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ASME Conference Presenter Attendance Policy and Archival Proceedings

2018;():V003T00A001. doi:10.1115/IPC2018-NS3.
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This online compilation of papers from the 2018 12th International Pipeline Conference (IPC2018) represents the archival version of the Conference Proceedings. According to ASME’s conference presenter attendance policy, if a paper is not presented at the Conference by an author of the paper, the paper will not be published in the official archival Proceedings, which are registered with the Library of Congress and are submitted for abstracting and indexing. The paper also will not be published in The ASME Digital Collection and may not be cited as a published paper.

Commentary by Dr. Valentin Fuster

Operations, Monitoring, and Maintenance: Automation and Measurement

2018;():V003T04A001. doi:10.1115/IPC2018-78037.

The rehabilitation of damaged pipelines plays a critically-important role in maintaining the integrity management of pipeline systems. The repair techniques employed by pipeline operators typically include welded Type A and Type B sleeves, as well as composite repairs. Once repairs are made, operators must trust the integrity and soundness of the repairs based on various monitoring and inspection techniques; however, there are no current widely-accepted techniques for monitoring either the reinforcement or the pipe itself.

A research program was conducted that involved the embedding of fiber optics in a steel sleeve and E-glass / epoxy composite repair systems. Measurements from the fiber optic sensors included temperature, hoop strain, and axial strain, which allowed engineers to monitor conditions in both the repair and the pipe sample. The implications of embedded technologies in pipeline repairs are far-reaching, including the ability to monitor not only the reinforcement itself, but also serve as a resource for monitoring pipeline activities including third party damage and land movement. This paper presents results from the test program, but also concepts for continued use of pipeline repair embedded technologies and their impact on the generation of large-scale data and enhancement of integrity management efforts.

Commentary by Dr. Valentin Fuster
2018;():V003T04A002. doi:10.1115/IPC2018-78044.

The present work arose from problems occurred during the revamp of a pipeline SCADA (Supervisory Control and Data Acquisition) system at the beginning of 2012, when occurred some unexpected system crashes that could interrupt the operation of the second major Brazilian pipeline maritime terminal.

Before a system breakdown, we observed some signs, like fail-overs in the event log files. If the development and maintenance crews were aware of these events not only the problem causes could be better understood, but also the imminent crash could have been avoided. A faster and autonomous way for the system communicates its problems was necessary.

ACARS (Aircraft Communications Addressing and Reporting System) — a part of an autonomous communication system, which reports aircraft condition for a system on the ground, through satellite links and short messages — inspired us to develop an Internet of Things (IoT) system, using text messages (SMS, short message service) of the Global System for Mobile Communications (GSM).

Autonomous and short text messages are the keywords that drove our work, and the solution came through a text message gateway — the solution to get information in advance.

This presentation will discuss the idea, hardware and software components, message format, applications and future perspectives.

Commentary by Dr. Valentin Fuster
2018;():V003T04A003. doi:10.1115/IPC2018-78057.

Currently, pipeline is the most effective way to transport large-volume products over long distance. To effectively satisfy market demands for multiple refined products by delivery due dates, the multi-product pipeline network usually transports several refined products in sequence from refineries to certain destinations. The integrated scheduling of multi-product pipeline network, including inventory management, transport routes planning, batch sequence, batch volume, et al., is one of the most strategic problems due to its large-scale, complexity as well as economic significance. This subject has been widely studied during the last decade. However, most researches focus on large-size scheduling models whose computational efficiency greatly decreases for a complex pipeline network or a long time horizon. Aiming at this problem, the paper develops an efficient decomposition approach, which is composed of two mixed integer linear programming (MILP) models. The first model divides the entire time horizon into several intervals according to delivery due dates and optimizes the transport routes and total transport volume during each interval with considering market demand, production campaigns and inventory limits. Then the solved results are used by the second model which sets the objective function as the membership function based on fuzzy delivery due dates. Besides, a series of operational constraints are also considered in the second model to obtain the optimal batch sequence, batch volume, delivery volume and delivery time in each node. Finally, the proposed approach is applied to a Chinese real-world pipeline network that includes 5 complex multi-product pipelines associated with 6 refineries and 2 depots. The results demonstrate that the proposed approach can provide a guideline for long-term pipeline network scheduling with delivery due dates.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2018;():V003T04A004. doi:10.1115/IPC2018-78093.

In the oil and gas industries, it is important to keep pipelines operating at the highest level-of efficiency. This means that a pipeline should not undergo events that may reduce the amount of pumped product at the end of the line. Examples of these events are the existence of debris moving along with the flow, or wax deposited on the pipe wall or the development of a crack or hole on the wall that may lead to the occurrence of a leak. The use of pigs (Pipeline Inspection Gauge) is one of the most common tools for inspection and cleaning of the pipe to restore the optimum pipe operation, despite the uncertainties and risks associated with its passage inside a long duct. For this reason, it is important to follow the pig motion inside the pipeline using numerical simulations. The velocity of the pig depends on the flow dynamics and the pig’s flowing characteristics. This paper presents a mechanical model for the pig motion, along with a numerical scheme, to obtain approximate solutions for the resulting initial-boundary-value problem that describes the pig motion in a transient gas/liquid-flow inside the pipeline in the presence of a leak. The model is formulated as an initial-boundary-value problem of hyperbolic nature. The system of non-linear partial differential equations is discretized within the finite-volume framework and solved using the flux corrected-transport (FCT) method, which is second-order in space. A situation involving a leakage of 10% of total inlet mass flow was simulated and the results are presented for the pig velocity history and for the distribution of flow pressure, velocity and liquid volume fraction along the pipe. In order to validate our results, the commercial software OLGA®, well known in the oil and gas industry, is used for comparison.

Commentary by Dr. Valentin Fuster
2018;():V003T04A005. doi:10.1115/IPC2018-78094.

In the oil industry liquid pipelines are very important for the transport of liquids, particularly in long offshore pipelines. The operation of these oil pipelines is susceptible to the occurrence of leaks in the system. Localizing a leak in a very long oil pipeline is an important piece of information that needs to be obtained before mitigating actions can be taken. These pipelines are usually subject to the temperature gradients that exist in the bottom of the ocean, and the resulting heat transfer process may lead to wax formation and deposition. The single-phase flow that occurs in this type of offshore pipeline that presents one leak point and suffers the effects of an external temperature gradient is numerically simulated in this paper. We consider a one-dimensional mathematical model that includes conservation equations of mass, momentum and energy, and its associated numerical method to calculate the transient liquid flow inside the pipeline. We are particularly interested in testing a leak localization model based upon the intersection of the hydraulic grade lines emanating from the pipeline ends under the influence of a non-zero temperature distribution. This paper proposes to compare the results for a non-isothermal flow with the corresponding isothermal flow to study the influence of the temperature distribution upon the leak localization strategy. The flow that develops along the entire pipeline, upstream and downstream of the leak, strongly affects the pressure gradient and has a significant influence on the location of the leak. Our numerical simulations show results that allow the model sensitivity to be studied by changing the leak magnitude, for a given leak position. From this analysis, we may observe how these parameters affect the pressure gradients along the pipeline that develop upstream and downstream of the leak and the model’s ability to predict the leak location.

Commentary by Dr. Valentin Fuster
2018;():V003T04A006. doi:10.1115/IPC2018-78169.

Pipeline, as one of the transportation modes, is playing an increasingly important role in national economy. But leakages in pipelines may cause severe problems, such as environmental damages and economic loss. Therefore, how to calculate the leak location and leak size has been investigated for last decades. This paper presents a calculation model based on time-domain analysis solution for detecting and locating two leaks in the pipeline. The model is based on a transient event that is generated by fast closure of the valve at the end of a reservoir-pipeline-valve (RPV) system. The presence of leak causes continuous drops in pressure waves and leak information can be revealed by analyzed the leak transient pressure waves. The time of reflection wave represents the leak location and the magnitude of the piezometric head represents the leak size. The governing equations for calculating the leak size are derived as a system of linear equations based on the Method of Characteristics (MOC). The first transient pressure wave was analyzed to obtain the calculation parameters. Then the applicability of this method is verified on simulated pressure data. The results indicate that this model can perfectly solve two leaks problem in a single pipeline.

Topics: Pipelines , Leakage
Commentary by Dr. Valentin Fuster
2018;():V003T04A007. doi:10.1115/IPC2018-78171.

Currently, the oil and gas pipeline network is a key link in the coordinated development of oil and gas upstream and downstream cohesion. To ensure the reliability and safety of oil and gas pipeline network operation, it is necessary to inspect the pipeline periodically to minimize the risk of leakage, spill and theft, as well as documenting actual incidents and the effects on the environment. Traditional manpower inspection is extremely labor-intensive and inefficient. Through the use of UAV (unmanned aerial vehicle) inspection, it is possible to greatly increase efficiencies by reducing the amount of manpower and resources required by traditional inspection methods.

The integrated optimization for UAV inspection path of oil and gas pipeline networks, including physical feasibility, performance of mission, cooperation, real-time implementation, three-dimensional (3-D) space, et al, is a strategic problem due to its large-scale and complexity. Aimed at improving inspection efficiency and maximizing economic benefits, this paper proposes a novel mix-integer linear programming model which could be used for inspection path planning. Minimizing the total inspection time is the objective function of this model. The constraints of the mission scenario and the safety performance of UAV are taken into account. By using evolutionary genetic algorithm, each candidate route can be measured through the evaluation function that takes into account the cost of the route, the mission scenario as well as the cooperative and coordinative requirements among the unmanned aerial vehicles constraints.

Finally, the proposed approach is applied to a virtual oil and gas pipeline network. Compared with the traditional inspection approach, the proposed method is 66.48% less in inspection cost and 22.07% shorter in total inspection time, verifying the rationality and superiority of the model.

Commentary by Dr. Valentin Fuster
2018;():V003T04A008. doi:10.1115/IPC2018-78235.

Transient hydraulic conditions during a shutdown and subsequent start-up of a segment of a pipeline that runs through a mountainous region were simulated using commercially available hydraulic simulation software and a model of the relevant portion of the pipeline facilities. The segment of interest is located in an area where the pipeline is normally operated with vapor present (slack line flow conditions) due to the large change in elevation. Pressure data that was recorded by the pipeline’s data acquisition system indicated a pressure surge occurred when the line was restarted. The suspected cause of this pressure surge was the collapse of the vapor in this pipeline segment. Beginning with an estimate of the flow, pressure and temperature data for the pipeline segment at steady state conditions prior to the shutdown, the simulation was tuned to reasonably match the measured data. The resulting simulated data closely replicated the surge event. Examination of the simulated data provides insights into the hydraulic conditions in the pipeline at locations where pressure data is not measured, as well as during the time intervals between data acquisition scans. It also reveals impact of the timing of the mainline valve opening sequence. Further, since the simulated data does accurately replicate the actual measured data, the model can be used to evaluate how changes to facilities or operating conditions impact the formation and the collapse of vapor in this pipeline segment.

Commentary by Dr. Valentin Fuster
2018;():V003T04A009. doi:10.1115/IPC2018-78244.

Characterizing the acoustic energy associated with small pipeline leaks is of particular interest to pipeline operators who are considering deployment of acoustic based External Leak Detection (ELD) systems along their pipelines. Small leaks are defined here as product leaks having release rates and/or release volumes that fall below the detection threshold currently associated with conventional or traditional leak detection technologies, including but not limited to Computation Pipeline Monitoring (CPM) systems. Characterization of such acoustic energy could be used to predict and evaluate the performance of acoustic based ELD systems in a variety of candidate deployment locations. It could also be used to optimize system performance of existing or future deployed acoustic based ELD systems. This study focuses on investigating the transmission of acoustic energy caused by pressurized fluid releases through two different soil mediums (a dry soil and a saturated soil). Specifically, signal attenuation and frequency content as a function of sensor location from the release source were investigated. To accomplish this, geophones were placed within a large soil filled tank to listen passively to controlled releases of hydrocarbon liquids from a buried pipe segment. These releases were driven through circular shaped orifices ranging in diameter from 0.79 to 4 mm and by pressures ranging from 50 to 500 psi. Signal attenuation was observed in both the longitudinal and radial directions however the effect was more significant in the radial direction. This does not necessarily imply that anisotropic effects exist, but rather a possible explanation is that the acoustic waves traveling along the pipe walls (i.e. in the longitudinal direction) are less attenuated and can therefore carry the acoustic energy further in that direction. In addition, it was found that the dominant bandwidth of the leak signals (which is approximately 600 Hz but it can be as high as 1200 Hz) is inversely proportional to orifice diameter and proportional to the release pressure. Also, the dominant frequency was found to be slightly higher in the saturated soil environment. This study provides insights into expected acoustics characteristics of small liquid leaks, which can help in the selection and placement of appropriate acoustic based ELD systems.

Topics: Acoustics , Pipelines
Commentary by Dr. Valentin Fuster
2018;():V003T04A010. doi:10.1115/IPC2018-78266.

Ultrasonic meters are widely accepted as being robust, reliable and having the ability to provide custody transfer accuracy over varied application ranges. Because of these characteristics and their inherent advanced signal processing and non-intrusive design, the meters have the capability to deliver unique performance and diagnostic information that can be used to improve Pipeline operations and Leak Detection applications.

This paper presents real time data from liquid ultrasonic meters. The data helps to improve pipeline operations including dual Drag Reducing Agent (DRA) injections, Batch Detection (BD), Commodity Movement Tracking (CMT) etc. Diagnostic data can also identify upstream instrumentation anomalies and illustrate the abilities of the utilizing diagnostics within liquid ultrasonic meters to further improve current leak detection real time transient models (RTTM) and pipeline operational procedures. The paper discusses considerations addressed while evaluating data and understanding the importance of accuracy within the metering equipment utilized. It also elaborates on significant benefits associated with the utilization of ultrasonic meters capabilities and the importance of diagnosing other pipeline issues and uncertainties outside of measurement errors.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2018;():V003T04A011. doi:10.1115/IPC2018-78279.

With the continuous development of offshore oil and gas resources, calculation software for multiphase flowing pipe network has become an important tool for the design and daily operation of multiphase flowing pipe network. Improved accuracy of hydraulic and thermal calculation is an engineering requirement for economic and efficient production. Therefore, a new program is developed for multiphase pipe network in this paper. This program contains a general data structure to describe the complex connection of a pipe network. The structure is based on the conception of the incidence matrix and the adjacency matrix in graph theory. Two processes, hydraulic equilibrium calculation and thermodynamic equilibrium calculation are successively taken in this program to gain the steady-state for a multiphase pipe network. For the hydraulic equilibrium calculation, applying flow equation to each pipe in the network gains a pipe flow vector. A nonlinear system of equations, which represent flow balance of each node, is obtained by multiplying the incidence matrix and the pipe flow vector. To solve these equations, the Newton-Raphson iterative algorithm is used and afterwards, the hydraulic parameters of the pipe network are obtained. For thermal equilibrium calculation, since all the temperature of source nodes is known, the key step is to find the solution order of other node temperature. The program obtains the order by transforming the adjacency matrix. Deng temperature drop formula is used to calculate the end temperature of each pipe. When a node has more than one inflow, an average temperature based on the heat capacity and mass flow is adopted after gaining each pipe’s outlet temperature. Combining hydraulic and thermal algorithms, a complete set of solution program for steady-state of multiphase pipe network is compiled. In the end, two cases are performed to check the accuracy of the program. In the first case, a pipe network is created by using the data collected from a condensate gas gathering network in the South China Sea. The result indicates that the program has a good agreement with the actual data. In the second case, the program is applied in a single-phase network and gains almost the same result calculated by PipePhase and PipeSim.

Topics: Pipes , Steady state
Commentary by Dr. Valentin Fuster
2018;():V003T04A012. doi:10.1115/IPC2018-78326.

Based on process principles and the operational features of crude oil pipelines, this research developed mathematical models to optimize steady-state pipeline operation, to apportion monthly flow into daily or hourly flow rates, and to predict monthly energy consumption. Corresponding algorithms were also developed. Because these models and corresponding algorithms are process-based, they are suitable for predicting monthly energy consumption of existing isothermal and hot crude oil pipelines. The predicted monthly energy consumption of crude oil pipelines depends on which flow distribution method is used, which pumping operation scheme is used and which heating operation scheme is used, with different flow distributions, different pumping and heating operation scheme yielding a range of monthly energy consumption predictions for a given transportation volume. The minimum monthly energy consumption can be determined from these predictions, and the interval of the predictions can indicate the extent to which the flow rate fluctuation affects pipeline energy consumption. Both of these findings can be used by pipeline operators to reduce the amount of energy needed to operate crude oil pipelines.

Commentary by Dr. Valentin Fuster
2018;():V003T04A013. doi:10.1115/IPC2018-78327.

Natural gas is a vital energy carrier which can serve as an energy source, which is extremely vulnerable to leakages from pipeline transportation systems. The required ignition energy is low. Although the safety of natural gas pipelines has been improved, the average economic loss of natural gas accidents, including leaks, is large. To solve these problems, an acoustic leak localization system is designed and researched for gas pipelines using experiments with methods proposed according to different application situations. The traditional method with two sensors installed at both ends can be improved by a newly proposed combined signal-processing method, which is applied for the case that it is necessary to calculate the time differences with data synchronicity. When the time differences cannot be calculated accurately, a new method based on the amplitude attenuation model is proposed. Using these methods, the system can be applied to most situations. Next, an experimental facility at the laboratory scale is established, and experiments are carried out. Finally, the methods are verified and applied for leak localization. The results show that this research can provide a foundation for the proposed methods. The maximum experimental leak localization errors for the methods are −0.592%, and −7.62%. It is concluded that the system with the new methods can be applied to protect and monitor natural gas pipelines.

