon dioxide flooding pipeline.
Ring Expansion Testing Innovations: Hydraulic Clamping and Strain Measurement Methods
Authors: Walsh William , Abotula Sandeep , Konda Bharath
Published: January 2021

Ring expansion testing is one of the three accepted methods in API 5L for the measurement of yield strength for line pipe. The other two are flattened-strap tensile testing and round-bar tensile testing. A novel-concept ring expansion test machine has recently been commissioned which uses hydraulic pressure to clamp the top and bottom pressure-reacting plates rather than a traditional bolting arrangement. The benefit of hydraulic clamping is vastly reduced set-up times. This paper describes the design approach and the pitfalls that were overcome in commissioning the ring expansion test unit. Expansion measurements are taken using two different methods: a chain extensometer and an LVDT with a band wrapping the circumference of the pipe. Both approaches are used simultaneously to generate and compare two stress-strain curves for one pressure test. In addition, a 3-Point contact approach is developed to determine the hoop strain during pipe expansion. The 3-point contact approach is an attempt to infer the full hoop expansion behavior by measuring the radius change over a segment of the circumference. The device has two rollers which contact the pipe surface while a dial indicator midway between measures the radius change. As the pipe expands, the rollers maintain contact with the pipe surface while the dial indicator records the change in radius.

Tests are performed on HFI, SAWL, and SAWH pipes ranging in outer diameter from 20-inch (508 mm) to 48-inch (1219 mm) and wall thicknesses from 0.375-inch (9.5 mm) to 0.969-inch (24.4 mm). The differences in the stress-strain behavior of these pipe forms are described and related to the residual-stress profiles generated by their respective manufacturing operations. The comparison to flattened-strap and round-bar tensile results are presented in a companion paper.

The results of the 3-Point contact approach show that the radius change during early stages of expansion are not uniform around the pipe circumference and different patterns are observed in the HFI, SAWL, and SAWH pipe forms.
Application of a Simplified Constant Crack Tip Opening Angle Model to Crack Propagation Analyses in Steel Pipelines
Authors: Bassindale Chris , Wang Xin , Tyson William R. , Xu Su
Published: January 2021

In this paper, a simplified constant crack tip opening angle (CTOA) model is presented and used to analyze two different pipeline steels. The steels examined in this work were an American Petroleum Institute (API) Standard X65 steel and a Japanese Industrial Standard (JIS) steel with the grade designation of STPG370. The commercial finite element (FE) code ABAQUS 2017x was used to generate the models and solve the analyses. The proposed propagation model was first verified through comparing the numerical results with published data. The steady-state fracture velocity data from the simplified model matched the data from literature within a maximum difference of 2% while drastically reducing the computational time required by an order of magnitude. Following the verification of the simplified model, it was then used to analyze recent experimental data. The model was able to match the experimental crack velocity data within a difference of 4%.
Managing the Threat of Selective Seam Weld Corrosion Using a State of the Art ILI System
Authors: Davies Christopher , Slater Simon , De Leon Christoper
Published: January 2021

