bluuebunny/crossref_metadata_2025_split huggingface dataset:
Crack Arrestors: Closing the Design Basis Gaps
Authors: Laughlin Shawn , Leewis Keith 
Published: December 2024

Abstract
The demand for pipelines to transport increased volumes of hydrogen and CO2 in the future is widely anticipated. The specific potential sources and nature of the fluids that are anticipated have led to concerns regarding potential gaps related to fracture control plans and operational integrity efforts. One of the specific gaps that has been identified is that of the design basis for the external devices (non-integral) which we generally refer to as “crack arrestors”. Specific concerns focus on anthropogenic CO2 with a more challenging decompression and hydrogen blends which could affect the pipe steel ductility. Crack arrestor devices are generally intended to arrest running ductile fractures or propagating shear. This paper reviews the technical history of this topic. Technical paper publications and intellectual property sources are reviewed. It will document the 1970’s understanding that the deformation in front of the fracture was considerable with specific characteristics. A review of effective and ineffective efforts over a 5-decade period is reviewed, as well as the design basis for these efforts. A review of the commonality of characteristics of effective and non-effective efforts is reviewed with a focus on identifying design basis flaws and the reasons for success. This paper will suggest that the mechanism of the phenomena of propagating shear is a plastic collapse of the pipe structure, with the propagating fracture an artifact. The means to stop the running ductile fracture is to add capacity to the structure or Resistivity to plastic collapse. In this context, the BTCM (or alternatives) with a focus on the speed of the gas decompression and the speed of the crack, are not necessarily the precise or sole path for a complete understanding of how to stop or arrest the event. A change in perspective is suggested from a focus on the speed of the propagation to adding capacity to the pipe structure. This paper will provide the basic details of an updated design basis for these crack arrestors devices.
Finite Element Analyses of Burst Capacities of Pipelines Containing Pinhole-in-Corrosion Defects
Authors: Shen Yufei , Zhou Wenxing 
Published: December 2024

Abstract
This study investigates the burst capacity of pipelines containing pinhole-in-corrosion (PIC) defects through elastoplastic three-dimensional finite element analyses (FEA) and quantify the extent to which the burst capacity of the PIC defect is affected by sizes of the corresponding pinhole and general corrosion anomaly and the relative position of the pinhole within the corrosion anomaly. The PIC defect in this study is idealized as a cylindrical-shaped pinhole located within a cuboidal-shaped general corrosion anomaly. Results of extensive parametric FEA reveal that, in general, the burst capacity decreases as the pinhole depth increases; however, the bust capacity is insensitive to the diameter the pinhole. The location of the pinhole is found to be a significant factor, with pinholes closer to the edge of the general corrosion having a smaller impact on the burst capacity, while a pinhole at the center of the general corrosion can greatly impact the burst capacity. The pinhole location effect is explained by considering the impact of the bulging effect on the burst capacity of PIC. The outcomes of the study provide the basis for developing an accurate, practical burst capacity model for pipelines containing PIC defects.
Impact of Operating Temperature Increase on Liquid Pipeline Corrosion Management
Authors: Yu Mengshan , Gibeault James , Li Yanping , Place Trevor 
Published: December 2024

