bluuebunny/crossref_metadata_2025 huggingface dataset:
Innovations Into Minimizing Interfacial Contamination Between Crude Batches due to Dead-Legs in Pump Station Piping Layouts
Authors: Botros K. K. , Clavelle E. J. , Vogt G. M.
Published: November 2016

Invariably, oil pump station piping layouts may contain multiple dead-legs brought about by closed valves at one end of side branches, while flows continue through the main runs. During the transportation of heavy crude through the pump station, these dead-legs will be filled with this crude. When a light crude batch is introduced next into the pipeline, following the heavy crude ahead, two phenomena will occur. First, contamination between batches at the interface of the two crudes will occur due to axial turbulent diffusion along the length of the pipeline itself. Second, as the light crude flows through the pump station, and passes by each dead-leg containing residual heavy crude from the preceding batch, the heavy crude trapped in these dead-legs will start to drain out into the passing light crude in the main run. This causes further contamination and spreading of the mixing zone between the two batches. The second source of contamination, which is addressed in this paper, could cause appreciable contamination particularly for large dead-leg sizes and numbers. A computational fluid dynamics (CFD) model has been developed to quantify the drainage rate of the contaminating crude into the main stream and its impact on widening the mixed zone (contamination spread) between the two batches. Two drainage mechanisms of the heavy crude in the dead-legs into the main stream of the light crude have been identified and quantified. Finally, potential innovations to mitigate contamination due to dead legs are presented and quantified for their respective effectiveness in minimizing the contamination spreads between batches of different crudes.
Microstructure Engineering of Thicker Gage Niobium Microalloyed Line Pipe Steel With Enhanced Toughness by High Temperature Processing Using TiN-NbC Composite Precipitate
Authors: Subramanian S. V. , Ma Xiaoping , Miao Chengliang , Zhang Xiaobing , Collins Laurie
Published: November 2016

Prediction of crack arrestability of higher grade line pipe steel microalloyed with niobium in full scale burst tests based on laboratory simulation tests including Charpy impact, DWTT and CTOD is rendered difficult, as the full scale burst test is found to be far more sensitive to microstructure variables than current laboratory tests. This paper deals with nano-scale TiN-NbC composite precipitate engineering as an alternative approach to strain-induced precipitation of NbC to produce thicker gage plate or coil with enhanced toughness and resistance to ductile fracture propagation of line pipe steel. Microstructure engineering is based on identification of key microstructural parameters to which target properties can be related, and engineer the target microstructure through design of base chemistry and optimization of processing schedules. Nano-scale precipitate engineering based on control of spacing and size of TiN-NbC composite precipitate offers a new approach to achieve excellent strength and toughness (300J at −60C) of line pipe steels through control of target microstructure consisting of: (i) refinement of austenite grain size (under 30 microns) of transfer bar before pancaking, (ii) high volume fraction of acicular ferrite with adequate plasticity to increase resistance to ductile fracture propagation, (iii) high density and uniform dispersion of high angle grain boundaries that arrest micro-cracks to suppress brittle fracture initiation, (iv) less intensity of unfavorable {100}<011> texture component that facilitate the propagation of brittle fracture, (v) suppression of ultra-fine precipitates in the matrix, thereby enlarging plastic zone ahead of the crack tip to blunt the tip of the crack, and (vi) suppression of coarse brittle constituents (carbides or MA products) that initiate brittle fracture. Experimental results are presented on thermo-mechanically rolled X-90 and K-60 that validate the concept of microstructure engineering using TiN-NbC composite precipitate engineering to enhance strength and fracture toughness.
Numerical Simulations of Burst of Corroded Pipes With Thermally Induced Compressive Axial Strain
Authors: Cunha Sérgio B. , Pacheco Mauricio , da Silva Amanda B.
Published: November 2016

Some onshore pipelines conduct fluids that are too viscous to be conducted at ambient temperature; they must be heated to enable efficient pumping and flow. These pipelines present a failure rate that is many times larger than those that operate at ambient temperature. The prevailing failure mode for these pipelines is external corrosion: the external thermal insulating coating can give rise to a very severe corrosion process.