For many years, pipeline safety regulations in the US have defined prescriptive minimum requirements for integrity management combined with a clear expectation that operators should do more than the minimum where appropriate. The regulations have also provided operators with the flexibility to take a performance based integrity management approach leveraging as much information available to manage threats effectively. One the threats that must be managed is Selective Seam Weld Corrosion (SSWC). SSWC is an environmentally assisted mechanism in which there is increased degree of metal loss in the longitudinal weld in comparison to the surrounding pipe body. An appropriate definition is linear corrosion that is deeper in the longitudinal weld zone than the surrounding pipe body. In some cases, the surrounding pipe body may have limited or no corrosion present, and in other cases the pipe body corrosion may have occurred but at a slower rate than the local corrosion in the longitudinal weld zone. Conventional responses to potential or identified threats focus on in-situ investigations, often resulting in expensive and un-planned repairs for features reported by In-line Inspection (ILI) that when assessed properly demonstrate a remnant life well into the next inspection interval. When ILI identifies metal loss indications co-located with the longitudinal seam weld, the current prescribed response is often a blanket call for remediation. Such a response may not be appropriate if an ILI system is deployed to discriminate feature types and integrity assessment is exercised leveraging a sound understanding of the pipe’s material properties. This paper describes an approach that can be taken to manage the threat of SSWC. The foundation of the approach is deployment of an appropriate ILI system incorporating an effective ILI technology, an optimized evaluation process considering the specific threat morphology, material testing and a structured dig program. The evaluation process uses the ILI data and data from the field in combination material properties data and a susceptibility analysis to classify anomalies as “Likely”, “Possible” and “Unlikely” SSWC. This is aligned with the guidance in API RP 1176 “Assessment and Management of Cracking in Pipelines” for defining an appropriate response to ILI calls. Approaching the management of SSWC in this way allows operators to define a structured response for excavation activities to verify the process and remediate features as required. By using likelihood classification the risk to pipeline integrity can be reduced by acting on the most likely SSWC features as a priority, whilst collecting the data needed to make informed decisions on where to focus resources and efforts on what is a very complicated and difficult to manage threat. The output form this work, including a future plan for managing the remaining metal loss features, can be documented in a procedure and incorporated into an existing Integrity Management Plan.
MAOP Reconfirmation for a 20 Inch Gas Pipeline Using the ECA Method and Enhanced ILI
Authors: Slater Simon , Davies Chris , Burkinshaw Ollie , Clyde Peter , Griffen John
Published: January 2021

In light of the revised Federal Pipeline Safety Regulations, active from July 1, 2020, operators of gas transmission pipelines are faced with the task of reconfirming pipeline MAOP in a prescriptive set of circumstances. This requirement is defined in section 192.624 of 49 CFR 192. Louisville Gas & Electric (LGE) is operating a pipeline with an MAOP established using a combination of partial and full traceable, verifiable and complete (TVC) documentation and the ‘grandfathering’ clause defined by 192.619(a)(3). LGE has developed a plan and embarked on the process of reconfirming the MAOP using Method 3 – Engineering Critical Assessment (ECA). The pipeline is 20 inch diameter and predominately 0.25 inch wall thickness. It was originally constructed from vintage ERW pipe circa. 1960 to 1970 and is 29.86 miles long. There have been no reportable incidents on the line. There are various HCAs, Class 3 and Class 4 locations, and newly defined MCAs (per 192.3) along the line. The approach taken by the operator is to reconfirm the MAOP along the full pipeline length to cover the possibility of class location changes in the future. MAOP Reconfirmation via method 3 is detailed in clause 192.632. A critical element of an ECA per method 3 is the implementation of various ILI technologies to detect, identify, and size target threats. ROSEN provided an enhanced program of ILI including technologies to assess material properties, and crack-like/metal-loss anomalies. A critical aspect of method 3 is the use of appropriate material properties in the ECA. The operator deployed the RoMat PGS ILI system as the foundation for material property verification process to fulfill the requirements of clause 192.607 of 49 CFR 192, a requirement to establish ‘unknown material properties’. This paper describes the comprehensive work performed by the partnership of ROSEN and LGE to establish and fulfill the MAOP reconfirmation process. Such a large ILI program is a significant undertaking considering the associated data-integration, operational and engineering details that have to be addressed. This paper presents the methodologies used for each stage of the ECA process and how the ILI and material verification results were used to determine predicted failure pressures and remaining life. By satisfying the regulations, the operator has established a process to manage pipeline integrity, reduce risk, and reconfirm MAOP.
Recommendations for Jet Fire Model Selection When Performing Consequence Assessments of Onshore Natural Gas Pipelines and Facilities
Authors: Smith Shawn , Fraser Alex M. , Shironishi Mari
Published: January 2021

