bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Feature-Specific Probabilistic Assessment of Pipeline Defect Size From ILI MFL Signal Using Convolutional Neural Network
Authors: Chen Jenny Jing , Westwood Stephen , Heaney David 
Published: January 2021

Abstract
When estimating pipeline burst pressure, one of the prevalent sources of uncertainty that needs to be factored into the calculation is the model error in the estimation of feature depth and length from the in-line inspection tool. Due to modeling technique limitation, as of today many ILI vendors have feature specific error bounds depending on the morphologies of the corrosion, this error can only be reported to operators as an overall error known as the ILI tool tolerance which is usually obtained from samples of excavation data or pull test data. At the most, the error is reported by classes based on corrosion morphologies specified by Pipeline Operators Forum. For example, a commonly reported corrosion depth sizing specification is ±10% of pipe wall thickness at 80% confidence for the General type of corrosion. This can be interpreted as that the error of each reported depth estimations is assumed to fall in a normal distribution with a mean equal to 0 and standard deviation equal to 7.8% of wall thickness. The shape of the distribution, the mean and standard deviation will then be used as constants to factor in the burst pressure calculation.
However, these factors are never constant for a sample of defects in reality. In fact, they ought to be variables on an individual feature basis. An example of such an approach would be a feature specific error tolerance, this could be that the estimated depth of a feature is 36%wt in an interval of [30%, 48%] of wall thickness with 80% confidence. This is believed to greatly reduce the level of uncertainty when it comes to failure pressure estimation or other type of pipeline risk assessment. The advancement in Machine Learning today, deep learning with deep neural networks, allows feature-specific error tolerance to be obtained after analyzing visual imagery of MFL signal. In this paper we will describe a novel approach to predict the size of metal loss defects and more importantly the distribution associated with each prediction. We will then discuss the benefits of this approach has with respect to risk assessment such as failure pressure estimation.
Pipeline Leak Detection Using a Moderate Gain Nonlinear Observer
Authors: Cunha Sérgio B. , Baptista Renan M. 
Published: January 2021

Abstract
Most pipeline control systems use some sort of autonomous leak detection system as a safety feature. Among the pipeline leak detection techniques, state observers stand out as the most sophisticated and promising technique. But its use has been inhibited as the dynamic models employed so far are large and estimating the states of nonlinear systems is not trivial.
Pipeline pressure and flow dynamics have been modelled in the literature by means of different numerical solutions to a pair of first order partial differential equations that express mass and linear momentum conservation. The numerical solution requires discretizing the pipeline length in a finite number of segments, resulting in a system of equations with size of twice the number of segments. Although there is nothing wrong with this approach, a smaller system is more convenient if one is concerned exclusively with pressure and flow at the pipeline entrance and exit sections. In this paper, energetic modelling principles are employed to obtain a pair of first order ordinary differential equations representing the dynamics of long liquid pipelines.
A recently introduced nonlinear observer enables straightforward use of linear, constant-gain observers with Lipschitz nonlinear dynamics. This observer gives the designer freedom to choose the observer eigenvalues and enables mathematically proven asymptotic stability with low gains. In this paper this observer, using a second-order model to represent the pipeline dynamics, is used as a pipeline leak detection algorithm.
Initially the observer was employed directly as a leak detection algorithm, the leak being indicated by a non-transient difference between the measured and the estimated flows. Afterwards the leak was modeled as a disturbance flow and a disturbance observer was designed. Both algorithms were verified by means of computer simulations. It was found that the two methodologies are capable of detecting and estimating very small leaks, but the disturbance observer seems capable of indicating small holes further way from the measuring points.
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.