bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of an Effective ASME IX Welding Procedure Qualification Program for Pipeline Facility and Fabrication Welding
Authors: Lu Junfang , Huntley Bob , Ludwig Luke 
Published: November 2016

For cross country pipeline welding in Canada, welding procedures shall be qualified in accordance with the requirements of CSA Z662 Oil and Gas Pipeline Systems. For pipeline facility and fabrication welding on systems designed in accordance with CSA Z662 or ASME B31.4, welding procedures qualified in accordance with the requirements of ASME Boiler & Pressure Vessel Code Section IX are permitted and generally preferred.
Welding procedures qualified in accordance with ASME IX provide advantages for pipeline facility and fabrication applications as a result of the flexibility achieved through the larger essential variable ranges. The resulting welding procedures have broader coverage on material thickness, diameter, joint configuration and welding positions. Similarly, ASME IX is more flexible on welder performance qualification requirements and accordingly a welder will have wider range of performance qualifications. When applied correctly, the use of ASME IX welding procedures often means significantly fewer welding procedures and welder performance qualifications are required for a given scope of work.
Even though ASME IX qualified welding procedures have been widely used in pipeline facility and fabrication welding, it is not well understood on how to qualify the welding procedures in accordance with ASME IX and meet the additional requirements of the governing code or standard such as CSA Z662 in Canada. One significant consideration is that ASME IX refers to the construction code for the applicability of notch toughness requirements for welding procedure qualification, yet CSA Z662 and ASME B31.4 are both silent on notch toughness requirements for welding procedure qualification.
This paper explains one preferred method to establish and develop an effective ASME IX welding procedure qualification program for pipeline facility and fabrication welding while ensuring suitability for use and appropriate notch toughness requirements. The paper discusses topics such as base material selection, welding process, welding consumable consideration and weld test acceptance criteria.
HFI Welded Steel Pipes for Low Temperature Pipelines
Authors: Brauer Holger , Veit Manfred , Stiller Michael , Grube Lutz , Meyer Frank 
Published: November 2016

Due to an ever increasing endeavor for the reduction of greenhouse gas emissions over the next few decades, with a gradually increasing demand for energy world-wide and despite a society which is becoming more and more civilized and industrialized, the actual challenge in handling this problem is intensified by decreasing sources of energy, a global economic recession as well as energy market instabilities.
Replacing fossil energy sources such as oil with alternative energy concepts is at best difficult because of the high initial investment costs needed installing alternative energy concepts.
As an answer to the problems faced, the industry offers several solutions ranging from advanced technologies with a high efficiency ratio such as fuel cell and hydrogen energy, up to and including alternative new or renewable energy sources such as solar, hydro and wind power.
One of the major solutions for the transitional period to economical and reliable renewable energies is considered to be the use of Liquefied Natural Gas (LNG).
To accommodate for these requirements, Salzgitter Mannesmann Line Pipe has continuously developed highly sophisticated materials in the form of bainitic pipes for the transportation of gaseous or liquefied medium at ultra-low temperatures.
In the first part of this presentation paper the process route as well as the material and pipe properties will be shown and explained. In cooperation with our construction partner Fernwaerme-Technik (FW), the bainitic pipes were used to construct a special multi-pipe system for the conveyance of liquefied natural gas (LNG) at a temperature of −162 °C. The pipe system as well as results from the field testing is presented below and tests have been conducted on this system for three years using liquid nitrogen. It can be shown, that not only the low temperature pipe material requirements for transportation of LNG are fulfilled, moreover it offers further potential as an alternative for the replacement of expensive austenitic steels applied at temperatures down to −196°C.
Experimental Study of Elevated Temperature Composite Repair Materials to Guide Integrity Decisions
Authors: Sheets Colton , Rettew Robert , Alexander Chris , Baranov Denis , Harrell Patrick 
Published: November 2016