Commentary by Dr. Valentin Fuster
2018;():V003T04A014. doi:10.1115/IPC2018-78341.

Considering market’s diversified demand and transport economy, large volumes of various refined products commonly move down the pipeline in batches, which are pumped at pump stations and delivered to respective delivery stations. The integrate detailed scheduling optimization is a sophisticated problem due to the characteristics of multi-product pipelines, such as market-oriented, fluctuated demand, various processing technique and complicated hydraulic calculation during batch migration. The integrate detailed scheduling optimization has been widely studied during the last decade, however, most of them studied pipeline scheduling and pump scheduling separately. Besides, the proposed methods are mathematical models, whose computational efficiency greatly decreases in large-scale pipeline scheduling, let alone in the problems coupling with pump scheduling.

Aiming at this problem, this paper presents a novel depth-first searching approach based on flowrate ratio to deal with the detailed scheduling of operations in a multi-product pipeline with multiple pump stations. As for each single time interval, the proposed method decides an ideal flowrate ratio according to current status, then solves out the optimal flowrate that mostly conforms to the ideal ratio and satisfies all operational constraints, and finally updates information for next time interval. However, during the computational procedure, backtracking method would be adopted to modify the previous flowrate ratios and recalculate new flowrate when the actual delivered products are insufficient. Finally, a case tested on a Chinese real-world pipeline with 6 delivery stations is given to demonstrate the veracity and practicability of the proposed method. From the results, computing time of the case is within 1 minute, and the solved detailed scheduling plans can fulfill demand with stable pump operations. Besides, the proposed approach is scarcely influenced by the scale of pipeline structure and time horizon, so it is also applicable to the long-term scheduling of a pipeline with many delivery stations.

Topics: Pipelines , Pumps
Commentary by Dr. Valentin Fuster
2018;():V003T04A015. doi:10.1115/IPC2018-78343.

Product losses from pipelines, whether attributed to acts of man or nature, amount to operator losses of approximately USD 133 billion annually [1], not even considering costs associated with remediation, environmental damage, and reputational harm. When an incident occurs, pipeline operators need to minimize the event by quickly and accurately locating and quantifying the pipeline loss and its cause. Having this detailed knowledge enables determination of the best method for dealing with possible issues while helping minimize remediation costs, pipeline downtime, and the impact of the work on surrounding infrastructure.

Currently, most systems for pipeline leak detection are limited to either listening methods, which require being online and monitoring both pipeline ends at the moment the leak occurs, or intrusive methods that require the insertion of a pig into the pipeline. Both of these techniques are restricted in usage because access should be available to both ends of the pipeline. Additionally, for the intrusive method, the pipeline should be piggable and, for the listening method, the instrumentation should be able to communicate with a central data processing point placed at both pipeline ends as they rely on travel time difference between signals received at either end of the pipeline.

The method this paper describes is a proven, nonintrusive technology that can be used by pipeline operators to identify losses quickly and safely with a repeatable and verified high level of accuracy. It monitors the signature response of a generated fluid hammer and resulting pressure wave transiting within the pipeline and analyzes the reflected signature wave and pressure data to extrapolate both the location and magnitude of the loss with all pipeline parameters taken into account. The method enables operators to detect, locate, and quantify the loss of pipeline inventory in a safe and cost-effective manner without having to stop production, beyond the temporary closing of a mainline valve, or risk tools or personnel, due to exposure to pressurized fluids, before performing any intervention at the leak site.

Commentary by Dr. Valentin Fuster
2018;():V003T04A016. doi:10.1115/IPC2018-78426.

Demonstrating the ability to reliably detect pipeline ruptures is critical for pipeline operators as they seek to maintain the social license necessary to construct and upgrade their pipeline systems. Current leak detection systems range from very simple mass balances to highly complex models with real-time simulation and advanced statistical processing with the goal of detecting small leaks around 1% of the nominal flow rate. No matter how finely-tuned these systems are, however, they are invariably affected by noise and uncertainties in a pipeline system, resulting in false alarms that reduce system confidence. This study aims to develop a leak detection system that can detect leaks with high reliability by focusing on sudden-onset leaks of various sizes (ruptures), as opposed to slow leaks that develop over time. The expected outcome is that not only will pipeline operators avoid the costs associated with false-alarm shut downs, but more importantly, they will be able to respond faster and more confidently in the event of an actual rupture. To accomplish these goals, leaks of various sizes are simulated using a real-time transient model based on the method of characteristics. A novel leak detection model is presented that fuses together several different preprocessing techniques, including convolution neural networks. This leak detection system is expected to increase operator confidence in leak alarms, when they occur, and therefore decrease the amount of time between leak detection and pipeline shutdown.

Commentary by Dr. Valentin Fuster
2018;():V003T04A017. doi:10.1115/IPC2018-78459.

There are many closed side branches in the gas conveying pipeline system. When the gas passes through the closed side branch, the shear layer will arouse the acoustic resonance in the closed side branch, which is harmful to the safe operation of the pipeline. The research work is insufficient about the influence of the cross-section shape of the closed side branch on acoustic resonance. Using the Detached-Eddy Simulation (DES) model, the acoustic resonance characteristics caused by the side branch pipe with different square cross-sections are simulated at the inlet boundary conditions of 25 m/s, 30 m/s and 35 m/s. The results show that in the center axis of the side branch, a 1/4 wavelength standing wave was formed, and the acoustic resonance occurs at a higher Strouhal number in circular branch. The cross-section shape of the side branch does not affect the acoustic resonance frequency, but it has a certain influence on the amplitude of pressure fluctuation and has a significant influence on the high-order frequency components.

Commentary by Dr. Valentin Fuster
2018;():V003T04A018. doi:10.1115/IPC2018-78499.

A recent trend in the field of pipeline monitoring has been the utilisation of an optical fibre based distributed acoustic sensing (DAS) technology, for the purpose of security monitoring of buried pipelines [1–3]. The technology comprises an interrogator, connected to an optical fibre cable, which is interrogated to acquire coherent Rayleigh backscatter. Localised environmental vibrations may result in a proportional strain of the fibre. This strain results in a localised optical path length variation, resulting in a phase distortion in the measured signals. Application of signal processing techniques infer the characteristic of the originating stimulus, and thus identify and locate the source activity of interest. Activity may arise as a result of ground excavation, vehicular movement, or similar in the vicinity of the pipeline.

Researchers are now studying the possibility of utilisng this technology for the purpose of pipeline leak detection monitoring [4]. This paper provides a review of one such programme of work.

Results are presented for a permanent installation, where signatures relating to leaks were identified, and located in the resulting DAS data. Results are provided relating to liquid leaks, where product was emitted at a flow rate of 20.0l/minute and operational pressure 20.0bar.

Commentary by Dr. Valentin Fuster
2018;():V003T04A019. doi:10.1115/IPC2018-78534.

The master-slave topology, based on programmable logic controllers and their respective controlled equipment are often characterized by the use of intermediate devices called Master Stations that perform the interface between data processing and triggering unit, and are responsible for protocol conversion, data acquisition, priority setting, and management of slave devices. For the most part, these intermediate control devices are systems developed by manufacturers and process equipment suppliers themselves, more specifically in the control of large quantities of motorized valves in industrial plants. As a result, a project was implemented to implement control and supervision information exchange routines of the motorized valve system directly through the PLC / Supervisory System, eliminating the need for the use of intermediate control devices. The results show high simplification in the architecture by removing the Master Station and changing the network topology, attaining an overall cost reduction, and a great improvement on performance, by the higher communication speed levels, especially for decreasing the latency delays; lastly, control centralization into more robust equipment and network segregation of the valve system, turned it easier to diagnose failures, ensured operational continuity, reduced the statistic of failures and increased the reliability of the process.

Commentary by Dr. Valentin Fuster
2018;():V003T04A020. doi:10.1115/IPC2018-78548.

Onshore, liquid pipelines are often modeled with isothermal models. Ignoring thermal effects is justified because thermal effects are of secondary importance and because the data, such as burial depth, soil thermal conductivity, soil heat capacity, and soil density, required to accurately predict thermal behavior in buried pipelines is not known accurately. In addition, run speeds are faster for isothermal models than for rigorous thermal models, which is particularly important in real-time models. One condition where thermal effects become important is when a pipeline is shut-in. Pumps increase the temperature of the fluid, so the fluid temperature is, on average, greater than ambient temperature. When a pipeline is shut-in, the temperature decreases causing a corresponding decrease in pressure. Since an isothermal model does not account for this behavior, the decreasing pressure can be misinterpreted as a leak. This paper discusses a strategy for correcting the model to properly account for the behavior in shut-in conditions. The strategy is applied to real-time pipeline models using Synergi Pipeline Simulator (SPS), although the method is applicable to any isothermal model.

Commentary by Dr. Valentin Fuster
2018;():V003T04A021. doi:10.1115/IPC2018-78615.

Excavation damage is one of the top causes of incidents in both the transmission and distribution pipeline sectors. Damage caused from insufficient notification of one-call centers or careless digging near gas pipelines can potentially result in property damage, significant injury, and/or loss of life. Pacific Gas and Electric Company (PG&E) and the Gas Technology Institute (GTI) have developed the framework for an Excavation Encroachment Notification (EEN) system to support damage prevention efforts to reduce damage from excavation activity. The research was funded by the California Energy Commission (CEC) and Operations Technology Development (OTD).

The system utilizes real-time Geographic Information System (GIS) technology and cellular-connected location and motion sensors placed on excavation equipment. Controlled and field-based testing and training of machine learning algorithms were conducted to aid in characterization of excavation equipment. Additionally, a GIS system populated with pipeline information allowed operators of excavation equipment and utilities to receive an alarm and indication when equipment is adjacent to or excavating in the vicinity of a gas pipeline. More broadly, the utility stakeholder has increased situational awareness of excavation activities within its service territory with access to the real-time activity of excavation equipment through a mobile-compatible dashboard, reducing excavation damage risk and improving safety. Lastly, the project offers historical data archiving for data analysis and trend identification.

Commentary by Dr. Valentin Fuster
2018;():V003T04A022. doi:10.1115/IPC2018-78619.

The use of drag reduction agents (DRA) can be a decisive factor in determining the technical and economic feasibility of new pipelines projects, meeting the demands not foreseen and seasonality accommodation without large investments in infrastructure. Knowing the friction reduction mechanism and its impact on the operating procedure of existing products is essential in order to have the guarantee of the benefit for your application.

Most of the works published report field experiences obtained from its application, seeking to determine the influence that internal and external factors have on the polymer. Knowing these effects is essential for better application performance. However, few authors have sought to identify the best way to operate an existing pipeline with DRA, with either an increase in capacity or an energy reduction.

Operationally, the use of drag reducing agents may decrease the currently used arrangement of pumps, or even the complete shutdown of a pumping station. In this context, the use of drag reducers may be a suitable solution for decreasing power consumption in fluid transport pipelines of petroleum and derivatives.

This paper presents a case study of the application of drag reducing agents in a Brazilian high-energy pipeline. It features five intermediate pumping stations and three withdrawal points along its nearly one thousand kilometer stretch. With the aid of a computer simulation software, it is proposed a methodology to evaluate the best application condition, minimizing pump costs, polymer volume and meeting the scheduled demand of the month.

This methodology first sought to validate the computational model of the pipeline. It was made a historical survey and inserted into the simulator, in order to reproduce faithfully a monthly operation. A sensitivity analysis is performed to determine which pump stations are most relevant. It was established an initial concentration of polymer to be injected in the sending refinery, aiming the reduction of arrangement or total shutdown of the subsequent station and keeping volume delivered on all points. The other bases remain working according to the operation of the month. This procedure is then repeated for the other bases, resulting in a combined and continuous injection, minimizing the operating costs.

An economic evaluation is finally performed to quantify the benefits of this application. A reduction in energy consumption of 49% was noticed, and considering the costs with DRA, the monthly movement had a 35% drop in the total costs of operation.

Commentary by Dr. Valentin Fuster
2018;():V003T04A023. doi:10.1115/IPC2018-78624.

This paper presents the results of the testing of an oil-on-water leak detection technology for isolated locations without power or communications infrastructure. A special attention was paid to the ability of the sensors to detect hydrocarbon leaks under freezing conditions, with thick ice formed on the surface of the water. A viable solution for remote locations and large water crossings needs ultra low-power solution and/or cyclic operation. The technology evaluated was a fully passive impedance polymer-absorption sensor (PAS) featuring “zero-power” consumption. This technology also provides an additional advantage, “an event memory”, and is perfectly suitable for cyclic operation for detecting moving oil stains. In October 2017 three polymer-absorption sensors of different lengths were placed in outdoor location in Ontario, Canada for long-term testing of reliability in freezing conditions. The sensors were connected to cellular modem for generating alerts. Another battery of three sensors of same lengths was installed in outdoor testing facility near Ottawa, ON, Canada and connected to real-time data acquisition equipment. A preliminary series of leak tests performed in October/November 2017 confirmed the initial assumptions of excellent sensitivity of the hydrocarbon oil-on-water detection based on polymer absorption. The average power consumption of the sensor excitation and its measurement frontend during the first two months of testing were found to be extremely low, a fraction of the power needed for the wireless modem itself. The leak tests were extended to oil under ice detection performed with 5 North-American crude oils and with 3 refined products from Mid-December 2017 to Mid-February 2018. The sensitivity, the sensor excitation/measurement front end power consumption, and the reliability of the sensors were assessed at freezing temperatures, with thickness of the ice comprised between 80 and 100 mm. The paper also presents the availability of stand-alone communication equipment suitable for integrating oil-on-water sensors, as well the energy harvesting or energy storage technologies for different climatic conditions.

Commentary by Dr. Valentin Fuster
2018;():V003T04A024. doi:10.1115/IPC2018-78640.

The timely detection of small leaks from liquid pipelines poses a significant challenge for pipeline operations. One technology considered for continual monitoring is distributed temperature sensing (DTS), which utilizes a fiber-optic cable to provide distributed temperature measurements along a pipeline segment. This measurement technique allows for a high accuracy of temperature determination over long distances. Unexpected deviations in temperature at any given location can indicate various physical changes in the environment, including contact with a heated hydrocarbon due to a pipeline leak.

The signals stemming from pipeline leaks may not be significantly greater than the noise in the DTS measurements, so care must be taken to configure the system in a manner that can detect small leaks while rejecting non-leak temperature anomalies. There are many factors that influence the frequency and intensity of the backscattered optical signal. This can result in noise in the fine-grained temperature sensing data. Thus, the DTS system must be tuned to the nominal temperature profile along the pipe segment. This customization allows for significant sensitivity and can utilize different leak detection thresholds at various locations based on normal temperature patterns. However, this segment-specific tuning can require a significant amount of resources and time. Additionally, this configuration exercise may have to be repeated as pipeline operating conditions change over time. Thus, there is a significant need and interest in advancing existing DTS processing techniques to enable the detection of leaks that today go undetected by DTS due to their signal response being too close to the noise floor and/or requiring significant resources to achieve positive results.

This paper discusses the recent work focused on using machine learning (ML) techniques to detect leak signatures. Initial proof-of-concept results provide a more robust methodology for detecting leaks and allow for the detection of smaller leaks than are currently detectable by typical DTS systems, with low false alarm rates. A key use of ML approaches is that the system can “learn” about a given pipeline on its own without the need to utilize resources for pipeline segment-specific tuning. The potential to have a self-taught system is a powerful concept, and this paper discusses some key initial findings from applying ML-based techniques to optimize leak detection capabilities of an existing DTS system.

Commentary by Dr. Valentin Fuster
2018;():V003T04A025. doi:10.1115/IPC2018-78643.

In a Supervisory Control and Data Acquisition (SCADA) system, operators use a human-machine interface (HMI) to interact with the process through industrial protocols, which have specific drivers (software pieces) installed in the SCADA servers. If the process device manufacturer does not develop a driver for its equipment, a gateway, with a protocol translator can be provided with the equipment, to translate its particular protocol to a standard industrial one, like the so popular Modbus.

This work presents the development of a gateway — protocol translator — that connects an odorant unit of a pipeline terminal, which has a proprietary protocol to an industrial protocol Modbus TCP/IP. All development is made with Open Source software.

The subject matter is extended to describe the solution to an issue observed due to the lack of a flowmeter in the odorant unit, where a Kalman filter was used as an estimator, to provide a virtual meter.

Commentary by Dr. Valentin Fuster
2018;():V003T04A026. doi:10.1115/IPC2018-78715.

When transporting multiple products in a pipeline, it is important to always understand the location of the head and tail of each batch. The operator will know where batch interfaces are in real-time and be ready to swing the valve at the exact time a batch arrives at a station to deliver product to the right storage tank or an end-customer with minimal contamination. It is relatively easy to track multiple batches in a pipeline with no elevation changes, and a fixed internal diameter. However, it is far more complex to track multiple batches in a pipeline with drastic elevation changes and different sizes in diameter. Column separation of the liquid, also known as slack, occurs when the pipeline pressure drops below the vapor pressure calculated at the liquid temperature in a specific area of the pipeline. This effect reduces the amount of liquid volume contained within the pipeline region, changing the actual physical position of the batch head and tail interfaces, and reducing the accuracy of the volume within the region and the corresponding Estimated Times of Arrival at stations. Draining or filling a pipeline section by delivering product at a different rate from what injected causes the same effect.