The thermal radiation from a jet fire is the dominant hazard resulting from accidental natural gas releases from onshore pipelines or facilities. To assess the consequences to both individuals and equipment, we require models to estimate the incident radiation from the jet fire to the surroundings. Simpler models with shorter implementation and run times are more viable for use in a full probabilistic risk assessment, in which the number of scenarios assessed could number in the millions. However, the level of accuracy within these models must be considered to ensure a reasonably conservative estimate is produced. A review and comparison of semi-empirical models from literature was performed and used to develop a decision tree to recommend the most computationally efficient jet fire modelling approaches based on the release scenario, while maintaining reasonable conservatism. Options for both vertical and non-vertical releases are presented, as well as corrections for lift-off, wind, and buoyancy. Additionally, an efficient algorithm from the area of computer graphics was adapted and applied to a weighted multiple point source jet fire model to account for the reduction in incident radiation to a receptor due to topography or structures partially obstructing the view of the jet fire.
A Midstream Pipeline Operator’s Perspective on the Implementation of API 1183
Authors: Konell Jeremiah , Dedeke Brian , Hurst Chris , Wu Shanshan , Bratton Joseph
Published: January 2021

In preparation for the upcoming (currently in draft form) Recommended Practice (RP) on Dent Assessment and Management (API 1183) [1], Explorer Pipeline Company, Inc. (Explorer) has performed an internal procedural review to determine how to effectively implement the methodologies into their Integrity Management Program (IMP). Explorer’s pipeline system transports hazardous liquids and is comprised of over 1,800 miles of pipeline ranging in diameter from 3 to 28 inches. The majority of the system was installed in the 1970s, but parts of the system were also installed as early as the 1940s. The primary focus of this review and implementation into the IMP is in regard to performing and responding to in-line inspection (ILI) based integrity assessments.

Prior to the development of API 1183, dent assessment and management consisted of following a set of prescriptive condition assessments outlined in the Code of Federal Regulations (CFR) Title 49, Part 195.452. In order to do this, pipeline operators required basic information, such as dent depth, orientation, and interaction with potential stress risers such as metal loss, cracks, gouges, welds, etc. However, in order to fully implement API 1183, additional parameters are needed to define the dent shape, restraint condition, defect interaction, and pipeline operating conditions.

Many new and necessary parameters were identified throughout the IMP, from the very initial pre-assessment stage (new ILI vendor requirements as part of the tool/vendor selection process) all the way to defining an appropriate reassessment interval (new process of analyzing dent fatigue life).

This paper summarizes the parameters of API 1183 that were not part of Explorer’s current IMP. The parameters are identified, and comments are provided to rank the level of necessity from “must have” to “beneficial” (e.g. can sound and conservative assumptions be made when a parameter is not available). Comments are also provided to explain the impact of applying assumptions in place of parameters. The table of identified parameters should provide a useful tool for other pipeline operators who are considering implementing API 1183 as part of their overall IMP.
Returning Pipelines to Service Following a Mw7.5 Earthquake: Papua New Guinea Experience
Authors: Albrecht Robert , Birthwright Rhys-Sheffer , Calame John , Cloutier Justin , Gragg Michael
Published: January 2021

The Papua New Guinea Liquefied Natural Gas (PNG LNG) project is a joint venture with participation by ExxonMobil, Oil Search Limited (OSL), Kumul Petroleum, Santos, JX Nippon Oil and Gas Exploration and Mineral Resources Development Company, and began production in 2014. As described in a previous IPC paper, the project, operated by ExxonMobil PNG Limited (EMPNG) sustained a M7.5 earthquake and approximately 300 aftershocks in 2018, epicentered directly under key facilities. Around 150 km of high-pressure gas and condensate pipelines in the rugged PNG highlands were affected but did not lose containment or pressure. Immediately following the M7.5 event, EMPNG began efforts to assess and inspect the pipelines in order to ensure public safety, and, at the appropriate time, restore LNG production. The technical efforts took place along the pipeline Right of Way (ROW) in a remote jungle environment, which, following the earthquake, was also a disaster zone in which the few available resources were prioritized towards humanitarian relief. Due to resource constraints, the pipeline field inspection team typically numbered only two or three specialists.

The inspection team drew heavily on analysis work, ongoing since project startup in 2014 and in progress when the earthquake occurred, that simulated the condition of the ROW and pipe stress state following earthquake events similar in magnitude to what actually occurred. The body of existing analysis work allowed the field team to compare aerially observed ROW ground movements to previously modeled cases, and rapidly infer pipe stress state without actually measuring pipe deformation on the ground. Due to resource constraints, that latter activity, if required before startup, would have significantly delayed project restart. The worldwide network of technical resources that had been assisting with ongoing simulations was quickly re-directed to analyzing actual observed ground deformations, efficiently supporting the small field team from outside the disaster zone.

