bluuebunny/crossref_metadata_2025_split huggingface dataset:
CFD Study on the Effectiveness of Purging and Loading Procedures for Gas Compressor Units Between Isolation Valves
Authors: Leung Teresa , Botros Kamal K. , Hartloper Colin , Lu Jason , Szuch Greg 
Published: December 2024

Abstract
Effective purging and loading procedures during start-up of compressor stations on gas transmission lines are critical in ensuring safe operation. Most gas compressor units have a single small-diameter line (typically NPS 2 or 3) across the unit suction valve for purging/loading and another small diameter line upstream of the unit discharge valve for venting. Due to either the depressurization rate limit on the compressor unit or the desired vent time window, the vent line is typically equipped with a restriction orifice (RO) or a control valve to achieve the desired depressurization rate. Consequently, when gas at mainline pressure is introduced through the small-diameter line to purge the unit, the purge flow rate is also limited by the RO or the control valve, which affects the degree of pressurization within the unit casing and piping. There is no readily available method to determine the purge velocity and system pressure that would minimize the risk of having flammable mixture inside the unit while avoiding an unnecessarily lengthy purge process that could delay unit start-up. CFD simulations are performed to analyze how the flammable zone would evolve during the purge process for different station layouts including detail compressor casing internal geometry, different piping lengths and vent line RO sizes. The time it takes for a system to reach above the rich flammability limit, the size of the flammable zones and the potential for gas-air stratification at different purge pressures inside each system will be analyzed. Furthermore, scenarios where ignition sources are present during purging are also simulated. This is particularly important once loading begins as the vent line will be closed. These results can guide operation in setting acceptable purge times and pressures.
Vibrating Wire Strain Gauges for Pipeline Geohazard Monitoring: Operation, Failure Mechanisms, and Data Interpretation
Authors: Khadka Suraj , Ahmadipur Amir , Mosaiebian Arash , Ebrahimi Ali 
Published: December 2024

Abstract
This paper provides an overview of vibrating wire strain gauges, detailing their operation, common failure mechanisms, recommendations for best practices for installation, and examples of strain gauge data. The investigation explores potential causes of malfunction occurring before, during, and after installation. Preinstallation damages, often stemming from mishandling or transportation issues, underscore the necessity for thorough quality control procedures. Factors contributing to strain gauge malfunction during installation, including welding defects and inadequate coating, are evaluated, along with post-installation risks, such as construction activities and animal interference. A recommended practice is outlined in this paper to prevent any damage during various phase of installation or operation, emphasizing proper quality control and protective measures.
Through a detailed examination of vibrating wire (VW) strain gauge data trends during installation, backfilling, and variations in pipeline operating conditions, this paper shows that malfunctioning trends can be differentiated from those resulting from geohazard activities. By developing a deeper understanding of how the strain gauges work and the complexities in measured strain patterns, pipeline operators can enhance the use of strain gauges for effective geohazard monitoring and geohazard management.
Key Elements and Best Practice in the Management of Circumferential SCC
Authors: Wang Yong-Yi , Warman David , Liu Banglin , Wang Jiawei 
Published: December 2024