Abstract
Some liquid pipeline operators are experiencing an upward trend in operating temperatures. This trend is influenced by increasing flowrate through fixed pipeline inventory (viscous heating), hotter product entering some pipelines, and environmental warming (less heat loss to soil and atmosphere).
While increasing temperature is known to increase the degradation rate of some coatings and the often-mentioned Arrhenius Equation suggests chemical reaction rate could double with every 10°C temperature increase, the true effect on pipeline corrosion is not fully understood. The real-world impact of temperature changes is a complex interaction of physical and chemical processes. To find the impact of temperature increase on pipeline external corrosion growth rate (CGR), results from laboratory studies and field case studies will be presented.
Long term corrosion testing was performed under a simulated coating disbondment condition at various fixed and modulated temperatures (to simulate seasonal variation). Corrosion rates were measured gravimetrically and by measured pit depth. It was demonstrated that Arrhenius level CGR-temperature correlations could be emulated under artificially severe conditions, but more realistic conditions produced a far lower CGR.
Long term case histories were conducted on liquid pipelines by investigating their temperature profiles, CGR (derived from consecutive in-line-inspections) and repair frequency before and after temperature increase. For a portion of one pipeline, an increase in maximum and average operating temperature of up to 10°C was observed starting in 2014. This line is 1960s vintage with polyethylene (PE) tape coating. After several years of operation at the increased temperature, no clear correlation was observed between operating temperature increase and corrosion degradation or repair frequency. This same trend is observed on another PE coated line. These observations align with the above laboratory testing.
However, in another unique case study, a 1950s vintage coal tar coated pipeline experienced very rapid external corrosion within a cased crossing shortly after the pipeline operating temperature was increased, suggesting that operating temperature increases may still require change management consideration.
Recommendations on liquid pipeline corrosion management with increased operating temperature will be presented.
A Pipeline Is a Pipeline Is a Pipeline, or Is It? Product Type, Project Differentiation, and Risk Today
Authors: Gillespie Jason , Schmidt Jon , Raun Jeff 
Published: December 2024

Abstract
In the past ten years, many pipeline and other linear energy projects have been cancelled in North America for economic, regulatory, or social license reasons. This trend is continuing today for energy transition-related pipelines and other linear projects. While the reasons for project cancellation are complex, key themes have been identified including a changing regulatory environment; political influence; increased opposition from affected and unaffected stakeholders; and market forces. Numerous project examples exist to support the analysis of oil and gas pipeline project execution risk. The paper explores how these examples illustrate future projects integral to enabling the transportation of carbon dioxide, hydrogen, biofuels, power or other products relevant to energy transition in Canada and the US. Traditional pipeline projects are compared to energy transition-related projects, testing the question of whether project differentiation and product type matter. Finally, the analysis identifies opportunities for reducing risk in pipeline project execution during the planning and regulatory phases. Energy transition faces significant new challenges requiring projects to manage an evolving regulatory, stakeholder and political landscape. Understanding these challenges helps proponents better position their projects with stakeholders who are similarly learning how modern technologies and products will be planned within existing pipeline development frameworks.
Benchmarking of Three Girth Weld Flaw Assessment Models: A Validation Methodology
Authors: Munoz Eduardo , Fateminia Seyed Hamed , Chirinos Saul 
Published: December 2024

Abstract
The application of quantitative risk assessment involves the utilization of pre-existing fitness for service calculators. This departure from the original intent of these calculators necessitates a comprehensive evaluation of their efficacy within an extended domain. This article elucidates the methodology employed to gauge the performance of three girth weld flaw assessment models: namely, the Kastner model, API 1104 Appendix A Option 2, and API 579.
The proposed framework delineates a comprehensive analysis, originally devised for financial models, surpassing the conventional validation process, which typically entails a comparison of predicted values against selectively chosen experimental data, commonly referred to as the “least square error Olympics”. A sensitivity analysis of the models was employed to evaluate the impact of data sparseness and ascertain the optimal data collection strategy. Furthermore, we advocate for the measurement of the decrease in entropy as a more effective means of demonstrating the predictive information encapsulated within distinct models.
The benchmarking exercise revealed that the venerable Kastner model exhibits a confined range of applicability but maintains a high level of accuracy. Additionally, it was observed that there are instances where a synergistic combination of models can be employed to enhance predictive capabilities.
Pipeline Operators Forum (POF) White Paper on In-Line Inspection Tool Readiness for Hydrogen Pipelines
Authors: van de Camp Peter , Fernandez Charles , Koops Sieger , Klein Stefan , Roovers Paul , Lewis Chris , Santamaria Wilson 
Published: December 2024