After restart, field inspection activities continued, observations were categorized, and an Earthquake Recovery (EQR) organization was initiated to execute ROW repairs. Just as the initial inspection work was aided by pre-earthquake analyses, EQR activities have been expedited by the extensive ROW maintenance program that had been ongoing prior to the earthquake.

This paper and accompanying oral presentation present details of the inspection and recovery, and show that the extensive simulations, preparations and maintenance programs supported by EMPNG during project operations prior to the earthquake enabled a rapid and efficient response when the earthquake actually occurred, and thus provided enormous value to the business.
The Impact of Pressure Fluctuations on the Early Onset of Stage II Growth of High pH Stress Corrosion Crack
Authors: Niazi Hamid , Zhang Hao , Lamborn Lyndon , Chen Weixing
Published: January 2021

Steel pipelines undergo the following sequential stages prior to high pH stress corrosion cracking (HpHSCC) failure, viz., formation of environmental condition, initiation of the intergranular cracks followed by cracks coalescence to form critical crack size (Stage I), mechanically dictated crack growth with higher rate (Stage II) compared to Stage I, rapid crack propagation to failure (Stage III). From fracture mechanics perspective, the crack size reaches the critical value at the onset of stage II; consequently, stress intensity factor (K) ahead of the crack tip exceed the critical value (KISCC). Although many researches have been devoted to understanding HpHSCC behavior, the mechanical conditions that accelerate the onset of stage II remains unknown. This study investigates the mechanical loading conditions that yield to early onset of stage II with respect to the most severe loading condition in operating pipeline, underload-minor-cycle type of pressure fluctuation. In this study, several loading scenarios were applied to pre-cracked CT specimens exposed to 1 N NaHCO3-1N Na2CO3 at 40° C and −590 mVSCE. The first series of tests were conducted through applying variable amplitude loading waveforms to determine the K value below the KISCC. It was observed the crack growth rate decreases from 1.5 × 10−7 mm/s to 2.5 × 10−8 mm/s when Kmax decreases from 36 to 15 MPa·m0.5. Then, both constant amplitude and variable amplitude loading scenarios with the Kmax = 15 MPa·m0.5 were applied to pre-cracked CT specimens. It was observed that low R-ratio constant amplitude cycles yield to highest crack growth rate (3.6 × 10−7 mm/s), which was one order of magnitude higher than other waveforms. However, comparing the intergranular crack advancement per block resulted in similar crack growth rates for those waveforms containing low R-ratio cycles. These results imply that stage I of crack growth is assisted by fatigue due to low R-ratio cycles. It was observed that loading/unloading frequency of low R-ratio cycles has a direct relation with crack growth rate at stage I, i.e., high frequency cycles accelerate onset of stage II. The implication of these results for pipeline operator is that pressure fluctuation, particularly large and rapid pressure fluctuation at the sites susceptible to HpHSCC, threatens the pipeline integrity. Avoiding such pressure fluctuations, if possible, increase pipeline lifespan and prevents catastrophic damages by intergranular stress corrosion crack growth through delaying the onset of stage II of HpHSCC crack growth.
Intelligent Prevention Method for Third-Party Damage of Long-Distance Pipeline Based on Mobile Devices Location Information
Authors: Ling Jiatong , Zhang Hang , Dong Shaohua , Luo Jinheng
Published: January 2021