Abstract
Circumferential SCC (C-SCC) is an emerging issue for the pipeline industry with no established management practice. Early experience indicated that C-SCC was strongly correlated to high axial/longitudinal stresses caused by geohazards. There is, however, growing evidence that the majority of C-SCC can be located in areas without identifiable geohazards. Effective management of this threat to the pipeline integrity needs a fresh approach.
Most of the current industry practice and experience have been focused on axially-oriented SCC (A-SCC). C-SCC and A-SCC share certain commonalities, but there are several significant differences. For instance, the sources and magnitude of axial/longitudinal stresses that are a key factor for C-SCC management are different from those for hoop stresses. The availability and performance of ILI tools for C-SCC can also be different from those for A-SCC.
This paper covers a few key elements in the management of C-SCC, including:
• Susceptibility,
• Growth rate,
• Fitness-for-service (FFS) assessment,
• Appropriate representation of safety margin in contrast to the concept of burst pressure (Pburst) or failure pressure ratio (FPR), and
• Repair and mitigation options.
Another key element, ILI technology for detecting and characterizing C-SCC, is also briefly discussed.
The state of the art and gaps in technology and understanding in those key elements are noted. For instance, the conventional understanding of a safety margin for A-SCC in the form of FPR (FPR = Pburst / MAOP) is not valid for managing C-SCC. In contrast to the hoop stress, which is a primary driver for A-SCC, axial/longitudinal stresses in pipelines are not well understood. While axial/longitudinal stresses from geohazards are often cited as a key contributor to C-SCC, axial/longitudinal stresses from other sources can be more common. In some cases, the magnitudes of these stresses can be higher than those from geohazards. The characteristics of axial/longitudinal stresses can potentially affect the growth rates and dormancy of C-SCC, the choice of mitigation options, and safety measures in field work when mitigations are performed. This understanding of the axial/longitudinal stresses becomes a major part of C-SCC management, and thus is one of the focuses of this paper.
A Risk Assessment Framework for Illegal Tapping Threat in Natural Gas Pipelines in Mexico
Authors: Siraj Tammeen , Gonzalez Jose Antonio Solis , Lu Dongliang , Garcia Sofia 
Published: December 2024

Abstract
The unauthorized access and siphoning of products from energy pipelines, also known as illegal tapping, is a growing concern for pipeline operators across the globe. In addition to loss of product and revenue, illegal tapping poses a significant threat to the integrity and safe operation of pipelines. Although typically aimed at liquid hydrocarbon pipelines, TC Energy’s (TCE) natural gas pipelines in Mexico have also been compromised in recent years, often due to the mistaken belief that they transport liquid hydrocarbons. Additionally, unintentional damage to nearby third-party pipelines can have severe consequences for TCE’s assets.
Illegal tapping incidents in TCE’s pipelines in Mexico has led to inclusion of this threat in TCE’s pipeline risk assessment process. Detailed review of the illegal tapping incidents indicates that high risk regions can be identified using factors such as elevated rates of hydrocarbon sabotage in specific areas due to active organized criminal activities, locations where foreign gasoline pipelines run in proximity to TCE’s gas pipelines, and population density around the pipelines. The goal of this study is to develop a data driven risk assessment framework for the illegal tapping threat in Mexico. The risk assessment framework will help regional operators to effectively identify high risk pipe segments for illegal tapping and implement risk mitigation plans accordingly.
Linking Satellite InSAR Ground Deformation Data Into Operational Decision-Making
Authors: Froese Corey , Engelbrecht Jeanine 
Published: December 2024

Abstract
Mature pipeline geohazard management programs assess information related to ground movement hazards, such as landslides or subsidence, in conjunction with the condition of the pipeline (vulnerability). This enables the development of site-specific risk rankings and intervention strategies along extensive networks of pipeline infrastructure. As technology and software tools have evolved, pipeline operators are better able to leverage spatial data from a variety of ground observations and remote-sensing data for an improved understanding of the hazard.
Remote sensing data can be used to identify potential geohazard features, monitor known geohazard sites, and assess the rate of ground displacement. When combined with geotechnical subject matter expert (SME) knowledge of ground conditions, gained through desktop assessments, field inspections, and analysis of in-line inspection tool data for example, remote sensing data can inform the prioritization of next actions.
In recent years, there has been a notable increase in the adoption of interferometric synthetic aperture radar (InSAR) data to support geohazard identification and monitoring. Consequently, numerous pipeline operators are actively seeking enhanced methodologies to leverage this data for risk-informed decision-making. This paper provides a comprehensive overview of InSAR considerations and limitations and explores how the data can be integrated into geohazard management programs. We also delve into the potential to correlate InSAR observations with site-specific risk classifications to determine the timing of operational actions and possible interventions.
Applying Computational Fluid Dynamics to Reduce Greenhouse Gases Emissions in Natural Gas Compressor Stations
Authors: Silva Fernando , Junior Carlos , Saggio Carlo , Fundo Fabio , Silva Matheus 
Published: December 2024

