bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pipeline Depth of Cover: Can You Demonstrate Compliance?
Authors: Finley Daniel , Daniel Simon , Ogden Paul 
Published: January 2021

Abstract
Third-party interference is widely documented as being a major cause of damage to buried pipelines. In addition to routine surveillance, maintaining a minimum depth of cover is recognized as a key means of mitigation against third-party interference. We know that the depth of cover over pipelines can change with time. Changes in depth of cover can also be an indication of thermal upheaval, frost heave or ground movement. Current techniques available for measuring depth of cover on buried pipes require significant effort to produce a high-resolution survey for an entire pipeline.
A UK Innovation project completed with National Grid Gas Transmission in 2017 successfully demonstrated a methodology for estimating pipeline depth of cover by combining ground elevation data with high-resolution inertial measurement unit (IMU) data collected during in-line inspection.
Since the end of the project, ROSEN has completed a further eight pipeline depth of cover inspections, with a total length exceeding 400 kilometers and including a range of pipe diameters.
Investigation Four-Phase Multi-Component Flow Techniques in Horizontal and Sub-Sea Pipelines
Authors: Odan Mohamed 
Published: January 2021

Abstract
Offshore drilling projects can be as complex as they are costly, and many problems can arise during the drilling and extraction of sub-sea pipelines petroleum, including environmental issues. The oil and gas industry relies on multi-phase, multi-component flow techniques to transport substances such as gas, oil and water through horizontal and sub-sea pipelines. Artic and offshore drill sites can be particularly challenging due to hydrate formation in the transport horizontal and sub-sea pipelines. This study investigates the feasibility of using a four-phase, four-fluid flow Multi-Component through horizontal pipelines to move a four-phase multi-component flow (oil, gas, water, and sand particles) through submerged pipelines. In order to accurately gauge the multi-component mixtures’ hydro- and thermo-dynamic properties, fluid equilibrium and phase-behavior models are constructed. As well, to examine various interrelated factors such as momentum, mass and heat transfer occurring between pipelines walls and flow, a series of equations are developed.
In the present study, the effect of temperature and pressure on multi-phase flows in horizontal and sub-sea pipelines is investigated. As well, models of flow patterns and pressure drops are created specifically for horizontal and sub-sea pipeline environments. Note that the terms “Four-Phase and Multi-Component flow” are used interchangeably in this study. And Create pressure drops and flow behavior models of multi-phase flows for horizontal and sub-sea pipelines.
Furthermore, multi-phase flows may occur in any one of the following combinations: liquid-gas, liquid-gas-solid, liquid-liquid-gas-solid, An example of a, liquid-liquid-gas-solid flow is four immiscible fluids and component (e.g., water, oil, gas, and solid), immiscible liquids being those which do not form a homogeneous mixture when added together. In terms of practical applications of multi-phase and multi-component flows, water injected into an oil pipelines helps to decreases both the pressure gradient and flow resistance.
A Pressure Reduction to Prevent a Time-Delayed Failure in a Damaged Pipeline
Authors: Cosham Andrew , Leis Brian N. , Roovers Paul , Zarèa Mures , Linton Valerie 
Published: January 2021