As one of the main risks of long-distance oil and gas pipelines, the consequences of pipeline accidents caused by third-party damage (TPD) are usually catastrophic. At present, TPD prevention approaches mainly include manual line patrol, fiber-optical vibration warning, and unmanned aerial vehicle (UAV) line patrol, but there are some limitations such as untimely warning, false alarm, and the missed report. As the location technology of mobile device matures, the user group provides massive data sources for the collection of location information, with which the tracks and features of the third-party activity along the pipeline can be directly obtained. Therefore, this paper proposes a method to identify the TPD behavior based on the location data of mobile devices. Firstly, the characteristics of relevant destruction behaviors were extracted from the historical destruction events. Then, the location information of the third-party activity near the target pipeline is obtained and the data is processed to remove the influence of noise, to reduce the computational burden of the subsequent identification process. Finally, calculate the difference degree of neighborhood trajectory and the similarity with the TPD features based on the data feature grouping (Difference feature and Similarity feature) to classify the type of third-party activity. Taking a 10km pipeline segment as an example, the method of this paper is used to preprocess the collected data and calculate the difference degree and similarity, 232 suspected TPD events are identified. After the on-site verification of the suspected damage by the line patrol, the results show that the method can better identify the third-party activities near the pipeline.
Modeling of Advanced Ultrasonic Testing Methods for Improved Characterization of Pipeline Damage
Authors: Van Velsor Jason K. , Malinowski Owen M. , Riccardella Scott A. , Velandia Luis , Kania Richard
Published: January 2021

Characterizing the performance of nondestructive evaluation (NDE) methods for the in-ditch detection and characterization of stress corrosion cracking (SCC) and other damage types has proven challenging for several reasons. Firstly, the availability of pipeline samples with real damage is limited. Compounding this issue, real samples often need to be destructively evaluated to establish the true damage characteristics such that the performance of the NDE methods can be properly understood. Destructive testing is both costly and results in the loss of valuable test samples. Secondly, the actual application of NDE methods to real samples has been shown to have significant human performance variations, which are difficult to separate from technology performance. To address these challenges, this work reviews advanced ultrasonic NDE modeling tools that have been developed to assist in benchmark studies for characterizing crack-like defects, such as SCC, and for establishing best practices. Specifically, explicit/dynamic finite element modeling techniques are utilized to model and compare traditional phasedarray ultrasonic testing (PAUT) and the newer full-matrix capture (FMC) PAUT techniques, such as the total focusing method (TFM). Insights into performance levels of the different modeled approaches are reviewed and guidance on the optimal application of these approaches is discussed.
Reliability-Based Assessment Method of Buried Pipeline at Fault Crossings
Authors: Zheng Qian , Liu Xiaoben , Zhang Hong , Adeeb Samer
Published: January 2021

The tectonic fault, which is one of the most common geohazards in field, poses great threat to buried pipe segments. Pipes will process to buckling or fracture due to large strain induced by continuously increasing ground displacements during earthquakes. Therefore, it is imperative to conduct safety analysis on pipes which are buried in seismic areas for the sake of ensuring normal operation. However, the highly nonlinearity of pipe response restricts the proceeding of reliability assessment. In this study, a hybrid procedure combining finite element method and artificial neural network is proposed for reliability-based assessment. First of all, the finite element model is developed on ABAQUS platform to simulate pipe response to strike-slip fault displacements. Thus, the strain demand value (the peak strain value obtained by finite element model in each design case) can be collected for database establishment, which is the preparation for neural network training. Thoroughness of the strain demand database can be achieved by a fully comprehensive calculation with consideration of influencing factors involving pipe diameter and wall thickness, operating pressure, magnitude of fault displacement, intersection angle between pipeline and fault plane, and characteristic value of backfill mechanics. Sequentially, Back Propagation Neural Network (BPNN) with double hidden layers is trained based on the developed database, and the surrogate strain demand prediction model can be obtained after accuracy verification. Hence, the strain-based limit state function can be respectively determined for tensile and compressive conditions. The strain capacity term is simply assumed based on published papers, the strain demand term is naturally superseded by the surrogate BPNN model, and Monte Carlo Simulation is employed to compute the probability of failure (POF). At last, the workability of the proposed approach is tested by a case study in which basic variables are referred to the Second West-to-East natural gas transmission pipeline project. It indicates that ANN is a good solver for reliability problems with implicit limit state functions especially for highly nonlinear problems. The proposed method is capable of computing POFs, which is an exploratory application for reliability research on pipes withstanding fault displacement loads.
Case Study of “TIEAMM” Approach to Geohazard Identification, Characterization, and Mitigation
Authors: Nasrallah Joshua , Theriault Bailey , Kammereck Andreas
Published: January 2021