Abstract
The Pipeline Operators Forum (POF) is a non-profit organization enabling pipeline integrity engineers to share and establish industry best practices to improve the quality of pipeline integrity management at every level. POF set up a working group (WG) on hydrogen pipelines to investigate ILI tool readiness for hydrogen pipeline inspection. This paper summarizes the current perspective of the WG on the state-of-the-art ILI tool readiness level including providing a gap analysis based on joint discussion and feedback of various ILI companies.
The WG will rely on the previously published POF standards (for example POF 100 Specifications and requirements for in-line inspection of pipelines) and recommended practices such as for example POF 300 Achieving successful in-line inspection, POF 310 Field verification procedures for ILI, and POF 320 In-line inspection contractor compliance check but recognizing if hydrogen is a new threat.
This paper outlines key elements recognized today to be considered for inspection of hydrogen pipelines and possible technology options to address possible issues in terms of threat categories (internal and/or external corrosion, hydrogen embrittlement fatigue, geohazard, third party damage, material properties) and morphology/appearance. In the introduction an overview of ILI technologies and anomaly types considered is given. A proposition for mapping state-of-the-art ILI technologies (axial magnetic flux leakage [MFL], circumferential MFL, ultrasound [UT], resonance UT, liquid coupled UT, electromagnetic acoustic transducer [EMAT], gas coupled Lamb wave, Eddy current, inertial measurement unit [IMU], axis stress measurement, low field MFL) versus pipeline integrity threats is provided by examples. The ILI tool readiness is defined and discussed in detail in terms of key ILI tool component material compatibility. Beside operational safety considerations, options to achieve acceptable inspection data quality are analyzed and elaborated on. The paper concludes by providing a technology gap analysis summarizing required technology development for ILI of hydrogen pipelines. Detailed guidance on how gaps can or should be closed is out of the scope of the paper.
Innovations in Long Gas Pipeline Loading Procedures: Staged Pressure Method From High-Pressure Rich Natural Gas
Authors: Botros Kamal K. , Strandlund Dale , Caruth Douglas , Yin Ole 
Published: December 2024

Abstract
Current trends in long gas transmission systems are to operate at high pressures in the dense phase region. When the gas is rich in composition, i.e. containing appreciable amounts of C2+, as well as relatively higher water, problems arise during loading newly constructed large diameter and long pipelines, e.g. 600+ km. In such a case, condensate dropping out and hydrates formation can occur downstream of the throttling loading valves due to Joule-Thomson (T-J) effects causing potential flooding of Hydrocarbon (HC) condensation and plugging due to hydrates formation in the pipeline near the loading location. In order to circumvent this, an innovative procedure was ideated and implemented on a newly constructed NPS 48, 640 km long gas pipeline in a cold environment where hydrocarbon condensation and hydrates formation are imminent as the supply pressure is in the dense phase and the temperature is relatively low. The new procedure is based on loading every sub-section to an intermediate pressure first, e.g. 50% of the supply pressure upstream, then the next sub-section will be loaded from the upstream sub-section now maintained at the intermediate pressure. In this case, the isenthalpic expansion of the gas from the intermediate pressure will be clear of intersecting the hydrate equilibrium line corresponding to the water content in the supply gas, and only a small amount of HC condensate could drop out. The loading process starts with partially filling of the very first upstream from the high pressure to an optimally determined intermedium pressure. Once this step is completed, the rest of the pipeline sections between Main Line Block Valves (MLBVs) can be loaded, from the now, intermediate pressure in the section upstream, and sequentially to the following section(s) between consecutive MLBVs. The third step is then to load the upstream sections (again in sequential manner) to the full supply pressure. Hence, the new concept is called “staged-pressure loading”. The paper describes the new procedure along with an example of specific loading conditions which was implemented successfully on an NPS 48, 640 km long transmission line. No appreciable hydrates or HC condensate were observed during loading based on the new procedure.
Refinement of Reliability-Based Safety Factors for Corrosion Assessment
Authors: Adianto Riski , Nessim Maher , Lu Dongliang 
Published: December 2024