Abstract
A time-delayed failure due to stress-activated creep (cold-creep) is a failure that occurs under a constant load and with no growth due corrosion, fatigue or some other environmentally assisted time-dependent degradation mechanism. A time-delayed failure is prevented by reducing the pressure.
ASME B31.4 and B31.8 recommend a 20 percent reduction, to 80 percent of the pressure at the time of damage or discovery. T/PM/P/11 Management Procedure for Inspection, assessment and repair of damaged (non-leaking) steel pipelines, an internal procedure used by National Grid, specifies a 15 percent reduction. The guidance in ASME B31.4 and B31.8, and in T/PM/P/11, is directly or indirectly based on the results of tests on the long term stability of defects conducted by the Battelle Memorial Institute and British Gas Corporation in the 1960s and 70s. The line pipe steels were Grades X52 or X60, and the full-size equivalent Charpy V-notch impact energy (where reported) did not exceed 35 J. The tests indicated that the threshold for a time-delayed failure was approximately 85–95% SAPF (straightaway-pressure-to-failure).
The strength and toughness of line pipe steels has significantly increased over the decades due to developments in steel-making and processing. The question then is whether an empirical threshold based on tests on lower strength and lower toughness steels is applicable to higher strength and higher toughness steels.
In the Tripartite Project, the Australian Pipelines and Gas Association (APGA), the European Pipeline Research Group (EPRG) and the Pipeline Research Council International (PRCI) collaborated in conducting full-scale six step-load-hold tests on higher strength and higher toughness steels. Companion papers present the other aspects of this multi-year project.
An empirical threshold for a time-delayed failure is estimated using the results of the six step-load-hold tests. That estimate is also informed by the other published small and full-scale tests (on lower strength and lower toughness steels). The Ductile Flaw Growth Model is used to infer the effect of strength and toughness on the threshold for a time-delayed failure.
A 15 percent pressure reduction, to 85 percent of the pressure at the time of damage (or of the maximum pressure that has occurred since the time of damage), is considered to be sufficient to prevent a time-delayed failure due to stress-activated creep in lower and higher toughness, in lower and higher strength, and in older and newer line pipe steels.
Earthquake in Papua New Guinea Results in New Concept for Securing Pipelines in Ridgeline Right-of-Way: The Micropile Contiguous Wall
Authors: Ladenhauf Christoph , Remmert Frank , Prager Christoph , Birthwright Rhyssheffer , Cushing Daniel 
Published: January 2021

Abstract
On February 25 (UTC), 2018, the project, a combine of wellpads, gathering lines, transport pipelines and its facilities, sustained a Mw7.5 earthquake, and ca. 300 aftershocks, epicentered directly under the key facilities. Around 150 km of high-pressure gas and condensate pipelines were affected. A number of design and construction decisions protected the pipelines, and prevented serious damage. However, the earthquake disturbed several sections of the pipeline Right-of-Way (ROW), which subsequently required intervention and stabilization. The challenges associated with re-occupying the remotely-situated, mountainous and disturbed ROW, and safely installing stabilization structures, led to the development of a new pipeline stabilization concept: the contiguous Micropile-Wall system.
The concept, leveraging tools and techniques from the tunneling industry, and practices from the Alpine region, consists of 139.7 mm micro piles, installed in 3 m joints, in rows along either side of the pipeline. Once installed, opposing rows of these micropiles are attached to each other at ground level with steel tendons. This new concept can be installed using light equipment with minimal vibration and ground disturbance. It is designed to sustain significant earthquake loads, does not retain groundwater, and is resistant to corrosion and third-party damage. This concept was developed and selected in order to repair parts of the damaged ROW and ensure pipe integrity. Future deterioration of the adjacent slopes was taken into account, but slope stabilization for several dozens of landslides was not looked into, as this would have been too large an effort considering the remoteness of the terrain, climatic conditions, safety considerations and other constraints.
Reliability-Based Crack Threat Assessment and Management
Authors: Yan Jason , Zhang Shenwei , Kariyawasam Shahani , Lu Dongliang , Matchim Tammie 
Published: January 2021

