bluuebunny/crossref_metadata_2025_split huggingface dataset:
An ILI Based Program That Prevents Reoccurrence of Post ILI Failures Seen in Industry
Authors: Huang Terry , Kariyawasam Shahani 
Published: November 2018

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.
Development of Reliability-Based Criteria for Corrosion Assessment
Authors: Adianto Riski , Nessim Maher , Lu Dongliang 
Published: November 2018

Reliability-based corrosion assessment criteria were developed for onshore natural gas and low vapor pressure (LVP) pipelines as part of a joint industry project. The criteria are based on the limit states design (LSD) approach and are designed to achieve consistent safety levels for a broad range of pipeline designs and corrosion conditions.
The assessment criteria were developed for two corrosion limit states categories: ultimate limit state, representing large leaks and ruptures; and leakage limit state, representing small leaks. For the ultimate limit state, a safety class system is used to characterize pipelines based on the anticipated severity of failure consequences as determined by pressure, diameter, product, population density and environmental sensitivity. Since the leakage limit state does not result in significant safety or environmental consequences, a single reliability target, applicable for all pipelines at all locations is used.
The assessment criteria formulations are characterized by three elements: the equations used to calculate the characteristic demand (i.e. operating pressure) and capacity (i.e. burst pressure resistance at a corrosion feature); the characteristic values of the key input parameters for these formulas (such as diameter, pressure and feature depth); and the safety factors defining the characteristic demand as a ratio of characteristic capacity. The process used to calibrate safety factors and characteristic input parameter values that meet the desired reliability levels is described, and an assessment of the accuracy and consistency of the resulting checks in meeting the reliability targets is included.
The assessment criteria include two methods of application: feature-based and section-based. The feature-based method divides the allowable failure probability equally between all features. It is simple to use, but conservative in nature. It is suitable for pipelines with a small number of corrosion features. The section-based method considers the failure probability of the corrosion features in a pipeline section as a group, and ensures that the total group failure probability is below the allowable threshold for the section. This method produces less conservative results than the feature-based method, but it requires more detailed calculations. It is suitable for all pipelines, and is particularly useful for those with a large number of features. The practical implications of the application of these criteria are described in the companion paper IPC2018-78608 Implementation of Reliability-based Criteria for Corrosion Assessment.
Experimental Evaluation of Blasting Near Pipelines
Authors: Gossard Justin , Waters Steven A. , Finneran Shane 
Published: November 2018

Construction blasting was proposed as a technique to create a trench for a new pipeline within the right-of-way (ROW) of an existing vintage pipeline where soil conditions consisted primarily of rock. Several field experiments were conducted to assess the potential loading conditions that the vintage pipeline could experience due to various blasting configurations as part of the nearby construction process. Two test pipe segments were constructed from segments removed from the vintage pipeline for use in these experiments. Each test segment contained two vintage bell-bell chill ring girth welds (GW) and were pressurized to operating conditions of the vintage pipeline for the duration of all blasting. Groups of eight resistive strain gages were bonded around the exterior surface of three distinct locations on each test segment. The three locations include one pipe body location and each of the two welds on each segment.
Four separate experiments were conducted with each experiment focusing on a unique combination of trench backfill material, compaction level and separation distance from the test pipe segments and the explosive charges. The primary objective throughout these four experiments was to monitor and record the behavior of buried test pipe sections due to nearby blasting activities. Long range 3-dimentional (3D) laser scanning equipment was used to track movement of each test segment from test to test. High-speed video equipment was also employed to capture each blast. The high-speed video provided additional details on the blast energy transfer, verification of individual charge initiation as well as pipeline test segment movement where each pipeline segment was exposed. Peak particle velocity measurements were taken during each test blast. Strain data collected during each test was used to assess potential damage to the vintage pipeline test segments as a result of blasting.
The combined information collected from the in-field testing showed that elevated strains and stresses may be observed during blasting activities near pipelines.
Simulation of a Full-Scale CO2 Fracture Propagation Test
Authors: Gruben Gaute , Dumoulin Stephane , Nordhagen Håkon , Hammer Morten , Munkejord Svend T. 
Published: November 2018

In this study, we present results from a numerical model of a full-scale fracture propagation test where the pipe sections are filled with impure, dense liquid-phase carbon dioxide. All the pipe sections had a 24″ outer diameter and a diameter/thickness ratio of ∼32. A near symmetric telescopic set-up with increasing toughness in the West and East directions was applied.
Due to the near symmetric conditions in both set-up and results, only the East direction is modelled in the numerical study. The numerical model is built in the framework of the commercial finite element (FE) software LS-DYNA. The fluid dynamics is solved using an in-house computational fluid dynamics (CFD) solver which is coupled with the FE solver through a user-defined loading subroutine. As part of the coupling scheme, the FE model sends the crack opening profile to the CFD solver which returns the pressure from the fluid. The pipeline is discretized by shell elements, while the backfill is represented by the smoothed-particle hydrodynamics (SPH) method. The steel pipe is described by the J2 constitutive model and an energy-based fracture criterion, while the Mohr-Coulomb material model is applied for the backfill material. The CFD solver applies a one-dimensional homogeneous equilibrium model where the thermodynamic properties of the CO2 are represented by the Peng-Robinson equation-of-state (EOS).
The results from the simulations in terms of crack velocity and pressure agree well with the experimental data for the low and medium toughness pipe sections, while a conservative prediction is given for the high-toughness section. Further work for strengthening the reliability of the model to predict the arrest vs. no-arrest boundary of a running ductile fracture is addressed.
Practical Improvements to Surface Loading Assessment: Building Accuracy, Efficiency and Transparency
Authors: Klementis Jennifer D. , Zhang Shenwei , Law Jonathan , Pino Maria , Yan Jason 
Published: November 2018