Abstract
Concerns about greenhouse gas emissions are rapidly increasing and becoming a priority in operations involving hydrocarbons. In natural gas transportation systems, compressor stations are commonly found to be the primary sources of emission of these gases. Some compressor stations with emergency depressurization systems are designed with a continuous purge of natural gas into the environment to prevent air ingress into the depressurization system, therefore avoiding formation of an explosive atmosphere within the line. Many of these projects were conceived before the widespread discussion on environmental issues, resulting in less concern about the amount of purged natural gas. To align these stations with emission reduction goals, the industry is seeking for solutions. However, most existing methods require more complex changes to safety characteristics and risk analyses of the plant. This work proposes a rapid and cost-effective method to determine the minimum flow rate of natural gas capable of preventing the formation of an explosive atmosphere in the depressurization piping. The approach involves simulations in Computational Fluid Dynamics, varying boundary conditions. When applied to a compressor station as a test case, the method indicated a flow rate reduction of nearly 50%.
Investigating Weld and HAZ Effects During SMAW of Pipe and Fitting Materials
Authors: Khotenko Nick , McIntosh Cory 
Published: December 2024

Abstract
The primary goal of weldments is to have the longitudinal strain not concentrated in the weld. To date, there is no reliable way to accurately predict this, given the variability of welding techniques, mechanical properties, and manufacturing methods of materials in CSA Z662 pipeline designs.
Several girth welds were completed using SMAW on common carbon steel pipe and fittings used under CSA Z662 designs. The results focus on comparing as-welded joint properties relative to the base metal. The base materials were chosen to be wide ranging in chemistry and manufacturing process. The deposited weld filler metal tensile strength can be relatively and consistently predicted; however, the overall weldment properties are more difficult to estimate.
The results provide an opportunity to learn more about the response of welding on the base metal. The goal is to improve the ability to design and complete weldments that have equal or better mechanical properties than the base metal. Advancements are already being made to new construction best practices, but there is value in understanding how conventional filler metals and base metals are allocated to highest risk welds for new construction and existing assets.
Leak Orientation Effects on Flow-Induced Vibration in Horizontal Multiphase Pipelines
Authors: Chen Haobin , Dang Zhuoran , Bayati Farzaneh , Park Simon , Hugo Ron 
Published: December 2024

Abstract
Multiphase pipe flow can result in strong structural vibrations. In this paper, an experimental investigation of the effects of leak orientation on flow-induced vibration in horizontal multiphase pipe flow is performed. Two leak orientations are investigated, a leak at the top of the pipe and a leak at the bottom of the pipe. Vibration signals are measured and high-speed videos are recorded. A total of four flow patterns including bubbly flow, plug flow, slug flow and stratified wavy flow are studied. Experimental results show that the leak orientation affects leak flow, leak flow rate, leak percentage and inlet flow rate in differing amounts depending on flow pattern. More pronounced changes are induced by a leak at the bottom of the pipe compared to a leak at the top of the pipe. Variance values of the extracted base functions are computed as a numerical indicator for the presence of a leak. A leak in bubbly flow is the easiest scenario to detect regardless of leak orientation. For a leak at the bottom of a pipe, differences in the computed variance values in plug and slug flows are comparable and detectable. A leak in plug flow induces a larger difference in the variance value than for slug flow if the leak is at the top of the pipe. Both leak orientations show difficulty in determining presence of a leak for stratified wavy flow. It is found that the differences in variance values computed using the x-axis (axial) accelerometer signal are smaller than the other two axes, indicating that more significant changes in FIV are induced in the radial and azimuthal directions during a leak event.
Probabilistic Erosion Assessment of Natural Gas Storage Wells
Authors: Veldhuis Sydney , Fraser Alex , Ayton Brent , Shironishi Mari , Shapiro Daniel 
Published: December 2024