Abstract
Crack or crack-like anomaly is one of the major threats to the safety and structural integrity of oil and gas transmission pipelines. The crack threat is usually managed by hydrostatic test or regular in-line inspection (ILI). For a given crack ILI pipeline tally, operators need to identify critical anomalies, determine appropriate response time, and whether pressure restriction (derate) is required. Traditionally, a deterministic approach is used to determine the mitigation plan based on characteristic values of pipe properties, conservative crack sizing and crack growth rate, and further considering a minimum required safety factor.
This study introduces a reliability-based approach to make the mitigation decision with full details. The annual probability of failure (POF) is evaluated for each reported crack anomaly by Monte Carlo simulation technique considering all the uncertainties associated with pipe geometry, material properties, crack size measurement, and assessment model error explicitly. Both environmental and cyclic fatigue load driven crack growth are considered following API RP 1176. A reliability-based mitigation threshold is proposed and calibrated against the deterministic minimum required safety factor for maintaining the system to a consistent safety level.
Two case studies were conducted to demonstrate the advantages of the reliability-based assessment approach in this paper. Case Study #1 considers an NPS 20 transmission gas pipeline with more than 2000 ILI reported crack anomalies. Compared to the deterministic approach using conservative characteristic values, the reliability-based approach can reduce the number of required mitigation activities significantly without compromising safety. Case Study #2 assumes a severe crack defect on an NPS 34 liquid pipeline to demonstrate the impact of fatigue driven crack growth on POF. The POF of crack anomalies can be compared and combined with other threats, e.g. external corrosion, to evaluate the quantitative risk throughout pipeline systems. The proposed framework in this study could be used by operators to improve the crack assessment programs.
Comparison of Non-Destructive Examination Techniques for Crack Inspection
Authors: Aulin Axel , Shahzad Khurram , MacKenzie Robert , Bott Steven 
Published: January 2021

Abstract
Effective and efficient crack management programs for liquids pipelines require consistent, high quality non-destructive examination (NDE) to allow validation of crack in-line inspection (ILI) results. Enbridge leveraged multiple NDE techniques on a 26-inch flash-welded pipe as part of a crack management program. This line is challenging to inspect given the presence of irregular geometry of the weld. In addition, the majority of the flaws are located on the internal surface, so buffing to obtain accurate measurements in the ditch is not possible. As such, to ensure a robust validation of crack ILI performance on the line, phased array ultrasonic testing (PAUT), time-of-flight diffraction (TOFD), and a full matrix capture (FMC) technology were all used as part of the validation dig program.
PAUT and FMC were used on most of the flaws characterized as part of the dig program providing a relatively large data set for further analysis. Encoded scans on the flash welded long seam weld were collected in the ditch and additional analyses were performed off-site to characterize and size the flaws. Buff-sizing where possible and coupon cutouts were selected and completed to assist with providing an additional source of truth. Secondary review of results by an NDE specialist improved the quality of the results and identified locations for rescanning due to data quality concerns. Physical defect examinations completed after destructive testing of sample coupon cutouts were utilized to generate a correlation between the actual defect size from fracture surface observation and the field measurements using various NDE methods.
This paper will review the findings from the program, including quality-related learnings implemented into standard NDE procedures as well as comparisons of detection and sizing from each methodology. Finally, a summary of the benefits and limitations of each technique based on the experience from a challenging inspection program will be summarized.
Comparison of Buried Pipeline Crossing Assessments Using API RP 1102, Analytical Method and Finite Element Approach
Authors: Joshi Nikhil , Ghosh Pritha , Brewer Jonathan , Matta Lawrence 
Published: January 2021

Abstract
API RP 1102 provides a method to calculate stresses in buried pipelines due to surface loads resulting from the encroachment of roads and railroads. The API RP 1102 approach is commonly used in the industry, and widely available software allows for quick and easy implementation. However, the approach has several limitations on when it can be used, one of which is that it is limited to pipelines crossing as near to 90° (perpendicular crossing) as practicable. In no case can the crossing be less than 30° . In this paper, the stresses in the buried pipeline under standard highway vehicular loading calculated using the API RP 1102 method are compared with the results of two other methods; an analytical method that accounts for longitudinal and circumferential through wall bending effects, and the finite element method.
The benefit of the alternate analytical method is that it is not subject to the limitations of API RP 1102 on crossing alignment or depth. However, this method is still subject to the limitation that the pipeline is straight and at a uniform depth. The fact that it is analytical in nature allows for rapid assessment of a number of pipes and load configurations.
The finite element analysis using a 3D soil box approach offers the greatest flexibility in that pipes with bends or appurtenances can be assessed. However, this approach is time consuming and difficult to apply to multiple loading scenarios.
Pipeline crossings between 0° (parallel) and 90° (perpendicular) are evaluated in the assessment reported here, even though these are beyond the scope of API RP 1102. A comparison across the three methods will provide a means to evaluate the level of conservatism, if any, in the API RP 1102 calculation for crossing between 30° and 90° . It also provides a rationale to evaluate whether the API RP 1102 calculation can potentially be extended for 0° (parallel) crossings.
A Prudent Approach to Evaluate Dig Effectiveness
Authors: Schartner Aaron , Woo Aaron , Puri Dushyant , Kariyawasam Shahani 
Published: January 2021