Although corrosion is a significant threat for pipelines that operate with heated fluids, the available corrosion assessment methodologies might not be appropriate for this situation. Several studies have been conducted considering a pipeline with a corrosion flaw with axial stress (or load) plus pressure. But a heated pipeline with axial restraint — as caused by the soil friction in a buried pipeline — imparts a compressive axial strain, not a stress. Although in the elastic regimen the thermally induced axial strain generates significant axial stress, it can be expected some level of decrease in the axial stress after yielding, due to the large reduction in the material stiffness and the increase in Poison’s ratio. Since localized yield in the flaws is allowed in the assessment of a corrosion flaw, it seems too conservative to use the elastic axial stress in this assessment.

In this article a numerical study of the effects of the temperature in the burst pressure of a pipeline with axial restraint and thermal expansion is presented. Finite element simulations were conducted using actual tensile test curves for two pipeline steel grades, API 5L Gr B and X70. The boundary conditions assumed axial restraint with free radial displacement. The loading comprised an initial heat of the pipe’s material and, afterwards, gradual increase of the pressure until burst, assumed to occur by plastic instability. Two diameter to thickness ratio and several flaw geometries were studied.

Initially, the effect of the temperature was evaluated for pipes without defect. Afterwards, numerical simulations of the burst of pipe sections with volumetric flaws of various depth and length were conducted. For both the cases of pipes with and without defect, the simulations were carried out comparing the cases of heated and not heated pipes.

It was found that although the thermal effect causes a large compressive axial stress in the elastic regimen, this stress is almost completely relaxed after yielding. No effect of the temperature in the burst pressure was observed in the numerical simulations.
Applying Corrosion Growth Rates Derived From Repeat ILI Runs to Predict Future Severity
Authors: Dawson Jane , Ganim Lautaro
Published: November 2016

Corrosion is still one of the major threats to the integrity of onshore and offshore pipelines. Realistic corrosion growth rates are essential inputs to safe and effective pipeline integrity management decisions. For example, corrosion rates are needed to predict pipeline reliability as a function of time, to identify the need for and timing of field investigations and/or repairs and to determine optimum re-inspection intervals to name just a few applications. The consequences associated with using wrong corrosion growth rates range from the inefficient use of resources (time, people and money) on unnecessary repairs and/or inspections to unexpected pipeline releases. The identification of where corrosion is active on a pipeline and how fast it is growing is a complex process which is understood in the general sense but is highly variable. Corrosion is therefore difficult to predict due to the very localised nature of its behaviour and the many parameters that influence the corrosion reaction.

Running an in-line inspection (ILI) tool in a pipeline identifies the internal and/or external corrosion located along the full length of the pipeline. The ILI inspection also determines the depth, length and width measurements for each corrosion site and for the overall feature. The use of repeat ILI data to match and compare metal loss sites in order to estimate the corrosion growth rates at individual defects along a pipeline is a well-used and established practice in the industry. The use of such corrosion rates to make predictions of the future integrity of a pipeline started in earnest approximately 5 to 10 years ago and over that time considerable experience has been gained. Now that we are starting to collect 3, 4 or even 5 or more ILI data sets for the same pipelines we are able to test and validate our earlier ILI based growth rate predictions versus what actually occurred in the pipeline over time. With the benefit of this hindsight, the methodologies employed for evaluating and applying ILI based corrosion rates can be further improved and refined to give more accurate predictions of the future pipeline condition, the response schedule and for setting the timing of re-inspections.