This study presents the implementation of a multidisciplinary team approach to geohazard identification, characterization, assessment, and mitigation \, that includes landslide subject matter experts (SMEs) in geotechnical and hydrotechnical engineering and geology and pipeline stress analysis with the pipeline owner/operator (Owner). This approach provided targeted and programmatic geohazard training, identification, exploration, assessment, mitigation, and monitoring, and hase been coin as the “TIEAMM” approach. The Owner worked with the geohazard SMEs to develop a system-wide geohazard pipeline integrity management program, including a phased geohazard assessment along the right-of-way, office and field-based training for the local operations staff, risk-based design mitigation approaches, on-site construction support, and continued monitoring.

The landslide discussed in this study is used as an example to demonstrate the TIEAMM approach; this site was identified by local operations staff, documenting differential movement of approximately 15 feet between November 2018 and February 2019. A more detailed geological exploration and assessment as well as a pipeline strain assessment was completed. The work allowed for mitigation efforts and corresponding costs to be optimized. The mitigation design was flexible to address ongoing monitoring, and then field-fit to address site conditions observed during the construction work. The approach to geohazard management completed for this site provided the data and information needed to make informed decisions to support targeted optimization for the scope and scale of mitigation work, and thereby avoided over-conservative (and thereby overly-costly) mitigation efforts.
Optimizing the Management of Excavation and Repair Data From Inline Inspection Programs
Authors: Safari Miaad , Shaw David
Published: January 2021

As integrity programs mature over the life of a pipeline, an increasing number of data points are collected from second, third, or further condition monitoring cycles. Types of data include Inline Inspection (ILI) or External Corrosion Direct Assessment (ECDA) inspection data, validation or remediation dig information, and records of various repairs that have been completed on the pipeline system. The diversity and massive quantity of this gathered data proposes a challenge to pipeline operators in managing and maintaining these data sets and records.

The management of integrity data is a key element to a pipeline system Integrity Management Program (IMP) as per the CSA Z662[1]. One of the most critical integrity datasets is the repair information. Incorrect repair assignments on a pipeline can lead to duplicate unnecessary excavations in the best scenario and a pipeline failure in the worst scenario. Operators rely on various approaches to manage and assign repair data to ILIs such as historical records reviews, ILI-based repair assignments, or chainage-based repair assignments. However, these methods have significant gaps in efficiency and/or accuracy. Failure to adequately manage excavation and repair data can lead to increased costs due to repeated excavation of an anomaly, an increase in resources required to match historical information with new data, uncertainty in the effectiveness of previous repairs, and the possibility of incorrect assignment of repairs to unrepaired features.

This paper describes the approach adopted by Enbridge Gas to track and maintain repairs, as a part of the Pipeline Risk and Integrity Management (PRIM) platform. This approach was designed to create a robust excavation and repair management framework, providing a robust system of data gathering and automation, while ensuring sufficient oversight by Integrity Engineers. Using this system, repairs are assigned to each feature in an excavation, not only to a certain chainage along the pipeline. Subsequently, when a new ILI results report is received, a process of “Repair Matching” is completed to assign preexisting repairs and assessments to the newly reported features at a feature level. This process is partially automated, whereby pre-determined box-to-box features matched between ILIs can auto-populate repairs for many of the repaired features.

The proposed excavation management system would provide operators a superior approach to managing their repair history and projecting historical repairs and assessments onto new ILI reports, prior to assessing the ILI and issuing further digs on the pipeline. This optimized method has many advantages over the conventional repair management methods used in the industry. This method is best suited for operators that are embarking on their second or third condition monitoring cycle, with a moderate number of historical repairs.
A Quantitative Index to Assess the Influence of Joint Fit-Up on Pipeline Weld Root Discontinuities
Authors: Grams M. R. , Ludwig L. , Mendez P. F.
Published: January 2021