Over the past two decades, a significant amount of research has been conducted on the use of composite materials for the repair and reinforcement of pipelines. This has led to vast improvements in the quality of composite systems used for pipeline repair and has increased the range of applications for which they are viable solutions (including corrosion and mechanical damage). By using composite repair systems, pipeline operators are often able to restore the structural integrity of damaged pipelines to levels equal to or even in excess of the original undamaged pipe. Although this research has led to substantial advancements in the quality of these repair systems, there are still specific applications where questions remain regarding the strength, durability, and effectiveness of composite repair systems, especially in elevated temperature, harsh environment conditions.
This program initially involved composite repair systems from six manufacturers. The test group included both carbon and E-glass based systems. Performance based qualifications were used to reduce the size of the test group from the initial six systems down to three. The experimental study consisted of small-scale testing efforts that ranged from tensile tests performed over a range of temperatures to 10,000-hour material coupon tests at elevated temperatures. The elevated temperatures used for testing were intentionally selected by the operator to reflect the 248 °F design temperature of the target pipeline.
Using small-scale qualification testing outlined in ASME PCC-2 – Repair of Pressure Equipment and Piping standard (Article 4.1, Nonmetallic Composite Repair Systems: High-Risk Applications) as a foundation, the test program described in this paper was able to demonstrate that, when properly designed, and installed, some composite materials are able to maintain their effectiveness at high temperatures. This study combined short-term and long-term testing of composite systems and demonstrated the advantages of a 10,000 hour test when aging properties are unknown. Finally, the study showed that, although high-temperature reinforcement using composite repair systems is feasible and commercially available, this capability is not standard practice across the composite repair industry. Proper analysis and verification using experimental methods, including full scale testing should be conducted prior to installation of a composite repair system in these types of harsh conditions.
Finite Element Analysis of Composite Repairs With Full-Scale Validation Testing
Authors: Sheets Colton , Rettew Robert , Alexander Chris , Iyer Ashwin 
Published: November 2016

Composite repair systems for pipelines are continuing to be used for increasingly difficult and complex applications which can have a high consequence of failure. In these instances, full-scale testing is typically pursued at a high-cost to the manufacturer or operator. Finite element analysis (FEA) modeling is a valuable tool that becomes especially attractive as a method to reduce the number of full-scale tests required. This is particularly true when considering the costs associated with recreating complex load and temperature conditions. In order for FEA to fill this role, it is necessary to validate the results through full-scale testing at the same loads and temperatures. By using these techniques, FEA and full-scale testing can be used in unison to efficiently produce accurate results and allow for the adjustment of critical parameters at a much lower cost than creating additional full-scale tests.
For this program, a series of finite element analysis (FEA) models were developed to evaluate the performance of composite materials used to reinforce corroded steel pipe in critical applications at elevated temperatures up to 120 °C. Two composite repair manufacturers participated in the study which was conducted on 12-inch × 0.375-inch Gr. X60 pipes with machined simulated corrosion defects that represented 50% wall loss. Load conditions consisted of axial compressive loads or bending moments to generate compressive stresses in the machined defect.
In the described evaluation program, FEA simulations were able to produce results which supported those found in full-scale validation testing. From the FEA models stresses and strains were extracted from the reinforced steel and composite materials. Good correlation was observed in comparing the results. Although limitations of the modeling included accurately capturing differential thermal strains introduced by the elevated test temperature, the results indicated that FEA models could be used as a cost-effective means for assessing composite repair systems in high-temperature applications.
HISC in Onshore Pipelines: Design Considerations
Authors: Lockey Aaron , Young Andy , Turner Tim , Kelly Brendan 
Published: November 2016

The occurrence of Hydrogen Induced Stress Cracking (HISC) is well documented in offshore pipelines constructed from duplex steel. The conditions required for HISC to occur are exposure to water, presence of a negative electrical potential from cathodic protection, and application of a high tensile stress. There is evidence that through wall HISC crack growth can occur in forgings when these conditions are present for just a few hours.
Onshore pipelines may also be constructed from duplex steel to provide corrosion resistance, particularly flowlines carrying well fluids. Where the fluid has a high pressure or low temperature, high tensile stresses may occur. These stresses are further increased at localised stress raisers such as girth welds and attachment fillet welds. The presence of water in the soil and the use of cathodic protection is likely for most buried onshore pipelines. Therefore all the conditions necessary for HISC to occur may be present.
Guidance for assessing the susceptibility of offshore duplex steels to HISC is available in DNV-RP-F112, based on laboratory testing and industry experience following failures caused by HISC. However, historically it has not been commonplace to use duplex material for onshore high pressure pipelines, so no standard guidance is available. A detailed engineering assessment is therefore required. However, many onshore design engineers may not be familiar with the HISC failure mechanism, and may not consider it at all when designing a pipeline using duplex material.
This paper discusses recent experience in applying the design rules in DNV-RP-F112 in an onshore pipeline design project.
Firstly the paper covers the conditions necessary for hydrogen generation to occur. It discusses the differences between onshore and offshore cathodic protection systems, with reference to the electrical potential required for hydrogen generation. It concludes that in some situations, control of the cathodic protection potential will be the sole barrier to hydrogen generation, and thus its reliability can be of critical importance.
Secondly the paper describes the detailed analysis required to determine peak stresses and strains at localised stress raisers, for assessment against the limits provided by DNV-RP-F112. The definition of ‘peak’ stress and strain is discussed, since this is different from the definition more commonly used (for example in fatigue analysis). The HISC phenomenon is driven by dislocation movement due to applied stress, but DNV-RP-F112 provides limits in terms of both stress and strain. A method is presented to determine strains caused exclusively by stress and not by thermal expansion or the Poisson effect.
It is concluded that some interpretation of the DNV-RP-F112 guidance is needed for application in an onshore environment. Further work, including testing, is required to demonstrate whether the DNV-RP-F112 guidance can be applied reliably onshore.
Assessing the Benefits of Hydrotests for Pipelines With SCC History Post-Crack Detection ILI Runs
Authors: Al-Otaibi Nader A. , Al-Muslim Husain M. , Harper William , Bubenik Thomas , Al-Usaimi Waleed A. 
Published: November 2016