Abstract
Reliability-based safety factors for corrosion assessment have been developed for onshore natural gas and low vapor pressure (LVP) pipelines and published in 2018. These safety factors were developed using 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 factors were calibrated for two corrosion limit state categories: ultimate limit state, representing large leaks and ruptures; and leakage limit state, representing small leaks. They can be applied with a deterministic limit state equation (such as the corrosion burst pressure model) and a set of calibrated characteristic values of key input parameters for the equation (such as wall thickness and feature depth) to assess the acceptability of a corrosion feature. With this set of reliability-based safety factors, a corrosion feature assessment can be carried out deterministically while still achieving a consistent risk level. For the ultimate limit state, the safety factors were calibrated for a safety class system that is aligned with the six safety classes described in the Annex C of the 2023 edition of CSA Z662.
Refinement of the previous formulation of the safety factors includes: 1) addition of more pipeline cases in the calibration to expand the applicability of the safety factors; 2) addition of the pipeline material strength in the safety factor calculation equations; and 3) further calibration of the safety factors to cover both the Annex O and Effective Area corrosion burst pressure models. These refinements were developed for natural gas pipelines, and LVP liquid pipelines are not considered in this paper.
To ensure that these safety factors lead to practical solutions for real cases, the performance of the reliability-based safety factors was compared to that of the CSA Z662 Clause 10.10.2.5.1 and the full probabilistic approach of TC Energy (“TCE”). The comparison was based on the number of corrosion repairs required by each method and was conducted using a comprehensive set of TCE pipeline cases that covered a wide range of pipeline diameters (NPS 6 to 42), hoop stress factors (0.23 to 0.80), and corrosion severity (feature density from &lt; 1 to &gt; 5000 per km).
Analysis of a Third-Party Action Incident in a Gas Pipeline: A Case Study of the Cuiabá Lateral Pipeline in Brazil
Authors: Silva Bruno , Morais Filho Pedro 
Published: December 2024

Abstract
The impact of third-party actions remains a primary cause of induced failures in transportation systems. In response, the operational safety management system needs continual revision and robust implementation to mitigate such risks effectively. This study goes through the analysis of an incident involving the rupture of a gas pipeline, specifically examining the event that happened in January 2021 along the Cuiabá Lateral Pipeline in Mato Grosso, Brazil. A comprehensive comparative evaluation is undertaken, contrasting the investigation taken by the pipeline operator, and the analysis conducted by the regulatory body. Within the Brazilian context, operators are mandated to adhere to the Technical Regulation of Onshore Oil and Gas Pipelines (RTDT), a regulatory framework grounded in process safety, encompassing requirements for inspection, community engagement, and incident investigations. The regulator assumes an important role in evaluating the investigations carried out by operators. This research sheds light on the divergent perspectives surrounding the management system, depending on whether it is viewed from the operator’s lens or the regulator’s standpoint. Operators tend to emphasize community actions, whereas regulators focus on the efficacy of preventive measures against third-party actions, underscoring the significance of inspection frequency.
Advanced Assessment of Pipeline Stress-Relief
Authors: Fathi Ali , Ndubuaku Onyekachi , Fowler Matthew , Yoosef-Ghodsi Nader 
Published: December 2024