Field experience on pipelines suggests that under the unique conditions of tie-in welding, a high-low offset at the inner pipe wall is related to an increased occurrence of latent root weld discontinuities such as cold cracking. Codes and standards offer conflicting and unclear guidelines regarding acceptance criteria for high-low offset. This study presents a numerical index to quantify the influence of non-ideal joint geometry on the latent discontinuity susceptibility of the root pass for circumferential pipeline welds. The index is based on the stress concentration at the root and the angular distortion associated with plastic strains produced during welding. This index relates geometric considerations such as pipe diameter, wall thickness, and the cross section of the root pass with welding procedure variables and the mechanical properties of the pipeline material. Although this study is meant for steel pipelines, the conclusions obtained are also applicable to other materials. The index presented is a contribution towards an objective criterion for acceptance of high-low offset during field welding, ranking the susceptibility to latent discontinuities as a function of variables available to practitioners during field welding.
Structured Response Plan After a Ground Movement Event
Authors: Wang Yong-Yi , Yu Dunji , Cook Mike
Published: January 2021

The vast majority of buried pipelines are not designed to accommodate significant localized ground movement caused by landslides, earthquakes, or subsidence/settlement. When a ground movement event occurs along the ROW of a buried pipeline, it is imperative that the pipeline operator determine whether the ground movement is a threat to pipeline integrity to protect those responding to the event, those living near the affected ROW, and the environment.

This paper covers the development of a response plan that provides guidance to pipeline operators responding to a ground movement event while considering the unique conditions associated with such events.

The response plan covers some critical decisions after an event, including, but not limited to (1) whether the event affects the pipeline, the local ROW, or those living adjacent to the ROW, (2) control of flow, i.e., the need for shutdown or pressure reduction, and (3) work needed to return the line to full-pressure service. The overall response plan is presented in three main phases:

• Phase 1: Immediate Response,

• Phase 2: Follow-on Assessment and Actions, and

• Phase 3: Long-term Management.

The structured response plan and associated guidance are presented in a self-contained stand-alone document available from PRCI. Parts of the document or the entire document can be adopted by operators, depending on the extent of existing procedures an operator may have. Alternatively, company-specific information and procedures can be added to the document to form a company-specific SOP.
Pipeline Multi-Parameter Decision Making Approaches
Authors: Abdolrazaghi Mona , Hassanien Sherif
Published: January 2021

Pipeline operators sometimes face challenges in finding an optimum decision while executing both capital and operational projects. Utility- and risk-based decision-making approaches could create a framework for devising an optimum solution, especially in cases involving multi-parameter decision making. From a utility function perspective, an optimum solution would be the one with the least amount of cost and the highest benefit. In other words, an optimum solution could be achieved by maximizing a utility function. Accordingly, as an optimization problem, constraints related to safety, risk, and reliability for a given scenario could limit or dictate the space of feasible solutions. Addressing the problem of arriving at an optimum solution for a multi-parameter decision is the core topic of this paper. Moreover, optimized utility functions — decision making analyses based on probabilistic risk assessment — are discussed. In addition, the paper introduces a conceptual approach that has been utilized for infrastructure decision making: the life quality index (LQI) approach.
Pipeline Fracture Control Concepts for Norwegian Offshore Carbon Capture and Storage
Authors: Gruben Gaute , Macdonald Kenneth , Munkejord Svend T. , Skarsvåg Hans L. , Dumoulin Stephane
Published: January 2021

The Northern Lights onshore terminal will initially receive CO2 transported by ship tankers from industrial source sites located in south-eastern Norway and transport CO2 via a 12 ¾” OD offshore pipeline for injection into the Johansen storage reservoir, located south of the Troll field. The CO2 injection pipeline will be laid from the shore terminal to a subsea wellhead structure from where the liquid CO2 will be injected into the reservoir. Presently, demonstrating arrest of longitudinal propagating shear fracture in CO2 transport pipelines is specifically addressed in two international guidelines, ISO 27913 and DNVGL-RP-F104. The study reported here aims to develop a robust fracture control methodology unique to the Northern Lights pipeline. To this end, the maximum loading in terms of saturation pressure is conservatively estimated from temperature and pressure scenarios from the planned pipeline route and applied in numerical simulations of the running-fracture phenomenon using the SINTEF coupled FE-CFD code. It is shown that, with the given pipe material, diameter, and loading conditions, the proposed wall thickness of 15.9 mm is sufficient to arrest a propagating crack. Furthermore, the Battelle TCM with ISO 27913 or DNVGL-RP-F104 arrest- and load pressure correction is shown to provide a good first estimate in pipe design, although the arrest pressure saturates for low Charpy energy toughness values, indicating limited accuracy in this study.
In-Liquid Laser Nanomachining by Photonic Nanojet in Laser Trapping System
Authors: Rahman Reza Aulia , Uenohara Tsutomu , Mizutani Yasuhiro , Takaya Yasuhiro
Published: January 2021