Stress corrosion cracking (SCC) is associated with pipelines made of susceptible steel operating in harsh corrosive environments under high stress. Saudi Aramco adapted the use of EMAT and UTCD in-line inspection (ILI) tools to locate, identify and size potential SCC defects, which revealed a significant number of cracks. All pipelines found with cracks have been in service for more than 30 years and tape coated. Many of these pipelines operate in subkha soil (alternatingly wet), indicating that the threat of SCC, which is time dependent, is persistent; requiring implementation of long-term mitigations.
The number of ILI-reported crack features varied from one to tens of defects per pipeline segment for the majority of the pipelines. Yet, some pipelines have been reported to have hundreds to thousands of cracks. Although these reported cracks are not deep enough to affect the near-term integrity, the cracks could potentially grow to become critical. Along with conducting ILI, Saudi Aramco investigated the use of hydrotests as a mitigation measure for pipelines found to contain SCC. Hydrotests are thought to complement the ILI program and ensure that the probability of premature pipeline failure is minimal.
Saudi Aramco conducted a study that entailed the evaluation of the benefit of conducting hydrostatic pressure testing as an SCC mitigation method for pipelines with reported SCC.
The assessment of hydrotests as a mitigation measure includes developing a set of survival probability matrices for each pipeline to determine which SCC defects would fail a hydrotest as a function of the test pressure and pipe properties.
A statistical analysis of the ILI and field results, is used to predict the number and dimensions of the estimated defect population within a pipeline. When this estimated defect population is combined with the survival matrices, a prediction of the expected number of failures during a hydrostatic pressure test can be estimated. The remaining defect population after a hydrotest is also predicted.
The effectiveness of the hydrostatic pressure test is taken as the ratio of features that failed in the hydrotest, divided by the total number of features that existed before the hydrotest. With the effectiveness of a hydrotest defined, it is possible to compare two assessment methods, such as ILI and hydrotesting when developing line-specific mitigation plans.
Susceptibility of Stress Corrosion Cracking in Liquid and Gas Pipelines: A Saudi Aramco Study Using Statistical Approaches
Authors: Harper William , Al-Otaibi Nader A. , Ababtain Abdulaziz N. , Bubenik Thomas , Al-Muslim Husain M. 
Published: November 2016

Owned by the Saudi Arabian Government, Saudi Aramco is a fully-integrated, global petroleum enterprise and a world leader in exploration and producing, refining, distribution, shipping and marketing. The company manages the largest proven reserves of conventional crude and the fourth-largest gas reserves in the world. The company runs a vast network of pipelines transporting oil, gas and refined products to processing plants, refineries, export terminals and other customers all over the Kingdom of Saudi Arabia. Saudi Aramco maintains its commitment to supply gas to the continuously growing local markets by implementing latest technologies and state of the art engineering solutions.
Since 2009, and as a result of launching an Electromagnetic Acoustic Transducer (EMAT) In-Line Inspection (ILI) Program, Saudi Aramco has discovered Stress Corrosion Cracking (SCC) defects in a number of its pipelines. Saudi Aramco built on ASME B31.8S criteria for identifying SCC susceptible segments to prioritize its network to manage the utilization of the EMAT technology. The criteria were based on pipeline operating parameters, environment, age and condition. An Extensive Field Verification program was put in action that illustrated the capabilities of the EMAT ILI tools. (Saudi Aramco’s ILI program included a few additional runs of Ultrasound Crack Detection Tool, UTCD, as well).
This paper discusses in more detail how the Study Team enhanced the ASME B31.8S prioritization criteria and the major findings and highlights realized from this activity. A statistical evaluation of the data compiled in the 1st phase of the comprehensive study was conducted along with the literature review. The Study Team used logistic regressions[1,2] to identify factors that increase or decrease the likelihood that cracking is present. The trends that were identified relate to coating type, pipe grade, pipeline age, diameter, thickness, metal loss, cathodic protection (CP) level, slope, and pipe type. The Study Team used the findings to profile crack susceptibility in the pipelines found with SCC and for the Saudi Aramco pipeline network as a whole to identify pipelines susceptible to cracking to include in the future ILI runs.
Development of a Magnetic Eddy Current In-Line Inspection Tool
Authors: Asher Stefanie L. , Boenisch Andreas , Reber Konrad 
Published: November 2016