This paper shares the experience gained and the improvements that can be made to the determination of corrosion rates and application of these rates in a pipeline integrity assessment. These topics are illustrated and investigated via the use of case studies on real ILI data sets.
Circumferential Crack Detection: Challenges, Solutions, and Results
Authors: Brimacombe Mark , Hennig Thomas , Wargacky Cory
Published: November 2016

Within the last decade, axial cracking became a significant and well-known threat to pipeline systems. The defects are commonly in/at the longitudinal welds or in combination with external corrosion/coating disbondment (SCC). Inline Inspection (ILI) service providers developed inspection technologies for liquid and gas lines that are now utilized regularly. In comparison to axial cracking, circumferential cracking does not yet show a significant role in pipeline integrity. Nevertheless, pipeline operators observe these defects, often in combination with circumferential welds and/or local stress/strain accumulation. Such features are often caused by soil movement, which may occur more readily in mountainous areas.

Over the course of the 2014/2015 calendar years, NDT Global inspected 12” pipeline segments for circumferentially oriented crack-like indications. The pipeline segments totaled 814 km in length and transported light crude oil. The 6 pipeline segments range in length from 61 km to 251 km each. The pipelines were considered to be susceptible to axial stresses (both in the base material as well in the girth welds) due to slope subsidence and outside forces acting on the pipe. In previous integrity digs, circumferential crack-like indications were found in conjunction with slope movement and these segments needed to be further investigated.

This paper provides information on the challenges solved during the course of the project. Lessons learned from previously inspected sections have been applied to future inspections. The authors will provide information on the inspection campaign, a discussion regarding field verification findings and ILI results, and project conclusions.
The Effect of Spiral Cold-Bending Manufacturing Process on Pipeline Mechanical Behavior
Authors: Chatzopoulou Giannoula , Sarvanis Gregory C. , Papadaki Chrysanthi I. , Karamanos Spyros A.
Published: November 2016

Large-diameter spiral-welded pipes are employed in demanding hydrocarbon pipeline applications, which require an efficient strain-based design framework. In the course of a large European project, numerical simulations on spiral-welded pipes are conducted to examine their bending deformation capacity in the presence of internal pressure referring to geohazard actions, as well as their capacity under external pressure for offshore applications in moderate deep water. Numerical models that simulate the manufacturing process (decoiling and spiral cold bending) are employed. Subsequently, the residual stresses due to cold bending are used to examine the capacity of pipe under external pressure and internally-pressurized bending. A parametric analysis is conducted to examine the effect of spiral cold forming process on the structural behavior of spiral welded pipes and the effect of internal pressure on bending capacity. The results from the present study support the argument that spiral-welded pipes can be used in demanding onshore and offshore pipeline applications.
Region-Specified Ratcheting Behavior of API X80 Welded Joint Under Uniaxial Cyclic Loading
Authors: Lu Hongsheng , Yang Yonghe , Chen Gang , Chen Xu , Wang Xin
Published: November 2016

Evaluation of mechanical performance of different regions can be difficult by using standard size samples due to the size limitation of weld metal and heat-affected zone (HAZ). At first, the microstructure of different regions was characterized and quantified by Scanning Electron Microscope, which indicate that the pipeline steel is a typical acicular ferrite steel. In this study the deformation behavior of different regions (base metal, weld metal and heat affected zone) in a welded joint of API X80 pipeline steel were studied by conducting uniaxial loading tests on miniature specimens with the cross section of 2×0.5mm and gauge length of 9mm. From the results of uniaxial tension in base metal and weld metal it is shown that the welding is overmatching. Compared to the base metal, the coarse grained HAZ exhibits a lower strength, while the fine grained HAZ exhibits a higher strength. Under near zero-to-tension cyclic stress loading, all regions of the welded joints exhibit progressive accumulation of plastic strain. Under the same stress level, the base metal shows the fastest ratcheting strain accumulation, which is the result of lower strength than other regions. This fact may indicate that the ratcheting behavior of the overall welded joint is highly dependence on that of base metal for the present case. But when under the same normalized stress level (σ = σ/σYS), the fine grained HAZ has the highest ratcheting strain accumulation, while the coarse grained HAZ has the lowest ratcheting strain accumulation, which reveals that the intrinsic resistance to ratcheting is yield strength dependent.
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.
Integrating Geophysical and Geotechnical Engineering Methods for Assessment of Pipeline Geohazards
Authors: McClymont Alastair , Ernst Erin , Bauman Paul , Payne Nicholas
Published: November 2016