A scientific approach to calculate the areas of slack and volume contained within a pipeline should provide sufficient information to track batches with a high degree of accuracy. However, it is neither simple nor straightforward to simulate this phenomenon offline, and it is much more challenging in an online, real-time environment. Online, additional complexities affect how batches and their interfaces are tracked, causing a big discrepancy between Estimated and Actual Time of Arrivals. This paper discusses an empirical approach developed to calculate the volume contained within a pipeline region by tracking the volume entering and leaving the region.

Estimated and Actual Times of Arrival are within a 15-minute time window after a batch has traveled a total distance of 1,200km with drastic elevation changes along the route. This method has proven that batch tracking can be highly accurate and reliable with less of the theoretical assumptions used in a hydraulic simulation package, with no need to model every single characteristic of the pipeline in detail. This removed the uncertainties that attend those assumptions and allowed this system to perform well on a pipeline with severe slack flow and draining/filling operations.

Commentary by Dr. Valentin Fuster
2018;():V003T04A027. doi:10.1115/IPC2018-78743.

Crude oil transportation pipelines depend on Computational Pipeline Monitoring (CPM) systems for leak detection. Accurate prediction of the volume of vapor phase in the pipeline is very challenging when crude oil goes though phase change (column separation) in the pipeline. It is also challenging to accurately predict the vapor phase volume when the pipeline is started from extended shut-in period during which thermal cooling or heating can occur depending on the season of the year. Pipeline operators rely on the accuracy of CPMs to make decisions on column separation and to avoid the masking of a leak during column separation. The column separation can happen due to heating and/or cooling during extended pipeline shut-in, or due to elevation changes or due to flow transients.

New methods of approach to address the hydraulics are necessary when dealing with a pipeline during shut-in period. Particularly a shut-in pipeline has no longitudinal motion of fluid, however phase change occurrence attempts to set the stationary fluid inside a pipe into motion and overcoming this difficulty was not available in the literature perhaps due to lack of encumberment with similar problems. This paper explains mechanism of column separation and its transients in pipelines during extended shut-in period. The results for a 90 Km long-pipeline shut-in over a 78-hour period will be presented to show the evolution of flow field and column separation (vapor phase change) prediction and hydrodynamic pressure in the whole pipeline over the shut-in period. This paper will also critically review the current approaches available in the literature to predict the column separation.

Commentary by Dr. Valentin Fuster
2018;():V003T04A028. doi:10.1115/IPC2018-78753.

The Pipeline Open Data Standard (PODS) Association develops and advances global pipeline data standards and best practices supporting data management and reporting for the oil and gas industry. This presentation provides an overview of the PODS Association and a detailed overview of the transformed PODS Pipeline Data Model resulting from the PODS Next Generation initiative.

The PODS Association’s Next Generation, or Next Gen, initiative is focused on a complete re-design and modernization of the PODS Pipeline Data Model. The re-design of the PODS Pipeline Data Model is driven by PODS Association Strategy objectives as defined in its 2016–2019 Strategic Plan and reflects nearly 20 years of PODS Pipeline Data Model implementation experience and lessons learned.

The Next Gen Data Model is designed to be the system of record for pipeline centerlines and pressurized containment assets for the safe transport of product, allowing pipeline operators to:

• Achieve greater agility to build and extend the data model,

• respond to new business requirements,

• interoperate through standard data models and consistent application interface,

• share data within and between organizations using well defined data exchange specifications,

• optimize performance for management of bulk loading, reroute, inspection data and history.

The presentation will introduce the Next Gen Data Model design principles, conceptual, logical and physical structures with a focus on transformational changes from prior versions of the Model. Support for multiple platforms including but not limited to Esri ArcGIS, open source GIS and relational database management systems will be described. Alignment with Esri’s ArcGIS Platform and ArcGIS for Pipeline Referencing (APR) will be a main topic of discussion along with how PODS Next Gen can be leveraged to benefit pipeline integrity, risk assessment, reporting and data maintenance. The end goal of a PODS implementation is a realization of data management efficiency, data transfer and exchange, to make the operation of a pipeline safer and most cost effective.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2018;():V003T04A029. doi:10.1115/IPC2018-78791.

Reliability and sensitivity are two main performance metrics of leak detection systems as defined by API 1130 [1]. Proper thresholding scheme is one of the primary factors in having a sensitive and reliable leak detection system with timely detection. In RTTM leak detection, if not dealt with properly, severe pipeline pressure transients can degrade the performance of the leak detection system. One of the common basic methods of reducing the effect of pressure transients is using moving averaging windows; having looser thresholds on the shorter averaging windows, while maintaining tighter thresholds on the longer ones. The thresholds are typically set to meet the API 1149 [2] curve for the pipeline. While the post-processing of filtered data and alarm assessment has been explored via different methods such as sequential probability ratio test, to the authors’ knowledge, there is currently no systematic way of selecting the averaging windows to minimize false alarms prior to the post-processing of the average-filtered data. Moreover, to be able to maintain tight thresholds, especially in shorter averaging windows, one of the common methods is to apply dynamic thresholds, i.e. temporarily expanding thresholds when transients occur. While effective in some scenarios, the main disadvantage of this method is that the imbalance caused by a transient may not clear until the entire averaging window period is passed. This causes either extended periods of degraded performance, or more false positives. This paper utilizes an alarming hold time (also referred to as alarm persistence [3]) to remedy this problem where the averaging window length is reduced while maintaining detection time and sensitivity. To find the optimal set of threshold values, hold times, and averaging window lengths, a Particle Swarm Optimization (PSO) is performed. The ‘fitness function’ of the optimization algorithm is designed to minimize total spill volume for leak scenarios and have minimum false alarms for no-leak scenarios. The former is achieved via setting the objective function to the spill volume and the latter is enforced via applying constraints to the optimization algorithm. For no-leak scenarios, the historical operational data of a pipeline system is used. For leak scenarios, the historical data is modified by introducing a bias in the inlet volume of the section to simulate a leak. The result of the PSO provides a set of alarming parameters, threshold value, averaging window length, alarm hold time, and clearing threshold that provide the minimum false alarm rate and spill volume for different detectability ranges. The optimization method proposed in this paper can be applied to any mass or volume balance-based leak detection system that utilizes moving averaging windows. However, the leak detection parameters found with this method depend on the pipeline system.

Topics: Optimization , Leakage
Commentary by Dr. Valentin Fuster

Operations, Monitoring, and Maintenance: Geohazards

2018;():V003T04A030. doi:10.1115/IPC2018-78013.

Earthquake hazard management for oil and gas pipelines should include both preparedness and response. The typical approach for management of seismic hazards for pipelines is to determine where large ground motions are frequently expected, and apply mitigation to those pipeline segments. The approach presented in this paper supplements the typical approach but focuses on what to do, and where to do it, just after an earthquake happens. In other words, we ask and answer: “Is the earthquake we just had important?”, “What pipeline is and what sites might it be important for?”, and “What should we do?”

In general, modern, high-pressure oil and gas pipelines resist the direct effects of strong shaking, but are vulnerable to large co-seismic differential permanent ground displacement (PGD) produced by surface fault rupture, landslides, soil liquefaction, or lateral spreading. The approach used in this paper employs empirical relationships between earthquake magnitude, distance, and the occurrence of PGD, derived from co-seismic PGD case-history data, to prioritize affected pipeline segments for detailed site-specific hazard assessments, pre-event resiliency upgrades, and post-event response.

To help pipeline operators prepare for earthquakes, pipeline networks are mapped with respect to earthquake probability and co-seismic PGD susceptibility. Geological and terrain analyses identify pipeline segments that cross PGD-susceptible ground. Probabilistic seismic models and deterministic scenarios are considered in estimating the frequency of sufficiently large and close causative earthquakes. Pipeline segments are prioritized where strong earthquakes are frequent and ground is susceptible to co-seismic PGD. These may be short-listed for mitigation that either reduces the pipeline’s vulnerability to damage or limits failure consequences.

When an earthquake occurs, pipeline segments with credible PGD potential are highlighted within minutes of an earthquake’s occurrence. These assessments occur in near-real-time as part of an online geohazard management database. The system collects magnitude and location data from online earthquake data feeds and intersects them against pipeline network and terrain hazard map data. Pipeline operators can quickly mobilize inspection and response resources to a focused area of concern.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2018;():V003T04A031. doi:10.1115/IPC2018-78047.

Many pipelines are built in regions affected by harsh environmental conditions where changes in soil texture between winter and summer increase the likelihood of hazards. Pipeline routes also cross mountains that are characterized by steep slopes and unstable soils as in the Andes and along the coastal range of Brazil. In other cases, these pipelines are laid in remote areas with significant seismic activity or exposure to permafrost. Depending on weather conditions and location, visual inspection is difficult or even impossible and therefore remote sensing solutions for pipes offer significant advantages over conventional inspection techniques. Optical fibers can help solve these challenges. Optical fiber based geotechnical and structural monitoring use distributed measurement of strain and temperature thanks to the sensitivity of Brillouin scattering to mechanical and thermal effects. The analysis of scattering combined with a time domain technique allows the measurement of strain and temperature profiles. Temperature measurement is carried out to monitor soil erosion or dune migration through event quantification and spatial location. Direct measurement of strain in the soil also improves the detection of environmental hazards. As an example, the technology can pinpoint the early signs of landslides. In some cases, actual pipe deformation must be monitored such as in the case of an active tectonic fault crossing. Pipe deformation monitoring operation is achieved by the measurement of distributed strain along fiber sensors attached to the structure. This paper comprehensively reviews over 15 years of continuous development of pipeline geohazard risk monitoring with optical fiber distributed sensors from technology qualification and validation to its implementation in real cases as well as its successful continuous operation. Case studies presented include pipeline monitoring in Arctic and Siberian environment as well as in the Andes which illustrate how the technology is used and demonstrate proof of early detection and location of geohazard events such as erosion, landslide, settlement and pipe deformation.

Commentary by Dr. Valentin Fuster
2018;():V003T04A032. doi:10.1115/IPC2018-78129.

Terrain analyses and geologic hazards assessments are recognized as important components for pipeline planning, permitting, and asset management. Although the two types of assessments have inherently different objectives and outputs, there is some overlap in the results between the two and they tend to complement each other; thus, there are benefits to conducting the two assessments in parallel, and integrating the results. Likewise, situations may arise where information from both assessments may simultaneously prove useful in driving decision-making.

Terrain analyses seek to identify homogenous terrain units based on material types, surface expression, depth to bedrock, slope, drainage, and geomorphological processes. Information compiled during a terrain analysis helps to develop a detailed understanding of the local terrain, which can be used to estimate geotechnical soil properties, provide cost savings, and formulate sound decision-making throughout the life of a pipeline.

Geologic hazards assessments generally seek to individually identify, map, characterize, and ultimately allow for mitigation/monitoring of potential geologic hazards, through increasingly detailed geomorphic/geologic assessments. Some typical geologic hazards that are evaluated include landslide, seismic, subsidence, and hydrotechnical hazards. Once identified, a qualitative hazard classification (e.g., low, moderate, high) is generally assigned to each possible hazard, based on several criteria such as the activity level of the geologic process, rate and magnitude of movement of the hazard, the areal extent and proximity of the hazard, the estimated likelihood that the hazard would affect or engage a pipeline during its service life. The hazard classifications are often then tied to recommendations for additional assessment and/or response and mitigation.

The identification of a landslide will be used as an example to highlight how the two assessments can overlap and complement one another, but still provide unique information, and how the two assessments can be used in conjunction to inform better decision-making. Both assessments may identify the location of the same landslide or potentially unstable slope. The geologic hazards assessment would further characterize the landslide’s spatial relationship to the pipe both laterally and vertically, its activity level, etc., in order to evaluate the potential hazard the landslide poses to the pipeline. If mitigation was deemed necessary, information from both the terrain mapping and geologic hazards assessment could be used to evaluate the specific characteristics of the landslide, as well as the surrounding terrain, in order to select the most suitable form of mitigation.

Topics: Hazard analysis
Commentary by Dr. Valentin Fuster
2018;():V003T04A033. doi:10.1115/IPC2018-78225.

Geohazards are threats of a geological, geotechnical, hydrological, or seismic/tectonic nature that may negatively affect people, infrastructure and/or the environment. In a pipeline integrity management context, geohazards are considered under the time-independent threat category of Weather-related and Outside Force in the American standard ASME B31.8S. Geotechnical failure of pipelines due to ground movement is addressed in Annex H and elsewhere in the Canadian standard CSA-Z662. Both of these standards allow flexibility in terms of geohazard assessment as part of pipeline integrity management. As a result of this flexibility, many systems for identifying, characterizing, analyzing and managing geohazards have been developed by operators and geotechnical engineering practitioners. The evolution of these systems, and general expectations regarding geohazard assessment, toward quantitative geohazard frequency assessment is a trend in recent pipeline hearings and regulatory filings in Canada. While this trend is intended to frame geohazard assessment in an objective and repeatable manner, partitioning the assessment into a series of conditional probability estimates, the reality is that there is always an element of subjectivity in assigning these conditional probabilities, requiring subject matter expertise and expert judgment to make informed and defensible decisions. Defining a specific risk context (typically loss of containment from a pipeline) and communicating uncertainty are important aspects of applying these types of systems. Adoption of these approaches for alternate risk contexts, such as worker safety during pipeline construction, is challenging in that the specific geohazards and threat scenarios considered for long-term pipeline integrity may or may not adequately represent all credible threats during pipeline construction. This paper explores the commonalities and differences in short- and long-term framing of geohazard assessment, and offers guidance for extending geohazard assessment for long-term pipeline integrity to other contexts such as construction safety.

Commentary by Dr. Valentin Fuster
2018;():V003T04A034. doi:10.1115/IPC2018-78422.

US pipeline operators may receive USGS automated earthquake notifications. In most of these cases, the seismic event poses little threat to pipeline assets. However, until an analysis is performed there can be uncertainty as to when and what actions should be taken.

The paper describes the development and implementation of a simplified screening process to assess the effects of seismic events on buried pipelines. A design basis was established based on a literature review of seismic models, seismic-pipeline interactions, von Mises equivalent pipeline stress limits, standards, regulations, and practices that are currently used to assess seismic effects on buried pipelines. This design basis was used to develop a screening tool that provides a simple “pass/no pass” determination and is based on the readily obtained attributes (seismic magnitude and pipeline distance from the earthquake epicenter).

“No Pass” scenarios are sub-divided into medium or high threat categories, with the latter likely needing to be evaluated on a more detailed basis.

General guidelines and charts have been developed and incorporated into a general procedure to assess when and what actions should be taken.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2018;():V003T04A035. doi:10.1115/IPC2018-78571.

Interferometric Synthetic Aperture Radar (InSAR) is a type of active remote sensing whereby a satellite transmits electromagnetic radiation (microwaves) at the ground and measures the differential phase of the reflected signal over multiple images (or multiple antennas on a single satellite). InSAR has the potential to provide centimeter and even millimeter-scale measurements of displacement over time, but is sensitive to vegetation, topography, and atmospheric effects. We consider herein, the application of InSAR at two known landslides on the Enbridge pipeline system, and discuss the strengths, weaknesses, values, and limitations of its application in the Geohazard Management of landslides impacting pipeline ROW’s. We compare information provided at each site by InSAR (both L-band and X-band) to data derived by mapping using Light Detection and Ranging (LiDAR) or air photographs, to differential LiDAR techniques, and to data derived from subsurface measurements (slope inclinometers). In doing so we find that L-Band data can be an effective tool to establish the extent or footprint of movement (or lack of movement) at known landslide locations, extending the interpretive power of a specialist and the understanding of event magnitude, and potentially affecting the mitigation options. Further, L-Band InSAR can be used in a supporting role to pre-screen areas for active landslides along the right of way (ROW), however, data gaps, a lack of explanatory power, and considerable noise in the results mean that a user step that further considers the terrain, other sources of data, and the identified magnitude, is essential. X-Band InSAR appeared impractical for ROW monitoring where vegetation prevented coherence between images, however, X-Band InSAR was able to detect small displacements at above ground infrastructures.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2018;():V003T04A036. doi:10.1115/IPC2018-78630.

Construction blasting was proposed as a technique to create a trench for a new pipeline within the right-of-way (ROW) of an existing vintage pipeline where soil conditions consisted primarily of rock. Several field experiments were conducted to assess the potential loading conditions that the vintage pipeline could experience due to various blasting configurations as part of the nearby construction process. Two test pipe segments were constructed from segments removed from the vintage pipeline for use in these experiments. Each test segment contained two vintage bell-bell chill ring girth welds (GW) and were pressurized to operating conditions of the vintage pipeline for the duration of all blasting. Groups of eight resistive strain gages were bonded around the exterior surface of three distinct locations on each test segment. The three locations include one pipe body location and each of the two welds on each segment.

Four separate experiments were conducted with each experiment focusing on a unique combination of trench backfill material, compaction level and separation distance from the test pipe segments and the explosive charges. The primary objective throughout these four experiments was to monitor and record the behavior of buried test pipe sections due to nearby blasting activities. Long range 3-dimentional (3D) laser scanning equipment was used to track movement of each test segment from test to test. High-speed video equipment was also employed to capture each blast. The high-speed video provided additional details on the blast energy transfer, verification of individual charge initiation as well as pipeline test segment movement where each pipeline segment was exposed. Peak particle velocity measurements were taken during each test blast. Strain data collected during each test was used to assess potential damage to the vintage pipeline test segments as a result of blasting.

The combined information collected from the in-field testing showed that elevated strains and stresses may be observed during blasting activities near pipelines.