Abstract
US operators are required to perform risk assessments for relevant threats on their underground gas storage wells as per 49 CFR 192.12 [1]. Sand brought up from the reservoir can present an erosion threat to the withdrawal piping attached to the wellhead (well laterals), where a failure would result in an immediate release to the atmosphere. This paper outlines a probabilistic model for assessing the erosion of well laterals that is part of a quantitative risk framework for SoCalGas’ underground storage sites in California.
DNV published a recommended practice for managing sand production and erosion (DNVGL-RP-O501)[2], which includes empirical equations to determine the rate of wall thickness loss for piping components such as straight pipe, reducers, target tees, elbows, and production chokes. The inputs are the gas and sand properties, the gas flow rate, and the components’ size and orientation.
The probabilistic model uses statistical distributions to account for the uncertainty in predicting erosion, specifically the variability in operating conditions and the amount of sand produced from wells. Using Monte Carlo simulation, the model assesses each lateral component’s failure probability and determines an overall time to failure for the lateral system while considering the potential for inspections and repairs.
Erosion was modeled for various lateral configurations and operating conditions to demonstrate the potential range in the probability of failure. The probabilistic model quantified the probability of failure and reported an expected year of failure for the more susceptible components. Further, the probabilistic model was used to demonstrate how certain combinations of operating conditions and lateral design lead to potentially erosive environments and how adding a sacrificial erosion probe and/or scheduling inspections of the laterals can effectively mitigate the erosion probability of failure. The potential for high probabilities of failure demonstrates the benefit of well-specific probabilistic assessments to gauge erosion potential and inform decisions on mitigation actions.
Advancing Data Completeness and Strategically Directing Record Reviews With a Machine Learning Approach
Authors: Sun Xiaoyu , Bandstra Daryl , He Ziming , Li Carly , Safari Miaad 
Published: December 2024

Abstract
This study presents an innovative machine learning approach for predicting the operating stress level as a percentage of the Specified Minimum Yield Strength (% SMYS) when primary pipeline properties such as grade and wall thickness in steel pipelines were incomplete.
This becomes particularly vital for pipelines where such data is missing, a common challenge in pipeline integrity management. The parameter, % SMYS, is essential for classifying pipeline segments into integrity management and regulatory categories such as Distribution and Transmission. However, missing records often necessitate time-consuming manual reviews of retained documentation to determine the appropriate values to record in their digital pipeline records databases. These reviews, while necessary, may not all have the same impacts on the company’s integrity management approach, decision-making, or mitigation of risks. There may be small diameter (&lt; NPS2), low pressure pipelines operating at a low stress level (&lt; 5% SMYS) ranging up to large diameter (&gt; NPS24) pipelines operating at much higher stress levels (&gt; 30% SMYS). The method’s goal is to strategically steer manual record reviews and enhancement efforts toward segments with the most significant impact, especially those potentially operating above 30% SMYS and above 20% SMYS in the distribution category.
This study employed machine learning tools to estimate the stress level or operating category (e.g., &lt; 20% SMYS, 20%–30% SMYS, and &gt; 30% SMYS) of pipeline segments. The model was trained and tested with a dataset of steel pipe segments with complete records, where stress level is available. The models will be used to estimate the stress levels of pipeline segments with incomplete records. The records that are estimated as high stress levels or operating categories (20%–30% SMYS, and &gt; 30% SMYS) are then prioritized for manual review. When the stress level of the missing record is predicted, the problem is framed as a regression problem, but when the operating stress level category of the missing record is estimated, the problem is framed as a classification problem. The implications and results of these two different frameworks are compared in this study. This paper used data splitting and cross-validation for training, validation, and testing the models. In this study, models including random forest and extreme gradient boosting (XGBoost) regressor were utilized.
Once records are prioritized and selected for manual records review, the results of the review can then be used to objectively evaluate the performance of the predictive model. In addition, these results can be fed back into the training dataset to improve the future performance of the model. This study provides broad guidance for the use of machine learning for dealing with incomplete data and to facilitate the integrity assessment of large pipeline systems.
Qualifying ILI Technologies Using an API 1163 Approach Hard Spots as the Example
Authors: Hubert Yvan , Winfrey Gary , Kindel Samuel 
Published: December 2024