Because pipelines can cover extensive distances through diverse terrain, they are subject to various geohazards, including slope failure and earthquake damage, which can have costly environmental and monetary impacts over their designed operational lifetime. Here, we show how geophysical investigative techniques can be used to complement other geotechnical investigation methods to provide a detailed understanding of site geology to best inform geohazard assessments. We pay particular attention to how multiple geophysical methods can be used to obtain spatially continuous measurements of subsurface physical properties, and layer and structural geometries. The geophysical data can then be used to either interpolate or extrapolate geotechnical engineering properties between and away from boreholes and excavations, or optimize the locations of subsequent boreholes or excavations. To demonstrate the utility of our integrated approach of incorporating geophysical methods to geohazard assessments, two case studies are presented. The first case study shows how electrical resistivity tomography (ERT), seismic refraction tomography (SRT) and multichannel analysis of surface wave (MASW) datasets are used to constrain the thickness and extent of potentially sensitive glaciomarine clay layers that are subject to slope instability and structural failure along a proposed pipeline route near Kitimat, British Columbia (BC). A second case study describes how high-resolution ground-penetrating radar (GPR) and seismic reflection surveys are used to locate and characterize fault strands that may cause future ground deformation at a proposed pipeline crossing of the Tintina/Rocky Mountain Trench fault in northeastern BC.
Apparatus for Testing Drag Reducing Agents in Gas Transmission Pipelines
Authors: Chen Jianlei , Zhao Wei , Di Yan , Jia Banglong , Wang Jianbo , Li Hao
Published: November 2016

Drag reduction agents (DRA) with its special properties adhering to the inner wall of gas pipeline can reduce the pipe surface roughness and turbulent velocity of gas flow. Injecting DRA into the natural gas pipeline is a potential and economical method which decreases the energy consumption and enhances gas delivery throughput. The premise that DRA can be used on site is to pass the performance test in laboratory, so reasonable DRA test system are designed through simulating the operation conditions of natural gas transmission pipelines. Emphatically improving the pumping system, atomization injection system and test pipe section. The pumping system adopts separation design pattern which can avoid various DRA samples blending drastically. The atomization injection system provides full atomized space for DRA solution which can ensure atomization injection process to carry out ideally. The test pipe section can replace quickly and ensure a higher measuring accuracy. The proposed approach above can perfect the test system for DRA used in gas transmission pipeline and can provide important guidance to the industrialized application of DRA.
Optimized Methods of Recording Pipeline Pressure Fluctuations for Pipeline Integrity Analysis
Authors: Zhao Jiaxi , Chevil Karina , Chen Weixing , Been Jenny , Keane Sean
Published: November 2016

A crack growth and remaining life predictive software Pipe-OnLine has recently been developed to predict crack growth of pipeline steels in near neutral pH environments. Pressure fluctuations from Supervisory Control and Data Acquisition (SCADA) data are utilized as inputs for crack growth calculations. The accuracy of crack growth predictions largely depends on whether the SCADA data have captured all crack-growth contributing events of pressure fluctuations during pipeline operation. This investigation is aimed at 1) to analyse typical characteristics of pressure fluctuations during oil and gas pipeline operations, 2) to model various pressure data recording scenarios in terms of capturing crack growth contributing pressure fluctuation events, and 3) to provide optimized methods for recording pressure data for the purpose of making crack growth and remaining service life predictions. One of the methods being developed requires to take maximum and minimum pressure points within a given sampling interval). By adopting this method, oil pipeline pressures could be recorded at a max time interval of 1 minute, while gas pipeline pressures could be recorded at a time interval up to 2 hours without reducing the accuracy of prediction. This could substantially reduce the size of data storage and shorten the time of data-analysis for life prediction.
Effects of Segregation on the Mechanical Performance of X70 Line Pipe
Authors: Collins L. E. , Wei P. , Nafisi S. , Wang P. , Wiskel J. B.
Published: November 2016