Topics: Blasting , Pipelines
Commentary by Dr. Valentin Fuster
2018;():V003T04A037. doi:10.1115/IPC2018-78651.

Pipeline integrity has been threatened at the Dead Horse Creek pipeline crossing in southern Manitoba by a slow-moving slope failure with a potential for crest retrogression. The movement zone extends from the slope crest to the bottom of the creek, a vertical distance of about 25 m and is approximately 80 m long from toe to scarp and 100 m wide along the creek. The slope has degraded over time and is controlled by the combination of local geology, which consists of weak colluvium overlying high plastic clay shale, and creek bank erosion and channel degradation. Saturated soil conditions, a function of poor drainage and elevated seasonal precipitation, have exacerbated the problem over the years.

The slope movements have been monitored on a regular basis since 2008 and presented an increasing risk to the integrity of multiple pipelines located in two rights-of-way (ROWs) situated within and immediately adjacent to the failing soil mass. The site is surrounded by various infrastructure and recreational areas that are key to the community, and therefore is considered a high consequence area with respect to potential pipeline failures. To manage the risk and protect pipeline integrity, various stress relief and other mitigating measures have been implemented since 2013 [1], culminating in a major slope rehabilitation project undertaken in 2015, which comprised earthworks, drainage and watercourse improvements, and slope stabilization using stone columns.

While the use of stone columns to stabilize embankments is not a new technique, it is not commonly used in the pipeline industry and represents another option for geohazard stabilization in the right situations. This paper presents the slope stabilization techniques employed and discusses the challenges of working on an active moving slope confined by a watercourse and live pipeline assets. The positive benefits of the stabilization measures are illustrated through the use of 2D and 3D numerical modelling, and confirmed through an ongoing geohazard management program that includes site inspection and instrumentation monitoring which continues to show improvements in slope performance post construction.

Commentary by Dr. Valentin Fuster
2018;():V003T04A038. doi:10.1115/IPC2018-78695.

Understanding where, when, and how conditions are changing along the extent of an energy pipeline system, which can be vast, is a challenging task. The challenge can be even greater when natural disasters1 create a condition where access to affected pipelines, qualified personnel, and equipment is limited.

To address these challenges, pipeline operators are working directly with experts in satellite technology to develop innovative applications incorporating the use of satellite technology and analytical processes to improve natural disaster monitoring and response. Through recent experiences following Hurricane Harvey in the Gulf Coast region of the United States in August-September 2017 and the wildfires and mudslides in Southern California that occurred in December 2017 to January 2018, space-borne Synthetic Aperture Radar (SAR) satellite data was shown to be a useful tool for wide-area monitoring. Satellite-based SAR imagery has the unique advantage of penetrating through cloud cover and smoke and is capable of providing an early view of the extent of damage in both conditions.

Satellite data and continuous improvements to their derived analytical products have resulted in significant benefits for pipeline operators preparing for and responding to the effects of potentially damaging natural processes, including river scour, erosion, avulsion, mudslides, and other threats to pipeline integrity and public safety. SAR change detection algorithms and processes can provide effective results in identifying areas affected by natural disasters that are not readily available by other means. These methods also provide timely information for allocating and directing resources to the most critical locations in support of post-disaster assessment and analysis. SAR satellite data and Amplitude Change Detection (ACD) algorithms provided the basis for confirming where flooding near pipeline infrastructure was most substantial following Hurricane Harvey. In the case of the Southern Californian forest fires and mudslides in Ventura and Santa Barbara counties, recent investigations into ACD and Coherence Change Detection (CCD) algorithms showed promising results, providing a detailed view of damaged areas in near-real time.

This paper describes the process of collecting, analyzing, and applying satellite data for assessing the impacts of natural disasters on pipeline infrastructure, and the methods applied, consisting primarily of multiple change detection algorithms, that are used to process the large volume of satellite archive images to extract relevant changes. This paper also describes how these tools and products were practically applied to support decisions by pipeline operators to protect and ensure the integrity and safety of pipelines in the affected areas.

Commentary by Dr. Valentin Fuster
2018;():V003T04A039. doi:10.1115/IPC2018-78740.

Flood monitoring is one method currently being used by the pipeline industry to provide alerts when flooding is approaching, or has exceeded, levels that could create hydrotechnical conditions that threaten pipeline integrity. Flood monitoring does not provide protection from hydrotechnical hazards or reduce the probability of failure, but can lower risk by providing advanced warning, allowing operators to initiate actions that reduce the consequences of failure in the rare event that pipeline integrity is threatened by hydrotechnical forces. Pipeline pressure reduction, shut-in, purge, and spill response mobilization are all examples of actions commonly used to reduce failure consequence. However, these actions require time to execute, ranging from a number of hours to a number of days, depending on factors such as site location, valve spacing, and product type. The effectiveness of flood monitoring as a consequence reduction strategy is contingent on having sufficient time to implement the flood response action. In designing a flood monitoring program, it is necessary to ask: can flood monitoring provide sufficient advanced warning for an action plan to be fully executed before pipeline integrity is compromised?

The present study evaluated 35 high priority pipeline watercourse crossings, to estimate the flood return periods at which actions could be taken that correspond to warning times of 12, 24, 48, and 72 hours before the critical flood (i.e., a conservative estimate of the flow at which fatigue failure is considered possible) and to evaluate the feasibility of flood monitoring as a short-term risk management strategy prior to mitigation. The 35 crossings are currently scheduled for mitigation and rely on flood monitoring as an interim risk management tool.

The rate of increase in flood discharge during all previously recorded flood events at each real-time monitoring gauge was first obtained to estimate the rate of flow increase during the critical flood event. Of the 35 crossings, 33 had a maximum warning time of less than 48 hours. Using a 24-hour warning time, 10 of the 35 crossings have a warning flow of less than a 1 in 5-year flood. The results show that the ‘action initiation flood level’ for more than 90% of the most susceptible watercourse crossings may be too low to be practical; at crossings where more than 48 hours of response time is required, flood monitoring may not significantly reduce hazard consequence as the action response plan may not be fully executed prior to pipeline failure.

Pipeline failures are rare, and flood monitoring provides a useful monitoring approach for short-term management in many watercourses. However, these results demonstrate the importance of evaluating the required action response time relative to the available warning time for each watercourse crossing to confirm that flood monitoring will achieve the risk reduction expected by the operator. If flood monitoring is determined to be impractical because the action initiation flood is too low, it may provide justification for initiating other management actions (e.g., flood forecasting, purging prior to the flood season, or elevating such sites on the priority list for physical repairs).

Topics: Floods
Commentary by Dr. Valentin Fuster

Operations, Monitoring, and Maintenance: Operations and Maintenance

2018;():V003T04A040. doi:10.1115/IPC2018-78016.

For almost 30 years composite repair technologies have been used to reinforce high pressure gas and liquid pipeline transmission systems around the world. The backbone of this research has been full-scale testing, aimed at evaluating the reinforcement of anomalies including, corrosion, dents, vintage girth welds, and wrinkle bends. Also included have been the assessment of reinforced pipe geometries including welded branch connections, elbows, and tees. Organizations sponsoring these research efforts have included the Pipeline Research Council International, regulatory agencies, pipeline operators, and composite repair manufacturers. Many of these efforts have involved Joint Industry Programs; to date more than 15 different industry-sponsored programs and independent research efforts have been conducted involving more than 1,000 full-scale destructive tests.

The aim of this paper is to provide for the pipeline industry an updated perspective on research associated with composite repair technologies. Because of the continuous advance in both composite technology and research programs to evaluate their effectiveness, it is essential that updated information be provided to industry to minimize the likelihood for conducting research efforts that have already been addressed. To provide readers with useful information, the authors will include multiple case studies that include the reinforcement of dents, wrinkle bends, welded branch connections, and planar defects.

Commentary by Dr. Valentin Fuster
2018;():V003T04A041. doi:10.1115/IPC2018-78117.

MV (Medium Voltage) controller lineup electrical protection is crucial in protecting the equipment from large scale damage upon the occurrence of an electrical fault, reducing the time to restore power, thereby minimizing the impact to liquids pipelines operation. The paper discusses typical electrical failure modes that may occur in MV controller lineups, and demonstrates practical relaying engineering techniques that enable fast and effective fault clearing. Electrical faults in the MV controller lineup are often arcing type, commonly involve ground. Mitigating arc hazards in MV Class E2 controller lineups has traditionally been challenging without sacrificing the protection selectivity. As the paper demonstrates, a relaying scheme with the combined use of high-speed light-sensing and overcurrent detection will effectively mitigate the incident energy, while maintaining the protection selectivity for non-arcing overcurrent events.

For new MV controller lineups, in addition to the “high-speed light detection and fault interruption”, zone-selective interlocking (ZSI) can also be a practical solution in improving relay protection speed, thus reduce the chance of severe arc flash occurrences. ZSI is particularly effective for fault occurrences on the line side of the phase CTs, busways or main incoming circuits. The ZSI scheme can be implemented on both Class E2 and circuit breaker (VCB) type MV controller lineups, however, with slightly different trip logic due to the limited fault clearing capability of the contactor.

Although there are multiple contributing factors, the direct causes of electrical failures in MV controller lineup are commonly related to improper power cable installation and handling, potentially leading to premature insulation breakdown due mainly to the proximity effect and/or partial discharge. Inadequate cable separation and prolonged fault trip delay can increase the possibility of arcing fault occurrence. This can usually be mitigated through appropriate cable spacing, adequate conductor insulation, and optimized fault detection schemes. The paper provides overviews of the mechanisms of proximity effect and partial discharge propagation, and the modern relaying approaches for accurate fault type discrimination and facilitating fast fault interruption.

Two case studies are provided in the paper as an aid in understanding the electrical fault mechanism originated from cable insulation failure, demonstrating the incident energy reduction before and after the implementation of high-speed light detection and fault interruption solutions on an existing MV controller lineup.

Commentary by Dr. Valentin Fuster
2018;():V003T04A042. doi:10.1115/IPC2018-78121.

Pipeline pigging is one of the most widely used wax remediation techniques in field practice. However, it still depends heavily on “rule-of-thumb” due to the limited understanding of wax deposit properties and wax removal mechanisms. By far, laboratory studies on pipeline pigging generally suffer a gross defect in test materials, i.e., the big discrepancy between the experimental wax samples and real wax deposits. To this end, this paper aims to explore the wax removal in pigging with naturally deposited wax, using a self-designed experimental facility. Wax deposit mass and wax content, two decisive indexes affecting wax removal, were also investigated. The experimental apparatus consists of two parts: a flow loop equipped with a detachable test section to achieve real wax deposits and a wax removal apparatus to perform pigging operations. The test section can be conveniently detached from the flow loop and/or mounted onto the wax removal apparatus for a quick conversion between wax deposition and pigging operation. The results indicate that a higher bulk flow temperature decreases the wax deposit mass and increases the wax content of deposit. Additionally, the distributions of wax content and wax layer thickness suggest that gravity settling plays no role in wax deposition. Moreover, the wax resistive force profile of naturally deposited wax presents four distinct stages, i.e., the build-up phase, the pre-plug phase, the plug phase and the production phase. To the best of the authors’ knowledge, this is the first study on wax removal with real wax deposits. It paves the way for the application of previous artificial-wax-based researches to real wax deposit scenarios.

Commentary by Dr. Valentin Fuster
2018;():V003T04A043. doi:10.1115/IPC2018-78123.

In this paper a summary of the investigation performed to identify the root causes for the heavy sludge formation in a sour gas pipeline downstream of a gas process plant is provided. The investigation included reviews of historical and current gas and heavy hydrocarbon analyses, particle size analysis, field investigations, operational records, records of cleaning pig runs, and analysis of chemicals used in the upstream process plant and in the pipeline. The strategy undertaken by the operator to manage and mitigate the issue of heavy sludge formation based on the investigation results is also discussed. In the first phase of the investigation, the operational conditions which resulted in sludge formation were investigated but the detailed chemical analysis to determine the mechanism of sludge formation will be performed in the next phase of the investigation, and therefore is not included in this paper.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2018;():V003T04A044. doi:10.1115/IPC2018-78179.

High friction between a fluid and a pipe wall results in increased pumping requirements. This friction contributes to lower production rates and reduced system capacity. Thermal heating, fluid blending, and drag reducing agents (DRA) are commonly used methods for decreasing pressure drop in pipelines. Surface patterns inscribed onto internal pipe walls have also been shown to reduce fluid friction.

In this paper, the effects of different surface patterns on the shear between a fluid and a wall are studied. Surfaces with different dimple patterns are investigated. Micro-dimpled patterns on the surface are created using an inclined, flat end micro-milling tool. The surfaces with different dimpled patterns are characterized and tested through morphological, contact angle, and viscosity measurement studies. The effects of the surface patterns are also studied through simulation. A Power Law relationship and apparent fluid viscosity is determined for the low Reynolds numbers investigated. The deepest dimpled surfaces investigated (0.2 mm dimple depth) result in a drag reduction of approximately 20% for silicone oil. Further research and application of the results to transmission pipeline systems are discussed.

Commentary by Dr. Valentin Fuster
2018;():V003T04A045. doi:10.1115/IPC2018-78216.

Many different inspections are conducted on gas transmission and gas distribution pipelines — valve inspections, cathodic protection system inspections, in-line inspection, odorant monitoring, etc. — demanding significant resources and operational expenditures from pipeline operators. Risk-based optimization relating to these kinds of operational activities has been applied in analogous industries. The result has been measurable savings consistently ranging at a level between 20–40%. Significantly, this explicitly means that 20–40% of many operational activities have been proven not to bring a benefit. In the pipeline industry, however, there has not been a basis to determine which activities bring no value in terms of risk reduction. In this paper, a detailed example is provided for risk-based optimization of valve inspections and the savings are found to be within these expectations. These savings can be taken in either a risk reduction benefit or completely in cost savings. Through development of a valve failure risk model (which independently considers loss of function and loss of containment failures) and an inspection cost model, a set of the optimum risk-cost combinations is developed and can be presented as an optimized inspection curve. Using the curve to establish inspection frequencies is demonstrated, including the impact on operating expenditures. As demonstrated via the presented case studies, the general framework is suitable for optimization of any gas pipeline inspection or maintenance activity.

Commentary by Dr. Valentin Fuster
2018;():V003T04A046. doi:10.1115/IPC2018-78307.

One of the challenges of transporting Natural Gas Liquids (NGL) is to ensure that the flow should be delivered with standards of safety, reliability, and efficiency while conducting repairs on the pipeline. This paper discusses the difficulties that had to be overcome to repair a damaged NGL pipeline by third parties performed in the Andean Mountains in Ayacucho, Perú, on NGL pipeline operated by Compañía Operadora de Gas del Amazonas (COGA). This pipeline and a parallel one also operated by (COGA) are the main source of supply of NGL and Natural Gas (NG) to the city of Lima, capital of Perú.

To repair the Third-Party damage, an emergency committee COLE by its acronym in Spanish (Local Emergency Operative Committee) was formed with the purpose to coordinate the actions for the execution of the repair and meet the Quality, Safety, Social and Environment standards. The committee had an important tool, the Operational Contingency Plan, which provided guidelines for dealing with an emergency. The job required isolating a section of 14-inch NGL transportation pipeline and a bypass to keep the pipeline operational. The work had a tight schedule that needed to be followed to reduce the environmental, safety and service risks. The situation presented several challenges including the use of double barriers to safeguard personnel and facility equipment during the pipeline repair. This double block methodology had to be applied to meet environmental and safety concerns. The damage was located at 4,495 meters above sea level (masl). The strike caused an NGL leak resulting in the installation of an NGL containment and storage system. This location lacked the logistical facilities for the attention of a pipe repair operation, adverse conditions of cold climate, desolate land and other conditions that had to be overcome. This paper discusses how social, safety, environment and logistical challenges were overcome to repair a damaged caused by third parties in an NGL pipeline, which resulted in timely repair completion and uninterrupted flow of NGL.

Commentary by Dr. Valentin Fuster
2018;():V003T04A047. doi:10.1115/IPC2018-78360.

Because of the stochastic nature of line pipe characteristics a small percentage of the pipe joints in a given pipeline may possess actual yield strengths below the specified minimum yield strength. During a hydrostatic test these segments may experience some plastic deformation as the hoop stress approaches the yield point. It is well known that the effect of room temperature creep near the yield becomes notable and therefore can affect pressure trending during the hold period (leak test). In this work a numerical model is developed for the analysis of creep deformation. A conceptual study is carried out to demonstrate potential effects of creep on hydrostatic test pressure trending during a leak test. This analysis can help operators understand the potential effects of creep and distinguish it from other factors such as temperature changes or leakage and can help identify, or rule out, the occurrence of pipe yielding during hydrostatic tests.

Commentary by Dr. Valentin Fuster
2018;():V003T04A048. doi:10.1115/IPC2018-78409.

The modal response characterization of structures is a proven and reliable technique used to monitor system behavior and change, providing information for condition assessment and damage identification. In traditional modal response characterization procedures, an external mass excitation source is used to excite the system, and this is modeled as an impact function. This provides system forcing across a broad range of frequencies. In this investigation, an in-situ method of system excitation is explored. The modal characteristics of externally-supported pipe structures are investigated by varying the flow Reynolds number (Red). Given the increase in flow turbulence with Reynolds number, hydrodynamic pressure fluctuations on the pipe wall provide a varying excitation source. This removes the requirement for an external excitation source.

A comparative analysis of data sets collected for both Acrylic and ABS pipe material show similar pressure spectra, while vibration spectra change significantly. Pressure spectra reveal a character whereby the spectral energy increases with increasing Reynolds number. A comparison of in-situ results to those obtained using traditional impact response tests show that vibration spectra collected through Reynolds number variation successfully capture the modal characteristics of the pipe-structure.