Abstract
Pipelines traversing landslides can be subjected to forces due to ground displacement. Stress-relief projects are usually planned before strain in the pipe, or a girth weld reaches one of the strain capacities associated with a limit state event using a certain safety margin. Accurate estimation of the pipe strain growth due to the slide movement is a key input for planning stress-relief projects. Through presenting a case study, this paper introduces the concept of an advanced stress-relief assessment approach. This method uses finite element simulation of pipe-soil interaction, to estimate the evolution of strain before stress-relief, pipe rebound as a result of stress-relief, and extension of the asset life after the backfill is completed. Using this modeling, the effects of additional improvements that can be added to a stress-relief project can also be estimated properly. These measures can enhance the performance of the pipe by increasing its strain capacity or reducing the impact of the slide movement.
The primary benefit of completing such assessment is to be able to optimize the timing of stress-relief projects. Given that the strain growth rate usually accelerates as more strain accumulates in the pipe, timely stress-relief can prevent excessive plastic deformations and consequently increase the benefit of stress-relief projects. This is especially important for lines, for which pipe replacement is much more expensive than a simple stress-relief (without cutouts).
The next step in this assessment is to use the output of this model for different scenarios of stress-relief in a risk assessment. This risk assessment provided an opportunity to compare the stress-relief option with horizontal directional drilling with a completely different cost/performance combination. The result of this assessment showed that if planned and executed as recommended, the stress-relief option can result in risk reduction below the risk target with significantly lower cost and complexity.
Optimization of Emergency Gas Supply Schemes in Natural Gas Pipeline Networks Under Extreme Conditions Considering Customer Characteristics
Authors: Zhao Sirui , Zuo Lili , Liu Dingzhi , Hou Haoyuan , Wu Changchun 
Published: December 2024

Abstract
During peak periods of natural gas consumption, extreme conditions can lead to a shortage in gas supply, reducing operator profits and customer satisfaction. This study proposes evaluation indexes for emergency supply schemes from the perspectives of profit and customer satisfaction. The study analyzes the characteristics of different customers and introduces reduction coefficients to constraint demand. Considering the hydraulic operation constraints of each pipeline, equipment, and nodes in the pipeline network, as well as the tiered pricing constraints of each customer, a multi-objective emergency supply scheme optimization model under extreme conditions is established. The spatial branch and bound algorithm in the Gurobi solver is employed to solve the established Mixed Integer Quadratic Programming (MIQP) model. The min-max method makes a trade-off among the Pareto solution sets to obtain the optimal supply scheme. Taking a large-scale loop-topology pipeline network in a province of China as a case study, the conflicting relationship between profits and customer satisfaction is analyzed under extreme conditions of source supply shortage and customer demand surge. The results indicate that the proposed method can effectively balance profits and customer satisfaction. The solution time under different conditions does not exceed 1 second. Compared with the SPS simulation software, the relative error of the node pressure does not exceed 3%, demonstrating high solution efficiency and feasibility. The method developed in this study can provide decision support for network operators to formulate gas supply schemes reasonably under extreme conditions, offering strong guiding significance.
Decompression Behaviour of Natural Gas-Hydrogen Mixtures: Shock Tube Test and Numerical Prediction
Authors: Michal Guillaume , Liu Xiong , Lu Cheng , Botros Kamal K. 
Published: December 2024

Abstract
Blending hydrogen into existing natural gas pipelines is a transition option to progressively increase the energy share of hydrogen. As part of the fracture control plan, pipelines must be capable of controlling a running ductile fracture for all blend ratios used in operations. It is important to understand the decompression characteristics of Natural Gas-Hydrogen (NGH2) mixtures at those ratios.
Under the aegis of the Future Fuels Cooperative Research Centre (FFCRC), a project was initiated to investigate the implication of the use of NGH2 blends on the Australian network, under the assumption that pipe properties are not affected by hydrogen during ductile fracture propagation.
In this work, a desktop study is carried out to evaluate the impact of hydrogen on the toughness requirements. The potential increase in toughness requirement with a rich gas mixture within a given range of hydrogen fraction is revealed. This provides a basis for the design of shock tube tests.
Eleven shock tube tests of NGH2 mixtures were carried out at TC Energy’s Gas Dynamic Test Facility in Didsbury, Canada. The mixtures targeted concentrations of 0%, 9%, 30% and 100% hydrogen.
The outcomes of the shock tube tests are reported. 1D isentropic numerical decompression wave speed predictions using the GERG-2008 equation of state are compared with experimental data.