Abstract
Pipeline operators analyze in-line inspection (ILI) reported features to determine if excavation is required to investigate a feature through direct examination in the ditch. Pipeline excavations require considerable resources and planning. In addition, excavations may cause disturbance to the land owner or cause varying impacts to the operation of the pipeline. Therefore, it is important to ensure that the excavation decisions are made effectively. While operators do review the key performance indicators on how the integrity programs are performing, currently there is no established definition or measure in the pipeline industry to evaluate the effectiveness of a dig program. Defining and measuring dig effectiveness would allow pipeline operators to identify areas to focus on, such as further research and development, opportunities for improvement, and potential optimization of the ILI-based corrosion management program, while maintaining safety and reliability.
This paper presents a method developed by TC Energy to measure dig effectiveness to evaluate the ILI-based corrosion management program. Effectiveness of digs depends on many aspects of the corrosion management program. First, a definition of dig effectiveness that reflects the objectives of the ILI program needs to be established. The method was developed using inhouse historical dig data for external corrosion features that required mitigation based on analysis of ILI data. The focus of the study included the probabilistic evaluation of excavations to baseline what can be expected in a dig program and have a process to evaluate factors that may affect dig effectiveness. The field measurements of digs completed for corrosion driven leak and rupture threats were gathered and analyzed to evaluate the effectiveness of different dig populations and to determine what bounds should be placed to monitor dig effectiveness. The advantages of measuring dig effectiveness using field results as opposed to other metrics such as repair ratio was also demonstrated in this paper. Examples of understanding areas of improvement by using the dig effectiveness are discussed.
Pipeline operators have the potential to incorporate the methodology presented in this paper in the integrity management program to enhance safety and identify areas of focus with the goal of increasing the effectiveness of the corrosion management program.
Third-Party Damage Monitoring: Internal Fiber Optic Installation on a Transmission Pipeline Using a Pig, a Disengagement System and a Pack-Off Hanger
Authors: Meena Carly , Gulewicz Neil , Kennedy Carl , Collis Tim 
Published: January 2021

Abstract
The risk associated with third-party damage to transmission pipelines in areas of urban development is high. Distributed monitoring is a modern technique that uses fiber optic cables as sensors to continuously monitor pipeline parameters such as acoustics, vibration, strain and temperature. The fiber optic system notifies the operator in real-time of ongoing events allowing decisions to be made to prevent external interference or quickly address an incident that has already occurred.
Traditional methods used to install distributed monitoring systems on pipelines have limitations and are not feasible for all transmission pipelines. For instance, it can be both challenging and expensive to trench in fiber optics in developed areas and other installation techniques require the pipeline to be temporarily taken out of service. SaskEnergy Incorporated’s transmission line subsidiary, TransGas Limited partnered with a Canadian pipeline monitoring service provider to install fiber optics inside of a natural gas transmission pipeline using a pig, steel capillary tubing and a pack-off hanger. A disengagement system was incorporated to release the fiber optics after the desired monitoring distance was reached.
It was decided to perform the pilot project on a newly constructed NPS 6 natural gas transmission pipeline located in Humboldt, Saskatchewan. Nitrogen was used as a medium to simulate an in-service pipeline in order to reduce the risks associated with the first attempt of the project designs. The fiber optics were inserted into steel capillary tubing and connected to a disengagement system located at the back of a pig. A pack-off hanger was used to maintain pipeline pressure during and after the installation was completed. The spool holding the steel capillary tubing was stopped once the maximum monitoring distance was reached and the differential pressure activated the disengagement system located at the back of the pig. The pig continued to the receive location and the fiber optics remained in the pipeline for continuous monitoring. The deployment was successful and the fiber optics will remain in the pipeline for a one (1) year monitoring period.
The primary limitation to this pilot project was the strength of the steel capillary tubing. The steel capillary tubing’s ultimate tensile strength would have to be higher to accommodate a pipeline with a larger outside diameter, multiple bends, large changes in wall thickness or large elevation changes. In addition, the steel capillary tubing must be removed from the pipeline in order to perform pigging activities.
Preventing Girth Weld Failure in Pipelines: Measurement of Loads and Application of Assessment Methods
Authors: Young Andy , Andrews Robert M. 
Published: January 2021