Commentary by Dr. Valentin Fuster
2018;():V003T04A049. doi:10.1115/IPC2018-78633.

This paper presents a tool for surface loading stress analysis that was developed in-house by TransCanada (TCPL). This tool utilizes fundamentals of the surface loading assessment method developed by Kiefner & Associates Inc. (KAI) for Canadian Energy Pipeline Association (CEPA), but incorporated many advanced functionalities to improve the accuracy, efficiency and transparency of the analysis. The new functions of the tool include the batch analysis, multiple angle analysis, generic/site-specific loading analysis, graphical display of stress distributions for refined assessment, user-defined impact factor and automated reporting for documentation of surface loading calculations. This tool also incorporated the improved numerical algorithm for longitudinal global bending stress considering the actual live load pressure distribution over a certain length of pipeline.

The accuracy of the developed tool was validated by comparing it to the KAI tool. The improved algorithm for longitudinal global bending stress calculation reduces the conservatism of the longitudinal global bending stress compared to the original simplified method but does not sacrifice safety, which has been demonstrated by comparison with the experimental results. The new functionalities improved the business efficiency and maintains safety and regulatory compliance.

Topics: Transparency
Commentary by Dr. Valentin Fuster
2018;():V003T04A050. doi:10.1115/IPC2018-78647.

There are many options available to pipeline operators when addressing anomalies or integrity threats. Repairing integrity threats requires an understanding of both the anomaly to be repaired, and the repair system itself. This can be challenging as pipeline repair systems come in a wide variety of materials, application techniques, and designs. Operators have similar challenges when performing maintenance activities on operating pipelines. Maintenance activities can take many different forms and often involve welding or other high temperature processes on the outside pipe surface. These processes can result in elevated temperatures on the inside surface of the pipeline and must be seriously considered before undertaking to ensure the safety of personnel performing the tasks and to protect the integrity of the pipeline. This study aimed to provide a greater understanding of pipeline reinforcement systems and maintenance activities as they relate specifically to thin-walled pipelines.

To evaluate systems reinforcing thin-wall pipes, five different repair systems were investigated using 12.75-inch × 0.219-inch, Gr. X65 pipe that had been removed from service. The systems included a Type B steel sleeve, an epoxy-filled, interference fit, Type A steel sleeve, a hybrid steel sleeve-fiberglass based composite repair system, epoxy-filled oversized Type A steel sleeves, and a rigid coil, pre-cured, fiberglass-based composite repair system. Each system was used to reinforce a simulated 50% wall loss anomaly and was installed with the pipe samples maintained at an internal pressure equal to 33% of the pipe’s specified minimum yield strength (SMYS). The samples underwent pressure cycling and hydrostatic testing while strains in the simulated wall loss region were continually monitored. As a final step, the samples were burst tested. Monitoring of strain gages installed in the simulated wall loss anomaly allowed for comparisons to be made between the tested repair systems. It was observed that the recorded strain magnitudes and strain ranges were higher in some samples than others during testing. This allowed the systems to be ranked according to the recorded strains. Although differences were observed in the recorded strains, burst testing showed that all reinforcement systems were able to force failure to the base pipe outside of the simulated wall loss region.

Maintenance procedures were also evaluated to identify those that could produce unacceptable temperatures on the inside surface of the thin-wall pipe. The maintenance procedures included installation of Type A steel sleeves (non-pressure containing), Type B steel sleeves (pressure containing), cad welds, and pin brazing cathodic protection (CP) test leads. Temperatures were monitored on the internal pipe surface using thermocouples and an infrared (IR) camera while the maintenance procedures were being performed. An internal surface temperature of 500 °F (260 °C) was set as the threshold for suitability. Monitoring of the Type B steel sleeve installation showed temperatures on the inside surface of the pipe that exceeded 1,200 °F (648 °C) when performing the circumferential weld at each end of the steel sleeve. A maximum temperature of 280 °F (137 °C) was recorded when making the longitudinal welds that included a backing strip. For the application being considered, this indicated that Type A steel sleeves (longitudinal welds only) could be installed within the required temperature limits. A maximum internal temperature of 936 °F (502 °C) was recorded during cad-welding. Pin-brazing was slightly lower, but also exceeded the 500 °F threshold. This testing confirmed that the installation of Type B steel sleeves, cad welding, or pin brazing should receive scrutiny before being performed on operating thin-wall pipelines.

Commentary by Dr. Valentin Fuster
2018;():V003T04A051. doi:10.1115/IPC2018-78660.

This paper develops an optimization concept based on J-curve analysis in pipeline system design as a tool in the quantitative evaluation of pipeline operation efficiency and maintenance decisions. The method includes the creation of the J-curve (total Capex and Opex per unit volume versus the pipeline flow rate) of the as build system without maintenance, the improvement or changing of the J-curve after maintenance goal is achieved, and the return of expenditure curve of the maintenance at different flow rate based on the current commodity market price. The J-curve improvement and the return of expenditure curve will show the efficiency of the maintenance activities as basis for their priority and necessity. The return curve also help to set up the range of optimized flow rates that the pipeline should be operated at given the market price status. The creation of J-curve is based on the pipeline performance hydraulics model bench marked with pipeline measurement data.

Commentary by Dr. Valentin Fuster
2018;():V003T04A052. doi:10.1115/IPC2018-78701.

This paper presents an experimental study on drag reduction induced by PEO (Polyethylene oxide) in a fully turbulent pipe flow. The objective of this work is to develop a correlation to predict drag reduction using the relaxation time of the polymer additives under dilute solution conditions, i.e., the polymer concentration is less than the overlap concertation. This paper discusses the meaning of relaxation time of polymers, and why the Weissenberg number, a dimensionless number that is related to the relaxation time and shear rate, is independent on the concentration in the dilute solution. Experimental data of drag reduction in a pipe flow are obtained from measurements using a flow loop. A correlation to predict drag reduction with the Weissenberg number and polymer concentration is established and a good agreement is shown between the predicted values and experimental data. The new correlation using the Weissenberg number and polymer concentration is shown to cost less to develop than one using the Reynolds number, in which larger pipes or higher flow rates are required.

Commentary by Dr. Valentin Fuster

Materials and Joining: Crack Propagation

2018;():V003T05A001. doi:10.1115/IPC2018-78043.

The third edition of the EPRG recommendations for crack arrest toughness for line pipe steels is presented. The third edition extends the applicability of the recommendations to pipelines transporting lean natural gas at pressures up to 100 barg (1450 psig), in diameters up to 1422.4 mm (56 inch), in grades up to Grade L555 (API 5L X80), and design factors up to 0.8.

A quantitative definition of a lean gas is included in the third edition.

The recommendations are intended to be applied to new pipelines. The recommendations are not intended to be applied retrospectively to existing pipelines.

Commentary by Dr. Valentin Fuster
2018;():V003T05A002. doi:10.1115/IPC2018-78097.

Axial ductile fracture propagation and arrest in high energy pipelines has been studied since the early 1970’s with the development of the empirical Battelle Two-Curve (BTC) model. Numerous empirical corrections on the backfill, gas decompression models, and fracture toughness have been proposed over the past decades. While this approach has worked in most cases, the dynamic interaction between the decompression of the fluid in the vicinity of the crack tip and the behaviour of the pipe material as it opens to form flaps behind the crack has been very difficult to solve from a more fundamental approach. The effects of the pressure distribution on the flap inner surface making up the crack-driving force which drives the crack propagation speed has been suggested in the past, but due to intensive computational effort required, it was never realized. The present paper attempts to tackle this problem by employing an iterative solution procedure where the gas pressure field in the vicinity of the crack tip is accurately solved for by computational fluid dynamics (CFD) for a given flap geometry determined from a dynamic FEA model to render a new flap geometry. In this model a cohesive-zone element at the crack tip is employed as a representation of the material toughness parameter. The final outcome is the determination of the cohesive energy in the FEA (as a representation of the material toughness parameter) to match the measured fracture propagation speed for the specific case. A case study was taken from full-scale rupture test data from one of the pipe joints from the Japanese Gas Association (JGA) unbackfilled pipe burst test data conducted in 2004 on the 762 mm O.D., 17.5 mm wall thickness, Gr. 555 MPa (API 5L X80) pipe.

Commentary by Dr. Valentin Fuster
2018;():V003T05A003. doi:10.1115/IPC2018-78109.

In this paper, the effect of inertia on the steady-state velocity of a propagating crack in a modern high toughness pipeline steel was investigated. The line pipe steel examined in this work was an American Petroleum Institute (API) Standard X70 steel. A tensile plate model, simplified from the geometry of a pipe, was studied using the finite element code ABAQUS 6.14-2. The cohesive zone model (CZM) was used to simulate crack propagation. The CZM parameters were calibrated based on matching the crack tip opening angle (CTOA) measured from a drop-weight tear test (DWTT) finite element model to the experimental CTOA of the material. The CZM parameters were then applied to the tensile plate model. The effect of inertia on the steady-state crack velocity was systematically assessed by altering the density of the material used with the plate model. To isolate the influence of inertia, the effect of strain rate on the fracture process and material plasticity was neglected. The results of this study demonstrate that the steady-state crack velocity was affected by the density of the material. The steady-state crack velocity was reduced with increasing mass density, as demonstrated by the effect of backfill. Furthermore, it was shown that the CTOA extracted from the CZ model was not affected by the density of the model.

Commentary by Dr. Valentin Fuster
2018;():V003T05A004. doi:10.1115/IPC2018-78278.

In ductile materials the fracture toughness is usually characterised by a tearing resistance curve, or R-curve, plotting the fracture toughness in terms of J or CTOD against crack extension. Recent research has evaluated the methods to determine CTOD in engineering alloys with a wide range of yield to tensile (Y/T) ratios for single point CTOD. This work develops the investigation into R-curves, and reviews the assumptions about SENB specimens deforming under rigid rotation, the evaluation of CTOD from J for R-curves, and the nature of tearing initiation in low Y/T ratio stainless steel, from comparisons against a series of silicone replicas cast from the SENB specimen notch during fracture toughness tests.

For CTOD R-curves, the methods based on CTOD from J in ISO 12135 and ASTM E1820 gave lower and less accurate R-curves than the rigid rotation methods in BS 7448-4 and WES 1108. However, the accuracy of the BS 7448-4 formula varied for the different strain hardening materials, and overestimated the R-curves in the low tensile ratio stainless steel.

Investigations into the effect of the assumption about rigid rotation in different strain hardening materials led to a rotational factor function of tensile ratio, rp sh, to be developed from numerical modelling. When this function was substituted into standard equations in place of the fixed value of rp an improvement in the accuracy of BS 7448-4 R-curves compared to replica measurements was seen for the range of strain hardening investigated, but it did not significantly improve the accuracy of the WES 1108 formula, which accounts for strain hardening in other parameters.

A combination of the elastic CTOD part of the WES 1108 formula, with the plastic CTOD incorporating the modified rotational factor, was concluded to offer the optimum method to determine CTOD R-curves for a range of strain hardening materials.

Topics: Work hardening
Commentary by Dr. Valentin Fuster
2018;():V003T05A005. doi:10.1115/IPC2018-78366.

Various numerical approaches have been developed in the last years aimed to simulate the ductile fracture propagation in pipelines transporting CO2 or natural gas. However, a reliable quantification of the influence of material plasticity on the fracture resistance is still missing. Therefore, more accurate description of the material plasticity on the ductile fracture propagation is required based on a suitable numerical methodology.

In this study, different plasticity and fracture models are compared regarding the ductile fracture propagation in X100 pipeline steel with the objective to quantify the influence of plasticity parameters on the fracture resistance. The plastic behavior of the investigated material is considered by the quadratic yield surface in conjunction with a non-associated quadratic plastic flow potential. The strain hardening can be appropriately described by the mixed Swift-Voce law. The simulations of ductile fracture are conducted by an uncoupled, modified Mohr-Coulomb (MMC) and the micromechanically based Gurson-Tvergaard-Needleman (GTN) models. In contract to the original GTN model, the MMC model is capable of describing ductile failure over wide range of stress states. Thus, ductile fracture resistance can be estimated for various load and fracture scenarios. Both models are used for the simulation of fracture propagation in DWTT and 3D pressurized pipe sections. The results from the present work can serve as a basis for establishing the correlation between plasticity parameters and ductile fracture propagation.

Commentary by Dr. Valentin Fuster
2018;():V003T05A006. doi:10.1115/IPC2018-78447.

A full-scale gas burst test was conducted to confirm the behavior of unstable ductile crack propagation and arrest and to confirm the required toughness value to prevent unstable ductile fracture under an ultrahigh pressure of 18 MPa. A full-scale test was conducted at the Spadeadam test site in the UK for unburied pipes. The test pipes used in this test were of API 5L Grade L450 with outer diameter of 610 mm and thickness of 17.5 mm. The toughness of the test pipes increased away from the center, where an explosive charge was placed across the top of the girth weld for crack initiation. The gas used in the test consisted of ∼89% methane and other heavy hydrocarbon gas components, and the test temperature was 0 °C. A gas circulation loop was constructed to ensure that a homogeneous gas mixture and temperature were achieved throughout the test rig.

In addition to dynamically measuring the ductile crack velocity and decompression behavior of the rich gas, as has often been done in previous burst tests, the circumferential distribution of the decompression behavior was measured using circumferentially placed pressure transducers. Furthermore, the fracture strain near the propagating crack was measured.

The initiated unstable ductile crack was arrested in the third pipe. From the material properties of the test pipes in which the unstable ductile crack was arrested, the required Charpy absorbed energy and DWTT absorbed energy to prevent unstable ductile fracture in unburied pipes were obtained. In addition, the above data can be useful for validating numerical models that evaluate the propagation/arrest of unstable ductile fracture.

The required Charpy and DWTT absorbed energy values obtained in this test were compared with those predicted by the Battelle Two-Curve Method (BTCM). As noted in previous studies, it was confirmed that the BTCM underestimates the required Charpy absorbed energy and requires a certain correction factor for precise evaluation, whereas the DWTT absorbed energy predicted by BTCM was consistent with the experimental result.

Topics: Pressure , Pipelines
Commentary by Dr. Valentin Fuster
2018;():V003T05A007. doi:10.1115/IPC2018-78510.

Dynamic measurement of drop-weight tear test (DWTT) and pipe burst test for 356 mm outer diameter and 9.5 mm wall thickness steel pipe were conducted using high-speed camera. Crack velocity in the DWTT were 10 m/s during the steady state. Crack Tip Opening Angle (CTOA) values measured in the DWTT showed the constant value of about 20.1° during steady state propagation. On the other hand, crack velocity in the burst test showed monotonically decreasing during crack propagation from 200 m/s but it was found that CTOA value kept constant value of about 13.2° until crack arrest irrespective of the crack velocity. These results showed the validation of the CTOA criterion for the high-pressure gas pipelines. The results also showed that CTOA in a burst test is generally different from that in a test using small-scale specimen. Future developments of the experimental procedure using a small-scale specimen to provide CTOA value corresponding with that in a burst test would be effective.

Commentary by Dr. Valentin Fuster
2018;():V003T05A008. doi:10.1115/IPC2018-78517.

Transport of anthropogenic carbon dioxide in pipelines from capture site to storage site forms an important link in the overall Carbon Capture, Transport and Storage (CCTS) scheme. The thermodynamic properties of CO2 are different from those of other gases such as natural gas that are transported in pipelines. Recent full-scale burst tests from the projects SARCO2 and COOLTRANS indicated significant variations in correction factors necessary to predict the arrest of a running ductile fracture. In addition, CO2 can be a potential hazard to human and animal life and the environment. While consequence distances of natural gas pipelines are well established and documented in standards, this is not the case with CO2.

The research focused CO2SAFE-ARREST joint industry project (JIP) aims to (1) investigate the fracture propagation and arrest characteristics of anthropogenic CO2 carrying high strength steel pipelines, and (2) to investigate the dispersion of CO2 following its release into the atmosphere. The participants are DNV GL (Norway) and Energy Pipelines CRC (Australia). The project is funded by the Norwegian CLIMIT and the Commonwealth Government of Australia. The joint investigation commenced in 2016 and will continue to 2019.

The experimental part of the project involves two full-scale fracture propagation tests using X65, 610mm (24“) pipe and two 6″ shock tube tests, with all tests filled with a dense phase CO2/N2 mixture. The full-scale tests were made up of 8 pipe lengths each, with nominal wall thicknesses of 13.5 mm and 14.5mm. The dispersion of the carbon dioxide from the full-scale test sections was measured through an array of sensors downwind of the test location. The tests were conducted in 2017/2018 at Spadeadam, UK.

Following a short review of the background and outcomes of previous CO2 full-scale burst tests, this paper provides insight on the aims of the overall experimental program along with summary results from the first full-scale fracture propagation test, carried out in September 2017. Two companion papers provide further details on the first test. The first companion paper [IPC2018-78525] discusses the selection of pipe material properties for the test and the detailed fracture propagation test results. The second companion paper [IPC2018-78530] provides information on the dispersion of the CO2 from the first full-scale test, along with numerical modelling of the dispersion.

Commentary by Dr. Valentin Fuster
2018;():V003T05A009. doi:10.1115/IPC2018-78525.