Pipeline in-line inspections (ILI) are one of the primary methods used to assess the integrity of operating oil and gas pipelines. Conventional ILI technology is based on ultrasonic testing (UT) or magnetic flux leakage (MFL) sensors. Although these technologies are suitable for most pipeline inspections, there remains an opportunity to expand ILI technology and application. ExxonMobil and Innospection Ltd. are working to develop a new ILI sensor technology based on a combination of Magnetic Eddy Current (MEC) and multi-differential eddy current. This new technology provides the potential to detect small volumetric features, inspect heavy wall gas pipelines, and inspect pipelines with corrosion resistant alloy (CRA) or non-metallic liners.
Initial feasibility trials were conducted with a prototype ILI MEC tool. Tests were conducted on an 8.625” (219 mm) X65 carbon steel pipe lined with 0.118” (3 mm) of Inconel 825 pipe. Four types of defects were machined into the pipe to represent natural defects anticipated in service:
• Metal loss features from 3 to 24 mm in diameter on the external surface of the carbon steel base pipe
• Erosion on the internal layer of the CRA liner
• Internal girth weld crack-like defects
• Metal loss defects at the interface of the CRA and carbon steel
Over 80 pull tests were conducted to determine the detection capabilities and speed sensitivities of the tool. Defects were detected by the sensors including the very small (<10 mm) pinhole-type features. Signals were analyzed by a preliminary sizing algorithm to demonstrate proof of concept. Detection performance was not affected at speeds up to 0.75 m/s. Since detection capabilities exceeded expectations, future development will continue based on the current prototype.
A New Approach to Pipeline Leak Detection Using Electromagnetic Sensing
Authors: Dawson Chris , Inkpen Stuart , Nolan Chris , Bonnell David 
Published: November 2016

Many different approaches have been adopted for identifying leaks in pipelines. Leak detection systems, however, generally suffer from a number of difficulties and limitations. For existing and new pipelines, these inevitably force significant trade-offs to be made between detection accuracy, operational range, responsiveness, deployment cost, system reliability, and overall effectiveness. Existing leak detection systems frequently rely on the measurement of secondary effects such as temperature changes, acoustic signatures or flow differences to infer the existence of a leak.
This paper presents an alternative approach to leak detection employing electromagnetic measurements of the material in the vicinity of the pipeline that can potentially overcome some of the difficulties encountered with existing approaches. This sensing technique makes direct measurements of the material near the pipeline resulting in reliable detection and minimal risk of false alarms. The technology has been used successfully in other industries to make critical measurements of materials under challenging circumstances. A number of prototype sensors were constructed using this technology and they were tested by an independent research laboratory. The test results show that sensors based on this technique exhibit a strong capability to detect oil, and to distinguish oil from water (a key challenge with in-situ sensors).
Evaluation of Back-Beveled and Counterbore-Tapered Joints in Energy Pipelines
Authors: Huo Xiaotong , Kenny Shawn , Hussein Amgad , Martens Michael 
Published: November 2016

Wall thickness transition joints are used to connect energy pipeline segments; such as straight pipe to fittings with different wall thicknesses. The transition joint may be subject to axial forces and bending moments that may result in a stress concentration across the transition weld and may exceed stress based design criteria. Current engineering practices, such as CSA Z662, ASME B31.4, and ASME B31.8, recommend the use of back-bevel transition welded connections. An alternative transition weld configuration is the counterbore-taper design that is intended to reduce the stress concentration across the transition.
In this study, the relative mechanical performance of these two transition design options (i.e., back-bevel and counterbore-taper) is examined with respect to the limiting burst pressure and effect of stress concentrations due to applied loads. The assessment is conducted through numerical parameter study using 3D continuum finite element methods. The numerical modelling procedures are developed using Abaqus/Standard. The performance of continuum brick elements (C3D8I, C3D8RH, C3D20R) and shell element (S4R) are evaluated. The continuum brick element (C3D8RI) was the most effective in terms of computational requirements and predictive qualities.
The burst pressure limits of the transition weld designs were evaluated through a parameter study examining the significance of pipe diameter to wall thickness ratio (D/t), wall thickness mismatch ratio (t2/t1), material Grade 415 and Grade 483 and end-cap boundary condition effects. The limit load analysis indicated the burst pressure was effectively the same for both transition weld designs. The effect of pipe diameter, D/t, t2/t1, and counterbore length on the stress concentration factor, for each transition weld design, was also assessed. The results demonstrate the improved performance of the counterbore-taper weld transition; relative to the back-bevel design as recommended by current practice, through the relative decrease in the stress concentration factor. The minimum counterbore length was found to be consistent with company recommended practices and related to the pipe diameter and wall thickness mismatch.