Abstract
Pipeline failures from circumferential cracking at girth welds continues to affect large diameter oil and gas transmission lines, even for modern lines constructed this century. The key factors that contribute to the failure at girth welds are the dimensions of defects present, the material properties of the pipe and weldments, and the presence of loading that drives crack growth. The mechanisms of failure are well understood, but identifying and measuring the contributing factors can be a challenge. Locating girth welds that are subject to elevated loads will enable operators to focus on sections with an increased threat of failure.
In this paper, we consider each of the key factors, how these are identified and defined, and the uncertainties in the measurement process. Specific attention is applied to the presence and quantification of loads and how these influence the potential for failure. This includes sources of active external loading due to ground movement, for example, or loads generated in the pipeline from the construction process. Loads can also be quantified by measuring bending strain from inline inspection inertial measurement units. A more complete picture of pipeline loading can be established by integrating a structural analysis that accounts for the direction of pipeline movement and the presence of axial loads. The relationship between assessing pipeline integrity from ground movement — typically with strainbased methods — and establishing whether the defect can survive the load is explored. The relative contribution of bending and axial loads in the failure of defects is considered. The outcome of the study will assist pipeline operators in prioritising actions that enable the quantification of the all the key parameters. The resultant analysis will provide guidance on the girth welds that have an increased risk of failure and this will enable protective actions to be defined and scheduled accordingly.
Characterizing Corrosion Defects With Apparent High Growth Rates on Transmission Pipelines
Authors: Dessein Thomas , Ayton Brent , Sera Travis 
Published: January 2021

Abstract
Consecutive in-line inspections of transmission pipelines enable a comparison between the inspection results to characterize corrosion growth. Despite the high levels of in-line inspection tool accuracy and detection capabilities, corrosion defects with low calculated burst capacities may be detected on a subsequent inspection that were not reported in a previous inspection. These newly reported defects can pose a substantial challenge as the apparent growth rates between inspections of these defects can potentially drive unnecessary repair digs. This paper characterizes the contributing factors that can explain these phenomena, including:
• Typical corrosion growth rates and their associated statistical frequency
• The diminishing detection capability of inspection tools for smaller defects
• The inspection tool minimum reporting threshold
• The measurement accuracy of inspection tools.
A statistical analysis was developed to quantify this interacting set of factors using Monte Carlo simulations that work retrospectively, covering a range of observed measured defect depths and then simulating the processes that could lead to newly reported defects being un-matched in a previous inspection.
This analysis can be used to quantify the likelihood that a defect of a specific measured size would have been unreported in an earlier inspection due only to the performance characteristics of the inspection tool, and not as a result of defect growth that initiated since the time of the previous inspection. A set of case studies covering a range of pipeline inspection intervals ranging from 2 to 10 years are presented to demonstrate how this approach can be used to quantify appropriate growth rates that may be applied to these un-matched defects when assessing the remaining life or predicted probability of failure.