The CO2SAFE-ARREST joint industry project (JIP) aims to (1) investigate the fracture propagation and arrest characteristics of steel pipelines carrying anthropogenic CO2, and (2) to investigate the dispersion of CO2 following its release into the atmosphere. The project is supported by two full-scale burst tests, each based on a layout of eight X65 grade 24″ line pipes filled with a dense-phase CO2-N2 mixture. The tests were conducted over the 2017–2018 period at the DNV GL testing site at Spadeadam, UK. An overview of both the CO2SAFE-ARREST JIP and the first full-scale burst test is provided in a companion paper (IPC2018-78517). The dispersion aspect is covered in another companion paper (IPC2018-78530).

This paper presents the material properties, the design layout and the results of the first full-scale burst test. Material characterisation of the pipes available to the project and the motivation leading to the design of the layout are first presented. Six pipes had a nominal wall thickness of 13.5 mm and the remaining two pipes had a nominal wall thickness of 14.5 mm. Laboratory testing was conducted on the material at the end of each pipe section. The testing consisted of Charpy impact and Drop Weight Tear tests, capturing the upper shelf fracture energy, load-displacement curves and an assessment of the fracture surfaces. Charpy and Drop Weight Tear test energies as well as strength data are provided.

The layout reflects the research focus of the project with both conventional and less conventional pipe arrangements. The test was primarily designed around 13.5 mm nominal wall thickness pipes with a 1m depth backfill and laid East-West. The design was telescopic and introduced an asymmetry with respect to the mid-point by arranging pipe sections with increasing Charpy toughness on one side and increasing yield strength on the opposite side.

The fracture was initiated at half-length, across the girth weld between the ‘west’ and ‘east’ initiation pipes. A running ductile fracture ensued, followed by an arrest in the third pipe on either side of the test section. Experimental data relevant to fracture velocity, decompression wave speed of the CO2-N2 mixture and pressure at the crack tip are presented.

The discussion is driven from the perspective of traditional running ductile fracture control technology applied to dense-phase CO2 carrying pipelines. Emphasis is put on the analysis of the fracture velocity and transient pressure data relative to the properties of the material and CO2 mixture. The limitations of the Battelle Two-Curve Method (BTCM) traditionally used in the analysis of running ductile fracture are discussed.

The design of this test was different from that used in the three full-scale burst tests conducted as part of the COOLTRANS project. The conclusions drawn here support those from the COOLTRANS project and apply to larger D/t ratios. The first CO2SAFE-ARREST test provides additional evidence that the original Battelle Two-Curve Model is not applicable to dense-phase CO2 carrying pipelines. A shift in prediction tool technology is called for.

Commentary by Dr. Valentin Fuster
2018;():V003T05A010. doi:10.1115/IPC2018-78579.

The drop-weight tear test (DWTT) has been widely used to evaluate the resistance of linepipe steels against brittle fracture propagation. However, in the recent years there is an ambiguity in its evaluation if inverse fracture appears on the specimen fracture surfaces. Although cause of the inverse fracture is not fully understood, compressive pre-straining near the impact hammer and existing tiny split have been discussed as a possible cause.

In this paper, machined notch in brittle weld DWTT for X65 was performed and compared with various notch types of DWTTs such as conventional DWTT specimen with a pressed notch (PN), a chevron notch (CN) and a static pre-cracked (SPC). The fracture appearances were compared with different strength X65 - X80 grades linepipes and with different initial notch types. The frequency of the inverse fracture appeared in these DWTTs were different in each material and each specimen types, but there were no cases where the inverse fracture did not occurs.

The purpose of DWTT is to evaluate the brittle crack arrestability of the material in a pressurized linepipe. A large scale brittle crack arrest test, so called West Jeferson test is generally used to reproduce crack propagation and arrest behavior in an actual pipeline material. A middle scale test so called Crack Arrest Temperature (CAT) test was also proposed to check the shear area fraction measured in DWTT with API rating with that the local shear lip thickness fraction in those tests. CAT test can well reproduce crack propagation and arrest behavior under the condition of brittle crack initiation from the initial notch.

Commentary by Dr. Valentin Fuster
2018;():V003T05A011. doi:10.1115/IPC2018-78631.

In this study, we present results from a numerical model of a full-scale fracture propagation test where the pipe sections are filled with impure, dense liquid-phase carbon dioxide. All the pipe sections had a 24″ outer diameter and a diameter/thickness ratio of ∼32. A near symmetric telescopic set-up with increasing toughness in the West and East directions was applied.

Due to the near symmetric conditions in both set-up and results, only the East direction is modelled in the numerical study. The numerical model is built in the framework of the commercial finite element (FE) software LS-DYNA. The fluid dynamics is solved using an in-house computational fluid dynamics (CFD) solver which is coupled with the FE solver through a user-defined loading subroutine. As part of the coupling scheme, the FE model sends the crack opening profile to the CFD solver which returns the pressure from the fluid. The pipeline is discretized by shell elements, while the backfill is represented by the smoothed-particle hydrodynamics (SPH) method. The steel pipe is described by the J2 constitutive model and an energy-based fracture criterion, while the Mohr-Coulomb material model is applied for the backfill material. The CFD solver applies a one-dimensional homogeneous equilibrium model where the thermodynamic properties of the CO2 are represented by the Peng-Robinson equation-of-state (EOS).

The results from the simulations in terms of crack velocity and pressure agree well with the experimental data for the low and medium toughness pipe sections, while a conservative prediction is given for the high-toughness section. Further work for strengthening the reliability of the model to predict the arrest vs. no-arrest boundary of a running ductile fracture is addressed.

Commentary by Dr. Valentin Fuster
2018;():V003T05A012. doi:10.1115/IPC2018-78686.

For a safe operation of gas pipelines, the prevention of propagating brittle facture is one of the most important requirements. To evaluate the transition temperature of a propagating fracture, the Drop Weight Tear (DWT) Test was developed in the 60s. Fracture surfaces of DWT specimens have been shown to correspond well to the fracture surface of a pipe exposed to a propagating fracture at a certain temperature. Historically, there have always been observations of the fracture initiating in a ductile manner in the DWT test. Nevertheless, the most widely used test standard rules out such behavior, known as inverse or abnormal fracture. As an option to prevent ductile initiation, an alternative notch is proposed. While this might have served in the earlier days, high toughness steels of today are known to provide a high resistance against crack initiation and are therefore prone to inverse fracture, even when making use of the suggested alternative notch. Other, non-standard notch types have been investigated and discussed in literature, amongst these the static pre-crack and brittle weld notch.

Observations of the DWT test, especially comparing material showing non-inverse and inverse behaviour, show delayed crack initiation resulting in large deflection when the specimens are inverse. This high degree of pre-deformation of the material will have an adverse influence on the material performance by the time the crack propagates into it. This implies that the appearance of inverse fracture is a test effect in the laboratory test, and not an inherent material property, leading to the question if such DWT test results still correspond to the behavior of pipes. If the correlation is shown to be valid, the brittle initiation requirement as such becomes questionable.

This study summarises investigations of different notch types in DWT tests. West Jefferson tests that have been conducted to verify the correlation to shear area fraction in DWT tests. The investigation revealed that ductile initiation could not be reliably suppressed. While neither Chevron nor static pre-crack specimen lead to any reduction of the occurrence of inverse fracture, test series of brittle weld specimens did have a higher number of valid specimens. Interestingly, the results of valid, non-inverse specimens and invalid, inverse specimens showed no shift in transitional behavior. Correspondingly, both valid and invalid specimens showed a good representation of the pipe behaviour in the upper transition region.

Commentary by Dr. Valentin Fuster

Materials and Joining: Fittings and Testing Methods

2018;():V003T05A013. doi:10.1115/IPC2018-78100.

Microstructural engineering to obtain 100% shear area in DWTT at low temperature requires target parameters to suppress brittle fracture. In-depth characterization of benchmarked steels has confirmed that %age shear area is decreased by high number density of ultra-fine precipitates (<10nm) that contribute to precipitation strengthening, high intensity of rotated cube texture and coarse brittle constituents like M/A or carbides. The control of these parameters by nano-scale precipitate engineering of TiN-NbC was covered in a previous presentation in IPC 2016 [1]. The present paper focuses on crystallographic variants selection that controls the density and dispersion of high angle boundaries, which arrest microcracks to suppress brittle fracture, thereby increasing %age shear area in DWTT at low temperature.

Studies on crystallographic variants selection in single undeformed austenite grain have clarified crystallographic variants configuration which gives rise to high angle boundaries is influenced by hardenability parameters, i.e., alloying, cooling rate and austenite grain size. The profound effect of carbon and solute niobium on density and dispersion of high angle boundaries in CGHAZ is demonstrated by analyzing EBSD data to reconstruct the shear transformation of undeformed austenite using K-S relationship. Moreover, pancaking of austenite influences crystallographic variants through Sv factor and dislocation density. Experimental results on nano-scale TiN-NbC composite precipitate engineered steel confirm that adequate solute niobium (>0.03wt%) is retained in the matrix, which is aided by the suppression of delayed strain induced precipitation of ultra-fine precipitates of NbC. The hardenability from solute niobium is found to be adequate to give high density of high angle boundaries to give about 95% shear area in DWTT at −40°C in 32 mm gage K-60 plate and 100% shear area in 16.3 mm X-90 strip. Both steels were processed by nano-scale precipitate engineering of TiN-NbC composite to control size and uniformity of distribution of austenite grains before pancaking.

Commentary by Dr. Valentin Fuster
2018;():V003T05A014. doi:10.1115/IPC2018-78178.

Carbon steel piping can be exposed to environments that contain various chemical and organic elements that induce corrosion and cracking events. This can lead to the loss of fluid into surrounding sensitive and remote environments. To minimize this inherent risk, various coating technologies have been utilized over the years in industry. These coatings typically suffer from complex application methods, high application cost, and vulnerabilities to environmental effects such as mechanical damage and cathodic disbondment. To overcome these challenges, a novel epoxy based composite coating that utilizes the properties of various nano-particulates such as graphene nanoplatelets (GnP), multi-walled carbon nanotubes (MWCNTs), chitosan, and hBN (Hexagonal boron nitride) is developed. These nanoparticles create a nano-scale “brick and mortar” type effect that is analogous to various natural structures such as the abalone shell (nacre). These nano-structures also enhance coating performance by increasing mechanical strength and anti-bacterial properties while simultaneously decreasing gas permeability. This performance enhancement serves to reduce overall corrosion-induced disbondment area. The dispersion of nanoparticles is verified using various microscopy methods such as scanning election microscopy and an optical 3D profilometer. To confirm the role of nanoparticles in the epoxy composite, the samples undergo rigorous testing to determine both mechanical properties as well as the feasibility of coating application, in particular, for use on girth welds. Using a dynamic mechanical analysis (DMA), the material strength of each combination of nanocomposites is tested and used to determine the glass transition temperature. The testing also includes abrasion, and both long-term mechanical and thermal behaviors of the coating. To test the feasibility of the coating, cathodic protection tests in an accelerated corrosive environment, and gas permeability tests are carried out. The results show that the composite coating made from these nanomaterials had a decrease in cathodic disbondment area and gas permeability and an increase the glass transition temperature and scratch resistance. Therefore, the nanocomposite coatings are found to be a significant improvement over standard epoxy-based coating.

Commentary by Dr. Valentin Fuster
2018;():V003T05A015. doi:10.1115/IPC2018-78243.

An intensive effort was undertaken to understand the fracture behavior in a recent TCPL pipe burst test. The 48-inch diameter X80 pipe was buried in soil at the Spadeadam Test Site, but since it was desired to have the gas and pipe cooled to the minimum service conditions of −5°C, a 50-mm thick polyurethane foam (PUF) insulation was sprayed on the entire pipe test section. This was a reasonable precaution since freezing of a high water content soil around a large-diameter pipe burst test can require significant cooling capacity or a much longer duration to get to the burst test conditions. In this burst test, the crack propagated much farther than anticipated by traditional predictive approaches such as using Charpy energy to predict the minimum ductile fracture arrest toughness, assuming that soil backfill conditions existed.

To explore this burst test behavior, two aspects were examined. The first was an assessment of the properties of the PUF insulation relative to the soil properties, and the second was the toughness evaluated by instrumented DWTT testing.

The 50-mm thickness of the PUF insulation corresponded to about 8.3% of the pipe radius. In past loose-fitting steel sleeve crack arrestor burst tests, if the radial clearance was greater than 5.5% of the pipe, then a ductile fracture propagated under the arrestor regardless of its length with no change in speed. Hence if the PUF could be easily compressed, then the pipe in this burst test would behave as if it was in a non-backfilled condition. Non-backfilled pipe requires much higher toughness to arrest a ductile fracture. So perhaps the pipe in this burst test condition acted somewhere between non-backfilled and backfilled conditions — an aspect that might need a much more comprehensive computational model to better assess.

Additionally to assess how material toughness played a role in this burst test, detailed instrumented toughness testing was conducted on material taken from several of the pipe lengths in the burst test. The evaluations of the Charpy energy to the DWTT energy suggested that one of the pipe materials may have behaved more like an X100 steel than an X80 steel. Correction factors on the predicted arrest toughness are well known to be needed for the Battelle Two Curve method (BTCM) when applied to X80 and X100 pipes. However, even with these corrections on the Charpy energy, arrest was predicted with soil backfill in several cases where in the actual test, the crack propagated through the pipes. Hence toughness corrections by themselves did not explain the test results.

Additional calculations were then done assuming a non-backfilled condition (as suggested from the PUF property evaluation) along with the appropriate grade effect correction from the DWTT testing, and propagation was properly predicted in each case consistently with the burst test. So the fracture behavior in this burst test was somewhere between those of backfilled and non-backfilled pipe.

As a result of this investigation it appears that the PUF insulation played an important role in crack arrest behavior, and because of its presence may have required much higher toughness than was actually needed for the actual service conditions of pipe buried in actual soil backfill.

Topics: Insulation
Commentary by Dr. Valentin Fuster
2018;():V003T05A016. doi:10.1115/IPC2018-78299.

Heat treated pipeline fittings (principally elbows, tees, and reducers) require careful process control. For example, furnace temperature, placement of the fittings in the furnace, transfer time to quenching tank, adequacy of quench or tempering time can all impact the fittings’ mechanical properties if not done properly.

In recent years, the National Energy Board (NEB) became aware of instances of quenched and tempered (Q&T) pipe and fittings having mechanical properties that did not meet Canadian Standards Association (CSA) or similar standards, being installed on pipeline systems under NEB and other regulatory bodies’ jurisdiction. In 2013, a pipeline rupture occurred on an NEB-regulated pipeline. Although failure to meet mechanical specifications was not the cause of the incident, the investigations revealed that there were fittings installed on the pipeline with yield strength of less than Specified Minimum Yield Strength (SMYS). The NEB undertook further investigations to determine if this low yield issue might indicate a systemic problem. In the cases examined, contrary to the recorded information in the Material Test Reports (MTRs), not all fittings met the specified mechanical properties requirements, and this was due to inadequate controls in the Quality Assurance Programs (QAPs) of different stakeholders. It is also important to note that MTR results based on a coupon test may not always reflect the properties of each fitting produced following that process.

The NEB has taken several actions in order to address this potential issue including:

- Issuing industry-wide Safety Advisories

- Issuing Orders to all companies under its jurisdiction

- Commissioning a third party to investigate and write a technical paper on this issue

- Hosting a technical workshop to facilitate broad dialogue between various stakeholders (using the technical paper as a seed document)

In this paper, the authors first review the manufacturing process of Q&T fittings. Then case studies are discussed involving four instances of nonconforming fittings. Lastly the authors propose solutions for different stakeholders to effect improvement in Quality Assurance (QA) of pipeline fittings. The authors also recommended enhancement of applicable clauses in related standards and initiation of several research and development (R&D) projects.

Commentary by Dr. Valentin Fuster
2018;():V003T05A017. doi:10.1115/IPC2018-78306.

When faced with an opportunity to install a branch connection using the “hot tapping” technique, pipeline operating companies have a wide variety of choices when it comes to branch connection design and installation practices (e.g., welding procedure options) depending on the application. The objective of a recently-completed joint industry project (JIP) was to develop industry best practices for hot tap branch connections, including a compendium of properly qualified procedures, guidance pertaining to specification of branch connection design for specific applications, and guidance pertaining to related areas of concern for which there was not widespread agreement.

The core group of welding procedures that was developed and qualified for branch groove welds and sleeve fillet welds all involve the use of shielded metal arc welding (SMAW) and conventional low-hydrogen electrodes. There are applications for which other welding processes and consumables have advantages, so procedures for a broader range of applications were also developed and qualified. All of the procedures were qualified in accordance with the requirements of a range of relevant industry codes, including the Twenty-first Edition of API Standard 1104.

The various options for branch connection design include integrally-reinforced fittings (e.g., Weldolets®), fabricated branch connections, and full-encirclement pressurized tees (e.g., Stopple® fittings). Some designs are better suited to some applications than to others. The guidance for specifying branch connection designs focused on geometric parameters, such as branch diameter, header diameter, and branch-to-header diameter ratio. Several antiquated branch connection designs that should no longer be used were also identified.

The related areas of concern for which guidance was developed included the need for sleeve end fillet welds, burnthrough prediction for in-service welding on thin-wall pipelines, pressure limits/pressure reduction requirements, flow rate limits, heat-affected zone (HAZ) hardness limits, welder qualification requirements, branch connection location and fit-up, pipeline support requirements, branch connection welding sequence, preheating for in-service welds, fillet weld size requirements, extent of welding required for integrally-reinforced fittings, inspection/non-destructive testing (NDT) requirements, delay time prior to inspection for hydrogen cracking, pressure testing prior to tapping, and grouting of larger diameter, larger diameter-ratio branch connections. This guidance, along with the branch connection design guidance, was used to develop a generic company specification for installing hot tap branch connections in the field. The use of this guidance and the compendium of properly qualified welding procedures that was developed during the JIP will reduce the cost of installing hot tap branch connections, increase safety during installation, and increase the reliability of completed connections.