Direct laser machining in sub-micron scale patterning at a surface of material remains a challenging task though the laser machining has been widely applied in various application. A photonic nanojet becomes a promising way to solve the problem by involving near-field focusing of light waves below the surface of a dielectric microsphere to fabricate pattern in micro- and nanometer size. By generating laser power to the microsphere and controlling the resulting photonic nanojet intensity distribution and position related to the workpiece, intended ablation size on the material could be controlled at the sub-micrometer scale. In this study, liquid is proposed as photonic nanojet machining medium due to several advantages that liquid offer during machining process. Laser trapping system is then introduced to the optical system to control the position of the microsphere during machining process. An in-liquid nanomachining by generating photonic nanojet in laser trapping configuration is a subject to study with the effect on the resulting ablation and viability of machining process from a set of parameters are investigated numerically using finite-difference time-domain (FDTD) technique. According to the findings of this study, nanometer scale, flexible, and fast novel laser nanomachining could be realized by combining photonic nanojet machining and laser trapping technique.
Effects of Position and Orientation Errors of Linear and Rotary Axis Average Lines of Five-Axis Controlled Machining Centre Onto its Motion Errors in Testing Method With Truncated Square Pyramid
Authors: Kikkawa Koichi , Mori Naoki , Mizugaki Yoshio , Ozaki Keisuke
Published: January 2021

In this paper, ‘position and orientation errors of linear and rotary axis average lines’ is newly named ‘geometrical mechanism deviations.’ This paper presents suggestive simulation results of tool motion error caused by geometrical mechanism deviations of a five-axis controlled machine tool. Firstly, there were assumed seven geometrical mechanism deviations consisting of three positional and four angular deviations. As positional deviations, the error of intersection is set to be 0.01 [mm] off-centre, and the squareness errors of the cross axes as angular deviations are 0.01 [°]. Secondly, there was simulated theoretically the shape of machined pyramidal surface according to the virtual cutter movement of a flat end mill along contouring tool paths. Thirdly, the correspondence of geometrical mechanism deviations and simulated flatness error was analysed and found to have two regularities. One of the two indicated that four pyramidal surfaces wave similarly with left half surface up and right half surface down. The other indicated that the centre of a specific pyramidal surface should be concave in the cases of squareness error between B-Z axes. Through the analysis of grouped flatness error, specific geometrical mechanism deviations seem to cause a particular deformation of pyramidal surface due to the misalignment of tool position and orientation.
Effect of Steady Rest in Cylindrical Traverse Grinding of Slender Workpiece
Authors: Fujii Hidetaka , Onishi Takashi , Lin Chinhu , Sakakura Moriaki , Ohashi Kazuhito
Published: January 2021

In the case of traverse grinding of a slender workpiece, the ground workpiece is easily deformed by the normal grinding force due to its low stiffness. To reduce the form error caused by the elastic deformation of the workpiece, a steady rest is widely used. Generally, a steady rest is set to push the ground area of the workpiece. However, the stepped shape error is generated at the contact point where a steady rest pushed the workpiece because the pushing force of a steady rest is decreased after the material of the contact point is removed. In this study, to reduce the stepped shape error of the ground workpiece, we proposed a new method to set a steady rest. In this method, the steady rest was set to push the area where was not ground. In addition, the traverse speed of the workpiece was adjusted to keep the elastic deformation of the workpiece constant. The suitable method to control the traverse speed was estimated by using a beam model that could simulate the elastic deformation of the workpiece during the grinding process. It was confirmed that the new method could improve the form accuracy of a slender workpiece through grinding experiments.