Abstract
API Standard 1163 “In-Line Inspection System Qualification” sets the requirements for operators to define the scope of the inspection, its goal(s) and validate that a system has met the intent of the inspection. As part of the Integrity Management Program (IMP), an operator often faces the need to bring a new technology or and known technology from a new provider. Over the years, a process was developed with the intent to reduce the learning curve for both the service provider and the operator and reduce the risk of using an unfamiliar technology and/or vendor.
Some of the risks that operators experienced in the past were the pace to which trust in the In-Line Inspection (ILI) tool can be built, the challenge in understanding if the results are truly representative of the total population of features to be managed, first run success and reporting.
The process leverages the requirements laid out in API STD 1163 to define three stages to the qualification:
1. Audit that included testing demonstration of all aspects of the tool or the vendor capacity to meet the goal of the inspection and the reporting deliverables.
2. Performance demonstration that the tool can meet the service provider’s claim.
3. A first inspection to provide overall confidence that the tool does function as intended which includes field validation and all requirements sets by both parties.
The paper will walk through these 3 steps by showing how an operator can apply it to the identification of a capable ILI technology to inspect pipelines for hard spots. It will include the audit process and how specific requirements were developed when needed. How a series of pull through tests were organized to understand the tool performance based on a known dataset of hard spots. Finally, how a ‘run-off’ in a pipeline segment was set up to complete the validation with a series of digs that were compared to each service provider’s ILI tool to validate Probability of Detection (POD), Probability of Identification (POI), and sizing accuracy (SA).
Observations, lessons learned, and recommendations will be drawn from the example to inform other operators on considerations to include in their ILI qualification processes.
Anhydrous Ammonia Pipeline Safety Experience in the United States
Authors: Lee Kenneth Y. , Chawla Sandeep 
Published: December 2024

Abstract
Transporting anhydrous ammonia by pipeline is receiving greater interest with global efforts to decarbonize and transition away from carbon-based energy. In the United States, there are currently over 2,000 miles (3,200 km) of anhydrous ammonia pipelines, which were constructed between 1960 to 1978, to primarily deliver ammonia from producers in the Gulf Coast to agricultural users in the Midwest.
In the United States, significant incidents have occurred with ammonia pipelines, which are regulated under the Code of Federal Regulations (CFR), Title 49, Part 195, highly volatile liquid (HVL) requirements.
Carbon steels in anhydrous ammonia service are susceptible to internal corrosion and stress corrosion cracking (SCC) when certain contaminants are present, such as oxygen, carbon dioxide or sulfur dioxide. SCC can be mitigated by avoiding contamination by air, oxygen, and carbon dioxide, or by the addition of small amounts of water where oxygen may be present. Pipeline experience in the United States has shown that 0.2–0.5 wt% water is effective in preventing SCC.
Specific areas of concern with anhydrous ammonia pipelines include thermal relief, ice formation, commissioning, decommissioning, and leak hazard mitigation. Strict purging practices, limiting contaminants such as oxygen and carbon dioxide, adding 0.2%–0.5% water to inhibit SCC, and operational considerations are important to ensure safe pipeline operation. Anhydrous ammonia pipeline leaks result in significantly greater immediate danger to human life than many other types pipeline leaks, where it is important that leaks are immediately detected and proper hazard mitigation actions are taken.