Commentary by Dr. Valentin Fuster
2018;():V003T05A018. doi:10.1115/IPC2018-78311.

Tensile testing on large diameter line pipe is generally done using strap samples obtained in the transverse to pipe axis (TPA) orientation of a pipe. The strap samples are then flattened and machined prior to testing. Although the standardized tensile testing is well documented, the variability in the reported TPA tensile properties of the same material tested within a lab or at different labs has always been an issue.

Recent work conducted at EVRAZ NA research lab has identified flattening as the main source of the variability in reported yield strength (YS) values for line pipe. The lack of a standard procedure for flattening TPA strap samples is a major obstacle to obtaining consistent results. Therefore, the main objective of this current study was to establish a standardized flattening procedure for TPA strap samples.

Both finite element analysis (FEA) and experimental approaches were adopted. Various flattening methods and fixtures were studied. Extensive flattening experiments were conducted on TPA samples from different line pipe products.

Results showed that the spring back after flattening in a TPA sample is different for pipes with different gauge and grades. It was established that consistent flattening can be achieved using appropriate fixtures for differerent ranges of tubular products defined by grade, diameter and gauges. Evaluation of the flattening fixture designs and experimental results are discussed in this paper.

Topics: Pipes
Commentary by Dr. Valentin Fuster
2018;():V003T05A019. doi:10.1115/IPC2018-78389.

The results of in-depth analysis of microstructure and crystallographic texture of several industrial batches of line pipes with known full-scale burst test results are presented. Several microstructural features promoting splitting are highlighted and quantified using electron back-scattered diffraction (EBSD) data. The actual splitting intensity is evaluated by means of Charpy tests in the direction of pipe wall thickness (Z-direction) and correlates with the microstructural parameters determined by EBSD analysis. This knowledge can be used in the design of thermo-mechanical controlled processing (TMCP) dedicated to production of splitting-free steel.

Topics: Steel , Pipelines
Commentary by Dr. Valentin Fuster
2018;():V003T05A020. doi:10.1115/IPC2018-78431.

High strength, butt-welded pipeline fittings are critical components for the construction of reliable and safe pipeline systems to extract, gather and transmit oil and gas products. Due to stringent safety and environmental requirements, fittings manufacturers are obliged to adhere to commonly accepted industry standards (e.g. CSA Z245.11, MSS-SP-75) and adopt supplementary operators’ specifications. Nevertheless, there have been several recent cases where fittings delivered by qualified manufacturers and available through local stock suppliers have not met the specified tensile properties, such that they failed during hydrostatic pressure tests or in-service operations. The issue has triggered concerns of operators and regulators (e.g. NEB SA 2016-01) warning about the use of substandard fittings. Although deficiencies in engineering design or operation beyond permissible conditions could be contributing factors, the root cause of the recent fittings failures was mainly associated with the underlying metallurgy and processing resulting in critically low yield strength and/or toughness levels. Further, existing standards and specifications are not stringent enough to screen out fittings with inadequate steel composition or improper manufacturing parameters. As such, a comprehensive modelling and experimental study has been launched to understand the interplay between the composition, grade, geometry and plant-specific processing parameters of quenched and tempered pipeline components. The experiment entailed plant trials using an instrumented NPS 36″ 3D elbow to measure the actual thermal response of the fitting during reheating, quenching and tempering cycles. Data was acquired from 36 different positions on the part in order to monitor any deviations from intended production parameters. Further, the metallurgical behaviour of the base steel plate, in terms of austenite grain growth, continuous cooling transformations (CCT) and temper softening of the as-quenched microstructure, has been established by dilatometric tests and microstructural characterization. The analysis and coupling of these diverse data sets is not trivial and requires scientific-based computational modelling. An integrated thermal-structure-properties finite element model was developed to predict the temporal and spatial evolution of the microstructure and provide a 3D strength map for any as-quenched and as-tempered fitting. This predictive engineering tool aids the selection of adequate steels and suitable heat treatment parameters such that target gauges and grades can be manufactured by a given plant to meet the specified requirements and standards. This paper describes the aforementioned methodology and highlights the challenges associated with the manufacture of fittings; in particular thick-wall pipeline components. Further, guidelines and existing knowledge gaps for improved specifications and standards will be discussed.

Commentary by Dr. Valentin Fuster
2018;():V003T05A021. doi:10.1115/IPC2018-78748.

This paper describes the development of large diameter heavy wall seamless tee fitting of WPHY-80 grade for low temperature pipeline station application. Steel tees with thicker wall generally tend to have low fracture toughness either in pipe body or in weld joint and low weldability. Therefore, improvement of fracture toughness and weldability are particularly important with respect to development of higher strength and thicker wall seamless tee fittings.

For the requirement of the China-Russia Eastern Gas Pipeline Project, WPHY-80 large diameter, seamless heavy wall reducing outlet tees were developed, with DN1400 × DN1200 and 57mm wall thickness. The billet steel production process was electroslag remelting (ESR), and the tee fitting production process used a forging and hot extrusion combination. Finally, quenching and tempering were carried out.

In this paper, the mechanical properties and microstructure of WPHY-80 seamless tee were studied. The results of mechanical testing showed that the tensile yield strength of the tee body was more than 590 MPa and also provided excellent low temperature toughness (CVN > 200 J at −45°C), which met the requirements of the specification for fittings applied in the China-Russia Eastern Gas Pipeline Project. In addition, the results of welding procedure qualification showed that the welding performance of the WPHY-80 seamless tee was excellent.

Commentary by Dr. Valentin Fuster
2018;():V003T05A022. doi:10.1115/IPC2018-78776.

Pipeline integrity management systems rely on robust records and data so that the correct decisions are made. The Pipeline industry regulator is intending to ensure operators possess traceable, verifiable and complete (TVC) pipeline records as a basis for sound integrity and risk management. This is being driven by PHMSA in the notice of proposed rulemaking (NPRM) 49 CFR 192. In recent years, ROSEN has introduced RoMat PGS, an inline inspection service that is capable of determining yield strength and other information relevant for the calculation of maximum allowable operating pressure (MAOP).

The data obtained from multiple ILI services forms the fundamental basis for an engineering assessment that integrates ILI data and other pertinent information to assign pipe grade for each individual pipe, within identified populations, with minimized field verification efforts.

For pipeline sections with incomplete records, the addition of strength data to other available information allows reliable identification of different populations along a pipeline. This permits the operator to better optimize integrity and material verification strategies.

In early 2017, Xcel Energy and ROSEN partnered to conduct a materials characterization assessment of a 20″ gas distribution pipeline. This was the second time that Xcel had implemented the service. This pipeline was originally installed in two sections, in 1928 and 1947, and has since been largely replaced over time through a series of reroutes and replacements. With more than 25 different assumed construction dates, the RoMat PGS service was used to identify the different pipe populations and confirm that these align with available records.

This paper presents the results and subsequent analysis. It represents a significant marker in the industry, demonstrating how a cooperative and integrated approach using state-of-the-art technology, engineering processes, and material verification techniques can be used to improve the integrity of operators’ records. The paper discusses the various stages of the process, the significant findings, such as the types of pipes identified and their properties, and — most importantly — how the results were implemented into a pipeline integrity and risk management system.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2018;():V003T05A023. doi:10.1115/IPC2018-78806.

To assess the integrity of pipelines containing cracks, single edge-notched tension (SENT) specimens in the end-clamped conditions have been widely adopted in the oil and gas industry to measure fracture toughness or resistance curves in terms of the J-integral or crack-tip opening displacement (CTOD). The CTOD toughness is often utilized in the strain-based design, and thus its measurement is important to the pipeline industry. Two types of CTOD-R curve test methods are available for a single SENT specimen test: J-conversion method and double clip gage (DCG) measurement method. However, these two CTOD test methods often determine different R-curves, leading to a long-running dispute.

To better understand the difference of the two CTOD test methods as well as the effect of material strain hardening rate on CTOD-R curves, a set of clamped SENT specimens are tested for two ductile steels with a high strain hardening rate (A36) and a low strain hardening rate (X80). Experimental R-curves are analyzed for the two steels, and results show that the CTOD-R curves determined using the J-conversion method and the DCG method are comparable for X80, but significantly different for A36. To study the root cause, elastic-plastic finite element analyses are performed for the SENT specimens of A36 and X80. With the numerical results of J-integral and CTOD, different CTOD estimation methods are evaluated, and the root causes of their differences are analyzed. On this basis, discussions are made on how to use the two types of CTOD-R curves in the pipeline design and integrity assessment.

Commentary by Dr. Valentin Fuster

Materials and Joining: Materials

2018;():V003T05A024. doi:10.1115/IPC2018-78102.

Transverse tensile samples were extracted from the centreline position of three different compositions of uncoated thick walled microalloyed X70 UOE pipe at a location 180° from the weld. Aging heat treatments of 5, 15, and 25 minutes and temperatures of 175, 215, and 255°C were applied. Tensile tests were conducted on both the original pipe and on pre-strained samples. Microstructural analysis was undertaken using optical microscopy and scanning electron microscopy (SEM). The effects of a combined time and temperature aging parameter, pre-strain, microstructure and tensile work hardening behaviour on the pipe yield stress and yield to tensile strength ratio, is presented.

Topics: Steel , Pipes
Commentary by Dr. Valentin Fuster
2018;():V003T05A025. doi:10.1115/IPC2018-78491.

Along with the development of the energy industry, demand for oil and gas pipelines has increased, and as the low oil price era has been prolonged, more economical pipe design and construction are required. Especially, ERW pipe has been expanding its range of applications, which is advantageous in terms of productivity and price. ERW pipes are made by passing through continuous rollers, where unintentional plastic deformation such as the Bauschinger effect occurs. Since plastic deformation caused by repetitive loading and unloading changes the initial properties of steel, it is necessary to precisely predict the final properties of the pipe as well as an accurate understanding of the manufacturing process. So, this study focused on evaluating the effects of manufacturing process considering plastic deformation for high performance ERW pipe manufacturing.

In this paper, three manufacturing process stages of ERW pipe were simulated as 3D nonlinear finite element models using ABAQUS: forming stage, sizing stage, and flattening stage. And the ABAQUS model was verified by comparison with the outer diameter measured from full-scale size pipes. In order to maintain the continuity of analysis between each manufacturing process stage, PEEQ, Alpha and residual stress were obtained from each manufacturing process stage, and then these mechanical properties were mapped to the next manufacturing process stage. And change of mechanical properties during the each manufacturing process stage were examined. Finally, the change of material properties at the flattening stage where reverse bending occurs was evaluated, especially in influence of sizing ratio on the flattening stage. Through the developed analytical model, numerical prediction of the mechanical properties of ERW pipe is possible.

Commentary by Dr. Valentin Fuster
2018;():V003T05A026. doi:10.1115/IPC2018-78511.

A continuous demand for plates for X60-X120 pipes with high toughness and cold resistance requires the development of new methods of additional grain refinement at all stages of thermo-mechanical control processing (TMCP). An effect of structure formation during slab reheating was studied. Physical models of secondary recrystallization during reheating and austenite recrystallization at roughing rolling of Nb-microalloyed pipeline steels were developed. Grain refinement in the course of hot deformation was studied through physical modeling. Using the recrystallization model, new rolling schedules were introduced. Industrial trials were conducted; the effect of reheating and deformation parameters on cold resistance of steel was investigated. Implementation of the results of given study into production practice made it possible to produce plates with excellent properties, including strength, toughness, and cold resistance.

Commentary by Dr. Valentin Fuster
2018;():V003T05A027. doi:10.1115/IPC2018-78551.

In the oil sand production field in Canada, steel pipes are used for injecting steam into the sands. Pipes for steam distribution are subjected to high operating temperature such as 350 degrees C for a long time. In this study, in order to insure the reliability of high strength pipe for steam distribution, long-term heating tests were conducted for X80 grade UOE pipe. To simulate the long-term operation at 350 degrees C for 40 years, accelerated tests were conducted at 400 degrees C for up to 4400 hours. The effect of initial bainite microstructure on tensile properties after long-term heat treatment was investigated by using two kinds of steel pipes with different bainite microstructure. One is accelerated cooling (ACC) type, and the other is heating on-line process (HOP) type just after accelerated cooling in plate manufacturing process.

It was revealed that strength decrease in ACC type steels produced by only accelerated cooling was mainly governed by decomposition of hard phase MA (Martensite-Austenite constituent) and recovery of dislocations. On the other hand, HOP type steels had small amount of MA and nanometer-sized carbides by applying HOP after accelerated cooling. The HOP type steels had almost the same initial strength in spite of small amount of MA. Fine niobium carbides gave enough precipitation strengthening. Formation of fine niobium carbides was promoted by the addition of niobium. The precipitates were stable after long-term heat treatment at 400 degrees C. It is confirmed that the fine niobium carbides in HOP type steels remained even after long-term heat treatment. The suppression of initial MA also lead to minimize the strength decrease by MA decomposition. Therefore, HOP type steels tend to have higher resistance to the strength decrease after long-term heat treatment.

Commentary by Dr. Valentin Fuster
2018;():V003T05A028. doi:10.1115/IPC2018-78574.

To guarantee the structural integrity of oil and gas transporting pipelines, a detailed analysis of the pipe’s structural response has to be performed. This is of particular importance for offshore applications. As large scale testing is costly and time consuming, one often relies on FE (Finite Element) modelling to accomplish, at least, part of this task. Properties that typically need to be evaluated are compressive strain capacity, collapse resistance and ovalization during reel-lay installation. Furthermore, it can be assumed that those properties are influenced by the pipe forming process, as pipe forming will change the mechanical properties and the level of anisotropy and will modify/introduce residual stresses. Therefore, a first logical step is to simulate pipe forming before evaluating the pipe’s structural performance, to account for these effects.

The reliability of FE simulations largely depends on the capability of the constitutive model to accurately describe the mechanical behaviour of the material being studied. Most commercial FE codes only offer combined kinematic-isotropic hardening models. Those models cannot capture the so-called cross-hardening effect and can therefore not predict the evolution of anisotropy during pipe forming. The present paper discusses the implementation and calibration of a more advanced constitutive model, more specifically the Levkovitch-Svendsen model, which accounts for isotropic, kinematic and distortional hardening. The model was implemented in Abaqus/Implicit through a UMAT user subroutine. An inverse modelling approach was applied to calibrate the constitutive model, whereby an extensive set of mechanical tests, involving cyclic tension-compression tests and tests with changing strain paths, was conducted.

To assess the model’s performance, it was used in two case studies. The first study focused on the evolution of mechanical properties during spiral pipe forming. The results show that the Levkovitch-Svendsen model allows prediction of the properties in both the transverse and longitudinal direction on pipe. When applying a kinematic-isotropic hardening law only, the properties in the longitudinal direction are significantly underestimated. In the second study, different hardening models were used to predict the evolution of ovality during reel-lay installation. It was observed that the predictions made with the Levkovitch-Svendsen model were much closer to the experimental values than the results obtained by means of a kinematic-isotropic hardening model.

Commentary by Dr. Valentin Fuster
2018;():V003T05A029. doi:10.1115/IPC2018-78763.

A decade ago, the pipeline industry was actively exploring the use of high strength steels (X80 and greater) for long distance, large diameter pipelines operating at high pressures. However in recent years the industry has adopted a more conservative approach preferring to utilize well established X70 grade pipe in heavier wall thicknesses to accommodate the demand for increased operating pressures.

In order to meet this demand, EVRAZ has undertaken a substantial upgrade of both its steelmaking and helical pipemaking facilities. The EVRAZ process is relatively unique employing electric arc furnace (EAF) steelmaking to melt scrap, coupled with Steckel mill rolling for the production of coil which is fed into helical DSAW pipe mills for the production of large diameter line pipe in lengths up to 80 feet. Prior to the upgrade production had been limited to a maximum finished wall thickness of ∼17 mm. The upgrades have included installation of vacuum de-gassing to reduce hydrogen and nitrogen levels, upgrading the caster to improve cast steel quality and allow production of thicker (250 mm) slabs, upgrades to the power trains on the mill stands to achieve greater rolling reductions, replacement of the laminar flow cooling system after rolling and installation of a downcoiler capable of coiling 25.4 mm X70 material. As well a new helical DSAW mill has been installed which is capable of producing large diameter pipe in thicknesses up to 25.4 mm.

The installation of the equipment has provided both opportunities and challenges. Specific initiatives have sought to produce X70 line pipe in thicknesses up to 25.4 mm, improve low temperature toughness and expand the range of sour service grades available. This paper will focus on alloy design and rolling strategies to achieve high strength coupled with low temperature toughness. The role of improved centerline segregation control will be examined. The use of scrap as a feedstock to the EAF process results in relatively high nitrogen contents compared to blast furnace (BOF) operations. While nitrogen can be reduced to some extent by vacuum de-gassing, rolling practices must be designed to accommodate nitrogen levels of 60 ppm. Greater slab thickness allows greater total reduction, but heat removal considerations must be addressed in optimization of rolling schedules to achieve suitable microstructures to achieve both strength and toughness. This optimization requires definition of the reductions to be accomplished during roughing (recrystallization rolling to achieve a fine uniform austenite grain size) and finishing (pancaking to produce heavily deformed austenite) and specification of cooling rates and coiling temperatures subsequent to rolling to obtain suitable transformation microstructures. The successful process development will be discussed.