Elemental segregation during continuous casting of steel is an inherent part of the solidification process. After rolling, the segregation is evident through banding of the microstructure, particularly at the centerline where the enrichment of such elements as carbon, manganese, molybdenum and chromium, may locally increase the hardenability of the steel and result in the formation of harder microstructural features. While operational steps may be taken to minimize segregation during casting, complete elimination of segregation is almost impossible. Various slab rating systems have been defined over the years which are employed as a means to measure slab quality taking into account such factors as internal cracks and segregation. While these slab rating systems were intended to aid mill operators in assessing slab quality, in recent years slab ratings have been prescribed as a means of assessing pipe quality. In this study the properties of pipe produced from a slab with Mannesmann rating of 2 are compared to those of pipe produced from a slab with a rating of 3. The work has been supplemented by microprobe analyses to measure the degree of segregation. Increased levels of Mn and Si were found at the centerline of pipe processed from the Mannesmann 3 slab. In the final pipe, these centerline bands were 10 to 20 μm in thickness and exhibited increased hardness (HV 50g) in the Mannesmann 3 pipe as compared to the Mannesmann 2 pipe. Despite evidence of increased segregation, the mechanical properties (YS, UTS, Charpy, DWTT) of both pipes comfortably met X70 property requirements.
Effect of Weld Thermal Cycles on Microstructure and Properties of Simulated Heat Affected Zone in Thick-Wall X80 Pipe Steels
Authors: Gianetto J. A. , Fazeli F. , Shalchi-Amirkhiz B. , Li J.
Published: November 2016

Continuous cooling transformation behaviour of the single cycled grain coarsened heat affected zones (GCHAZs) produced with a peak temperature (Tp) = 1350°C and cooling times, Δt800-500 = ∼ 1 to 100 s was evaluated for three different X80 pipe steels having various content of C, Mn, Ni, Cr, Mo and microalloying elements that include Nb, V and Ti. Optical microscopy was initially used to characterize the simulated GCHAZ, which consisted of a range of coarse prior austenite grains that transformed to different fractions of mainly low carbon lath martensite/fine bainite, mixtures of upper bainite and/or granular bainite as a function of increasing cooling time. A consistent trend of decreasing microhardness with increasing cooling time occurred for the range of GCHAZs formed in the pipe steels. The significant differences in GCHAZ microhardness for Δt800-500 < 15 s is attributable to the respective pipe steel compositions and the resulting microstructures. The GCHAZ microstructures were further characterized by means of scanning electron microscopy with electron backscattered diffraction and transmission electron microscopy with focus to analyze features of the transformation products, fraction of high angle boundaries and the nature of microconstituents, including carbonitride precipitates and inclusions. The simulated GCHAZ Charpy-V-notch impact energy transition curves revealed a consistent upward shift towards higher temperatures with increasing cooling time (Δt800-500 = 6, 15 and 30 s). The primary factors contributing to the variations in impact toughness of the respective GCHAZs were the differences in the microstructure, hardness and detailed features, including fraction of high angle boundaries (packet size), and the presence of various M-A microconstituents.
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.
Pipeline In-Line Inspection Enhancement Opportunities
Authors: Asher Stefanie L. , Crapps Justin M.
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. These inspections can be complicated to conduct due to a variety of reasons ranging from operational limits (high/low flow velocity, wall thickness, pipeline extreme depth or pressure, etc.) to limits inherent to the inspection technology. Often these complexities are overcome with tools customized to a specific pipeline. Although this has been effective for singular pipeline inspections, a more industry-wide approach should be considered to develop broader solutions. This paper discusses the opportunities to enhance ILI and suggests a ranking of priorities for technology development.
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.