This paper presents a tool for surface loading stress analysis that was developed in-house by TransCanada (TCPL). This tool utilizes fundamentals of the surface loading assessment method developed by Kiefner & Associates Inc. (KAI) for Canadian Energy Pipeline Association (CEPA), but incorporated many advanced functionalities to improve the accuracy, efficiency and transparency of the analysis. The new functions of the tool include the batch analysis, multiple angle analysis, generic/site-specific loading analysis, graphical display of stress distributions for refined assessment, user-defined impact factor and automated reporting for documentation of surface loading calculations. This tool also incorporated the improved numerical algorithm for longitudinal global bending stress considering the actual live load pressure distribution over a certain length of pipeline.
The accuracy of the developed tool was validated by comparing it to the KAI tool. The improved algorithm for longitudinal global bending stress calculation reduces the conservatism of the longitudinal global bending stress compared to the original simplified method but does not sacrifice safety, which has been demonstrated by comparison with the experimental results. The new functionalities improved the business efficiency and maintains safety and regulatory compliance.
Development of an Industry Test Facility and Qualification Process for ILI Technology Evaluation and Enhancements: Performance Evaluation Phase
Authors: Cazenave Pablo , Gao Ming , Deeb Hans , Black Sean 
Published: November 2018

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.
Using Finite Element Analysis to Prioritize ILI Calls for Combined Features: Dents in Bends
Authors: Kemp David , Gossard Justin , Finneran Shane , Bratton Joseph 
Published: November 2018

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.
Integrating a Pipeline Odorant System Using Open Source Software, Including a Kalman Filter Solution to Virtualize a Flow Rate Indicator
Authors: D. Bezerra Marco Antonio , da Silva Sidney C. , Silva Silvio C. 
Published: November 2018

In a Supervisory Control and Data Acquisition (SCADA) system, operators use a human-machine interface (HMI) to interact with the process through industrial protocols, which have specific drivers (software pieces) installed in the SCADA servers. If the process device manufacturer does not develop a driver for its equipment, a gateway, with a protocol translator can be provided with the equipment, to translate its particular protocol to a standard industrial one, like the so popular Modbus.
This work presents the development of a gateway — protocol translator — that connects an odorant unit of a pipeline terminal, which has a proprietary protocol to an industrial protocol Modbus TCP/IP. All development is made with Open Source software.
The subject matter is extended to describe the solution to an issue observed due to the lack of a flowmeter in the odorant unit, where a Kalman filter was used as an estimator, to provide a virtual meter.
Strengthening the Current Class Location Designation System
Authors: Willson Diana , Colquhoun Iain , Carnes Dean 
Published: November 2018

CSA Z662, Oil and gas pipeline systems, defines class location as “a geographical area classified according to its approximate population density and other characteristics that are considered when designing and pressure testing piping to be located in the area.” In other words, the purpose of class location designations is to identify areas where specific measures are considered necessary to enhance public safety. Designations range from Class 1 (rural) to Class 4 (urban with high-rise buildings).
The current class location framework relies mainly on a location factor (L) to represent reliability. Higher reliability is achieved by using more resistant pipe — that is thicker and/or stronger — to reduce the probability of failure from operational hazards, such as corrosion and mechanical damage caused by line strikes. Currently, the need for a particular level of reliability is driven principally by the number of people impacted.
This paper discusses possible measures that can be implemented in the next edition of Z662 that, beyond requiring thicker pipe for certain products, will strengthen the class location designation system by considering the potential impact radius of an ignited gas pipeline rupture, as well as the occupancy and nature of buildings within assessment areas. The paper also discusses possible changes to improve environmental protection by introducing the concept of a designated geographical area (DGA) and associated requirements, enhancements to valve spacing requirements, and the handling of changes to class location designations for existing pipelines through interim measures and retroactivity.
Well-Integrated Design of Surge Relief Systems in Oil Storage Facilities
Authors: Perez Emma , Mehta Ashishkumar 
Published: November 2018

Oil Storage facilities (terminals) that receive fluids from pipelines or inject fluid into them, are usually designed with a lower pressure rating than the actual pipeline between these facilities. This is mostly due to the fact that the pressure expected in the terminal is much lower than the pressure required to transport the oil. However, these terminals are still subject to pressure surges caused by abnormal transient events during normal operations. In cases where the surge pressures exceed the allowed operating pressure of the equipment, a relief system can be installed to mitigate these surges to acceptable levels.
When constructing a new terminal or altering an existing one, the hydraulic calculations of these terminals are generally based on design values of the project, such as maximum and minimum flow rates. The hydraulic studies and simulations that are normally done by companies are based on steady state conditions, however, to design intrinsically safe facilities, the system’s entire operating envelope should be considered at the design stage of the project. Once transient analysis results show the need to install a pressure relief device, the proper location of this equipment is critical for the effectiveness of the surge relief system to mitigate overpressures properly.
The effect of flow rate, piping configuration, and initial pressure profiles were simulated and compared to determine their impact on pressure surges and on the critical devices along the flow path. Secondly, simulations were done with the relief system installed in different locations along the terminal pipe and the resulting changes in maximum pressure surges.
The objective of this paper is to show the importance of a detailed transient analysis based not only on design parameters but also on operational scenarios to mitigate surge overpressures in a more cohesive manner. The secondary objective of the paper is to discuss key parameters that need to be considered for selecting the location of the surge relief valve to ensure critical devices are safe during the upset conditions. The analysis presented in this paper is applicable across a broad configuration of oil facilities.
Improving the Accuracy of Traditional Dent Fatigue Analysis: A Method for Quantifying the Initial Damage Caused by Dent Formation
Authors: Turnquist Michael , Parsons Adam 
Published: November 2018

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.