Topics: Gages , Pipes
Commentary by Dr. Valentin Fuster
2018;():V003T05A030. doi:10.1115/IPC2018-78809.

There has been a number of unexpected girth weld failures in newly constructed pipelines. Girth weld failures have also been observed in pre-service hydrostatic testing. Post-incident investigations indicated that the pipes met the requirements of industry standards, such as API 5L. The welds were qualified per accepted industry standards, such as API 1104. The field girth welding was performed, inspected, and accepted per industry standards, such as API 1104. Some of the traditional causes of girth weld failures, such as hydrogen cracks and high-low misalignment, were not a factor in these incidents.

This paper starts with a review of the recent girth weld incidents. A few key features of a failed weld and their implications are examined. The characteristics of the recent failures is summarized, and the major contributing factors known to date are given.

Some of the options to prevent future failures include (1) changes to the tensile properties of the pipes and enhanced hardenability, (2) welding options aimed at increasing the weld strength and minimizing heat-affected zone (HAZ) softening, and (3) reduction of stresses on girth welds. This paper focuses on the first two options.

The trends of chemical composition and tensile properties of linepipe are reviewed. The potential contribution of these trends to the girth weld incidents is examined. Possible changes to the linepipe properties and necessary updates in the testing and qualification requirements of the linepipes are provided.

Welding options beneficial to enhanced girth weld strain capacity are discussed. Possible revisions to welding procedure qualification requirements, aimed at achieving a minimum level of strain tolerance/capacity, are proposed. The application of previously developed tools in estimating the propensity of HAZ softening is reviewed.

Commentary by Dr. Valentin Fuster
2018;():V003T05A031. doi:10.1115/IPC2018-78815.

The offshore oil and gas industry has seen a continual trend of conservatism in design for applications where a high level of strain is expected during the installation phase, leading to a tightening of the acceptable mechanical property performance of the linepipe. This is especially true with regards to longitudinal tensile properties in the strained and aged condition. Due to the expected change in data seen throughout previous projects, are the tightening expectations realistic for the manufacturers and cost effective for the client?

The current condition that is widely accepted for the release of pipes suitable for high strain events is straining and ageing. However is this appropriate given that pipes are coated (aged), installed (strained) then left over time (aged)? These questions will be investigated through a series of tests and data analysis. For this project a conventional ageing as per the standard and a coating simulation were used, with all test pieces having either 0% or 1% applied strain. The test pieces for this project were tested in one of seven conditions;

• As manufactured

• Aged (at 200°C/5min or 250°C/1hr)

• Strained and aged (1% strain applied then aged at 200°C/5min or 250°C/1hr)

• Aged and strained (aged at 200°C/5min or 250°C/1hr then 1% strain applied)

To ensure a direct comparison in the data the comparable test pieces were taken from the same circumferential position on the pipe. All testing for this project was carried out on material of a similar composition and future development of this work will comprise of documenting the effect on different microstructures, t/D ratios and levels of strain. It was clear from the project that changing the conditions used had an impact on the results. This could have implications for the industry in the future and has set up a scheme of development following on from this project to gain a greater understanding.

Commentary by Dr. Valentin Fuster

Materials and Joining: Welding

2018;():V003T05A032. doi:10.1115/IPC2018-78250.

Welds that are made onto an operating pipeline cool at an accelerated rate as a result of the flowing pipeline contents cooling the weld region. The accelerated cooling rates increase the probability of forming a crack-susceptible microstructure in the heat-affected zone (HAZ) of in-service welds. The increased risk of forming such microstructures makes in-service welds more susceptible to hydrogen cracking compared to welds that do not experience accelerated cooling.

It is understood within the pipeline industry that hydrogen cracking is a time-dependent failure mechanism. Due to the time-dependent nature and susceptibility of in-service welds to hydrogen cracking, it is common to delay the final inspection of in-service welds. The intent of the delayed inspection is to allow hydrogen cracks, if they were going to occur, to form so that the inspection method could detect them and the cracks could repaired. Many industry codes provide a single inspection delay time. By providing a single inspection delay time it is implied that the inspection delay time should be applied for all situations independent of the welding conditions or any other preventative measures the company may employee.

There are many aspects that should be addressed when determining what should be considered an appropriate inspection delay time and these aspects can vary the inspection delay time considerably. Such factors include the cooling characteristics of the operating pipeline, the welding procedure that is being followed, the chemical composition of the material being welded and if any preventative measures such as post-weld heating are applied.

The objective of this work was to provide an engineering justification for realistic minimum inspection delay times for different in-service welding scenarios. The minimum inspection delay time that was determined was based on modelling results from a previously developed two-dimensional hydrogen diffusion model that predicts the time to peak hydrogen concentration at any location within a weld HAZ. The time to peak hydrogen concentration was considered equal to the minimum inspection delay time since the model uses the assumption that if a weld was to crack the cracking would occur prior to or at the time of peak hydrogen concentration.

Several factors were varied during the computer model runs to determine the effect they had on the time to peak hydrogen concentration. These factors included different welding procedures, different material thicknesses and different post-weld heating temperatures. The post-weld heating temperatures were varied between 40 F (4 C) and 300 F (149 C). The results of the analysis did provide justification for reducing the inspection delay time to 30 minutes or less depending on the post-weld heating temperature and pipeline wall thickness. This reduction in inspection delay time has the potential to significantly increase productivity and reduce associated costs without increasing the associated risk to pipeline integrity or public safety.

Commentary by Dr. Valentin Fuster
2018;():V003T05A033. doi:10.1115/IPC2018-78283.

An extensive experimental program to characterize the Charpy-V-notch (CVN) impact toughness of ten contemporary Electric Welded (EW) pipes was recently completed to establish a database to support the revision of the EW seam weld Charpy toughness testing requirements in Canadian Standards Association (CSA) Z245.1-14. The toughness in these welds is lowest at or near the weld bond line (BL) within a narrow zone ±≈0.5 mm wide. It is feasible and desirable to position the BL notch to a precision to match this width, i.e. ±0.5 mm from the BL. In this paper, typical results of microstructure, micro-hardness, CVN toughness (i.e. absorbed energy) as a function of temperature and notch location, and fractography will be presented. CVN absorbed energy requirements for EW welds in CSA Z245.1 have been determined using a failure assessment diagram (FAD) procedure. The values of required CVN estimated from the FAD are close to those specified in CSA Z245.1-14 but are higher than the specification in CSA Z245.1-18.

Commentary by Dr. Valentin Fuster
2018;():V003T05A034. doi:10.1115/IPC2018-78305.

Hydrogen-assisted cracking in welds, which is also referred to as ‘hydrogen cracking’ or ‘delayed cracking,’ often requires time to occur. The reason for this is that time is required for the hydrogen to diffuse to areas with crack susceptible microstructures. Prior to inspection for hydrogen cracking, general good practice indicates that a sufficient delay time should be allowed to elapse — to allow any cracks that are going to form to do so and for the cracks to grow to a detectable size. What is a ‘sufficient’ delay time? Why does a delay time tend to be required for some applications (e.g., installation of a hot tap branch connection) and not for others (e.g., construction of an offshore pipeline from a lay barge)? This paper will address these and other related questions and present the results of recent experimental work on this subject.

When determining appropriate delay times prior to inspection, it is important to consider not only the time-dependent nature of hydrogen cracking, but also the expected susceptibility of the weld to cracking. From a time-dependent nature standpoint, longer delay times decrease the chance that cracking can occur after inspection has been completed. From a probability standpoint, if measures can be taken to assure that the probability of cracking is extremely low, then determining an appropriate delay time becomes a moot point. In other words, if the weld is never going to crack, it does not matter when you inspect it. The probability of cracking can be minimized by using more conservative welding procedures (i.e., by designing out the risk of hydrogen cracking during procedure qualification). For example, if hydrogen levels are closely controlled by using low-hydrogen electrodes or a low-hydrogen welding process, or if the hydrogen in a weld made using cellulosic-coated electrodes is allowed to diffuse away after welding by careful application of preheating and slow cooling, or the use of post-weld preheat maintenance (i.e., post-heating), the probability of cracking is significantly reduced, and immediate inspection may be justified. This alternative approach to time delay prior to inspection for hydrogen cracking, which can allow for immediate inspection, will be presented.

Commentary by Dr. Valentin Fuster
2018;():V003T05A035. doi:10.1115/IPC2018-78317.

Multipass welding of high strength steels used for fabrication and joining of transmission pipelines presents a number of metallurgical challenges. A key concern is both the strength and toughness of the heat affected zone (HAZ) adjacent to both seam and girth welds. In this work, a systematic study has been conducted on regions of the heat affected zone in the base metal where the first welding pass produces a thermal excursion which results in a coarse-grained heat affected zone (CGHAZ). The subsequent weld pass involves intercritical annealing of this region, i.e. a microstructure associated with intercritically reheated coarse grain heat affected zone (ICCGHAZ). The small ICCGHAZ region is often identified as being particularly susceptible to crack initiation. This work was undertaken to understand microstructure development in this zone and how the ICCGHAZ may affect the overall performance of the HAZ.

Gleeble thermomechanical simulations have been conducted to produce bulk samples representative of different welding scenarios. Charpy impact tests and tensile tests have been performed over a range of temperatures. It was found that when a continuous necklace of martensite-austenite islands form on the prior austenite grain boundaries (i.e. for a M/A fraction of ≈10%), the Charpy impact toughness energy is dramatically decreased and the ductile brittle transition temperature is significantly raised. Detailed studies on the secondary cracks have been conducted to examine the fracture mechanisms in the different microstructures. The results show that the lower bainite microstructures obtained after the 1st thermal treatment, representative of CGHAZ have excellent impact properties. The impact toughness of the microstructures typical of ICCGHAZ is strongly dependent on the composition as well as morphology and spatial distribution of the resulting martensite-austenite (M/A) islands transformed from inter-critically formed austenite. This zone can play a significant role in fracture initiation and thus needs to be considered in alloy and welding process designs.

Commentary by Dr. Valentin Fuster
2018;():V003T05A036. doi:10.1115/IPC2018-78416.

The fracture mechanics based engineering critical assessment (ECA) method has been accepted as a fitness for service (FFS) approach to defining weld flaw acceptance criteria for pipeline girth welds. Mechanized gas metal arc welding (GMAW) processes are commonly used in cross country pipeline girth weld welding because of the advantages in good quality and high productivity. With the technical advancements of non-destructive testing (NDT) techniques, automated ultrasonic testing (AUT) has greatly improved flaw characterization, sizing and probability of detection during weld inspection. Alternative weld flaw acceptance criteria are permitted in pipeline construction code to assess the acceptability of mechanized girth welds using an ECA. The use of an ECA based weld flaw acceptance criteria can significantly reduce the construction cost. Mechanized girth weld acceptance criteria have been progressively transitioned from workmanship standards into using fitness for service based ECAs.

To successfully deliver an ECA on a pipeline project, a multidisciplinary approach must be taken during the welding design and construction stages. Welding, NDT, mechanical testing and field control are all integral elements of pipeline construction. All these four elements have to be fully integrated in order to implement the ECA and achieve the overall integrity of a pipeline. The purpose of this paper is to discuss the importance of the integration of these four elements necessary for proper implementation of the ECA weld flaw acceptance criteria.

Commentary by Dr. Valentin Fuster
2018;():V003T05A037. doi:10.1115/IPC2018-78498.

Double submerged arc welding is an efficient process used during the production of longitudinally-welded large-diameter pipes. It is well known that the associated high heat input has a negative influence on the toughness of the heat-affected zone (HAZ). The toughness drop is related to changes in the HAZ microstructure compared to the base metal. The austenite grain size increases significantly and larger carbon-rich martensite/austenite particles (M/A-particles) are formed within a coarse bainitic matrix during the phase transformation compared to the as-rolled base material. The exact relationship between the microstructure, the processing conditions, base metal composition and the weld metal are at the focus of attention of materials development efforts at EUROPIPE and Salzgitter Mannesmann Forschung GmbH (SZMF).

In the present study, scanning electron microscopy (SEM) and electron backscatter diffraction (EBSD) were used to investigate the HAZ of X70 large-diameter pipe material as well as tested Charpy specimens from the same material. Secondary cracks in the direct vicinity of the primary fracture surface of tested Charpy specimens from the HAZ were analyzed by EBSD and SEM to investigate the damage mechanism in detail. It was found that these cracks originate at M/A-particles and that the dominant crack path depends on the crystallographic orientation of the surrounding matrix. The analysis of several EBSD measurements and a 3D-analysis of the propagation direction of the crack showed that secondary cracks frequently propagate parallel to {100} and rarely along {110}-planes. It is known from literature that these are preferred cleavage planes in ferritic steels. The SEM analysis performed in the HAZ of the investigated steel showed that the volume fraction of elongated M/A-particles is elevated close to the fusion line and decreases within the first few hundred micrometers distance from the fusion line. The EBSD measurements illustrate that the geometrically necessary dislocation density is significantly increased in the neighborhood of M/A-particles. This indicates that the bainitic matrix is work-hardened around the M/A-particles during testing and is therefore more prone to the formation of microcracks than other surrounding regions.

Commentary by Dr. Valentin Fuster
2018;():V003T05A038. doi:10.1115/IPC2018-78504.

Toughness testing of the heat affected zone (HAZ) of longitudinal welds is increasingly often required in pipeline standards and specifications. This includes simple tests such as the Charpy impact test that was designed to serve as quality test as well as enhanced methods including crack tip opening displacement (CTOD) tests that are necessary to conduct an engineering critical assessment (ECA). If occasional low toughness values are observed, the question turns towards assessing the impact of such numbers and how representative they are of the behavior of a pipe in service. The significance of low toughness values measured in laboratory testing can be judged on basis of ring expansion and hydraulic burst tests.

The current study summarises an extensive test series to quantify the toughness of submerged arc welds (SAW) obtained by different test methods. The tested pipes cover a wide range of material including medium strength X70 up to high strength X100. Their welds are characterized in terms of fracture toughness properties with single edge notch tension (SENT) and single edge notch bending (SENB) tests. Different constraint levels are obtained within each series by introducing notches of standard depth as well as shallow notches. Structural behavior is characterized with burst tests as well as ring expansion tests containing notches in the longitudinal weld.

The experimental results are assessed within dedicated finite element studies. The assessment is conducted for pipes serving as pressure containment, thus having circumferential stress resulting from internal pressure. Based on the results achieved the conclusion can be drawn that the standard route including high constraint CTOD leads to overly conservative results concerning the integrity of longitudinal welds. A better representation of structural behavior is observed in ring expansion tests.

Commentary by Dr. Valentin Fuster
2018;():V003T05A039. doi:10.1115/IPC2018-78518.

Many pipe mills may not be familiar with a Crack Tip Opening Displacement (CTOD) requirement on the pipe seam weld, nor will they find easily relevant information in open literature. Influencing — and certainly not independent — factors are: welding parameters, base material and consumable selection. Out of these, the welding parameters such as heat input and cooling rate cannot be varied over a wide range during the pipe production, which means that the leverage is rather limited at the given welding process. The properties of the heat affected zone will be mainly affected by the base material, while the properties of the weld metal will be affected by both, base material and filler wire selection. In particular with respect to the weld metal properties it will be difficult to obtain general quantitative information. For example, a welding consumable supplier will readily provide the properties of the filler wires but would be unable to predict the changes caused by the dilution from any base material in the weld pool and specific welding procedures that may have been used.

To support the pipe mills in the selection of the consumables for submerged arc welding, an experimental program was launched with the aim to provide recommendations on how to optimize CTOD toughness of the spiral weld seam. For this, a large number of welds were produced on 20 mm thick X70 coil samples, with eight different filler wire combinations, using a 2-wire (tandem) set-up for both the inside and outside weld. Welding parameters were kept constant. The welding program was applied to two different X70 steels to determine a potential influence of the micro-alloying elements, particularly Nb.

The results show clearly that a careful consumable selection is required for obtaining acceptable CTOD toughness in the weld metal. Ni-Mo and Ti-B additions to the weld metal are found to be beneficial with both steel concepts. Mo addition alone both to the ID and OD welds was clearly not a suitable selection.

Topics: Welding
Commentary by Dr. Valentin Fuster
2018;():V003T05A040. doi:10.1115/IPC2018-78600.

Economic and environmental incentives encourage operators to maintain pipeline operation during repair and maintenance procedures including hot-tap branch fitting installation onto pipelines. Welding onto a liquid-filled pipeline induces accelerated cooling of the weld and heat affected zone (HAZ), increasing the propensity for cracking. In-service welding codes and due diligence requires that several key factors be considered during the design of an in-service welding procedure specification for its intended purpose. The level of restraint (LoR) imposed by the geometry, material, or dimensional differences of the branch compared to the run pipe has also been shown to be a significant contributor to cracking. Finite element analysis (FEA) was utilized to investigate the geometric effects of an in-service weld procedure to approximate the LoR of hot-tap branch installation. The LoR was quantified and compared by simulating multi-pass weld sequences on two configurations: a branch-on-pipe (BoP) configuration of various dimensions and a configuration using perpendicular plates (PP) that has been used as an alternative to the branch-on-pipe configuration. The highest LoR, as measured by transverse tensile stress at the fillet weld toe, was the branch-on-pipe configuration with the largest branch wall thickness, the smallest branch diameter, the largest run pipe diameter, and the largest run pipe wall thickness. FEA modeling revealed that the PP configuration has lower LoR, thus it is not recommended to use for simulating in-service branch weld procedures.

Topics: Welding , Geometry
Commentary by Dr. Valentin Fuster

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