bluuebunny/crossref_metadata_2025_split huggingface dataset:
Manufacture and Qualification of Small Diameter / Thickwall Reelable DSAWL Linepipe
Authors: Hall Stephen , Connelly Martin , Alderton Graham , Hill Andrew , Wen Shuwen 
Published: November 2016

Tough market conditions have seen the price of oil drop which with the subsequent uncertainty surrounding the industry have seen the oil and gas industry concentrate on reducing the cost of designing, installing and operating pipelines. A critical process for the industry is the procurement, manufacture and installation of appropriate linepipe. The method of installation is often dictated by the pipe size and the water depth that the pipe is to be laid in, however there are times when the choice of lay method is due to vessel availability and relative costs for each technique.
In early 2014, Tata Steel successfully manufactured and delivered 16"OD × 0.875”WT X65 submerged arc welded longitudinal (SAWL) linepipe for installation via the reel lay method. Notable features about this fact were the size, which represents the thickest 16” external diameter UOE pipe yet delivered by Tata Steel, and that this was to be the first UOE pipe to be installed by the reel lay method in the North Sea. The ability to manufacture small diameter thickwall linepipe was only possible due to recent operational developments including an established tooling programme and a fully validated Finite Element (FE) model of the UOE process, along with years of experience of integrating these tools into the manufacturing process.
This paper discusses the manufacturing challenges for small diameter thickwall linepipe, and how with the aid of modelling tools, innovative thinking and previous experience in supplying small diameter thickwall linepipe into two reel-installed projects, the pipe was manufactured and delivered with the properties shown to be compliant with DNV OS-F101 Supplementary Requirement P.
Full-Scale Stress Corrosion Crack Growth Testing of an X70 Spiral-Welded Pipe in Near-Neutral pH Soil Environment
Authors: Kang Jidong , Bibby Darren , Blanchard Romain , Zheng Wenyue 
Published: November 2016

Stress corrosion cracking (SCC) in near-neutral pH environment remains a major concern for high pressure pipelines transporting oil and gas in Canada since its first discovery in 1980s. A variety of laboratory experiments and models have been developed to address different aspects of this complex problem. Full-scale pipe SCC testing using soil box that mimics the condition in the field can directly assess crack growth in terms of pressure level, range of pressure fluctuation, soil conditions, etc. This type of test also offers the most direct validation of SCC models.
A state-of-the-art full-scale SCC pipe testing facility has been established at CanmetMATERIALS Hamilton Laboratory. The facility includes a new hydraulic power unit (HPU), an upgraded 500 kN fatigue frame, and a new 2000 psi (14MPa) pressurization system. In addition, a 24-channel direct current potential drop (DCPD) unit has been refurnished for in-situ monitoring of crack growth.
The full-scale pipe SCC testing facility has been successfully used to measure crack growth in an X-70 (Grade 483) large diameter (914 mm or 36” OD) spiral seam-welded pipe. Six axial cracks were made using saw cutting and fatigue pre-cracking in the base metal and across the spiral-weld metal. All cracks were buried under two types of soil boxes with soil obtained from a near-neutral pH SCC pipeline failure site mixed with distilled water or NS4 solution. The pH of the solution was maintained between 6.9 and 7.2 throughout the testing. Several loading conditions were tested and DCPD was used to monitor SCC growth rate during all the tests.
No detectable growth was observed in the cracks of weld area during all the tests mainly due to over-matching strength. Crack growth was also not detected for the base metal until the maximum pressure was raised up to 95% SMYS with R = 0.7. The threshold of the range of stress intensity factor, (ΔK)th for SCC is thus estimated to be between 11.53 to 13.52 MPa m1/2. The measured average crack growth rate was 5.98×10−7 mm/s.
Analysis of a Dense Phase Carbon Dioxide Full-Scale Fracture Propagation Test in 24 Inch Diameter Pipe
Authors: Cosham Andrew , Jones David G. , Armstrong Keith , Allason Daniel , Barnett Julian 
Published: November 2016

A third full-scale fracture propagation test has been conducted using a dense phase carbon dioxide (CO2)-rich mixture (approximately 10 mole percent of non-condensables), at the DNV GL Spadeadam Test & Research Centre, Cumbria, UK, on behalf of National Grid, UK.
The first and second tests, in 914 mm (36 inch) outside diameter pipe, also conducted at the Spadeadam Test & Research Centre, showed that predictions made using the Two Curve Model and the (notionally conservative) Wilkowski et al., 1977 correction factor were incorrect and non-conservative. An additional correction was required in order to conservatively predict the results of the two tests.
A third full-scale test was necessary to evaluate the fracture arrest capability of the line pipe for the proposed 610 mm (24 inch) outside diameter Yorkshire and Humber CCS Cross-Country Pipeline, because the predictions of the first and second tests were non-conservative, and it was unclear if and how the results of these tests could be extrapolated to a different diameter and wall thickness.
The third test was designed to be representative of the proposed cross-country pipeline, both in terms of the grade and geometry of the pipe, and the operating conditions.
The test section consisted of seven lengths of pipe: an initiation pipe and then, on either side of the initiation pipe, one transition pipe and two production pipes. The (in total) four production pipes are representative of the type of line pipe that would be used in the proposed cross-country pipeline.
A running ductile fracture was successfully initiated; it propagated through the transition pipes on both sides, and then rapidly arrested in the production pipes. The result of the test demonstrates that a running ductile fracture would arrest in the proposed Yorkshire and Humber CCS Cross-Country Pipeline.
The main experimental data, including the layout of the test section, and the decompression and timing wire data, are summarised and discussed.
Furthermore, the implications of the three tests, in two different pipe geometries, for setting toughness requirements for pipelines transporting CO2-rich mixtures in the dense phase are considered.
Leak Detection and Operations Management in Offshore Pipelines
Authors: Zhang Jun , Kane Adrian 
Published: November 2016

This paper will demonstrate that with limited instruments at the terminals and platforms only, it is feasible to monitor the integrity of offshore pipelines effectively. Some examples of applications will be shown, including both crude oil and natural gas pipelines.
The statistical volume balance technology based on flow and pressure measurements at the inlets and outlets only provides the detection and location of leaks. The paper describes the performance of these leak detection systems for incidents ranging from small leaks to pipeline rupture.
To help operators run pipelines safely and cost effectively, real-time transient models are used to calculate the flow, pressure, temperature, density and other fluid properties along the pipeline. Instead of using measured flow and pressure, the operators rely on these calculated values to take operational decisions. The combination of hydraulic modelling and statistical leak detection provides the operators with the information and confidence in the integrity of their pipelines. In the event of any incident the operators can take actions quickly and correctly to minimize the consequences.
Development and Implementation of a Risk Based Prioritization Methodology for MAOP Reconfirmation of Gas Transmission Facilities
Authors: Sloterdijk Wytze , Hommes Martin , Coster Roelof , Rovella Troy , Herbison Sarah 
Published: November 2016

As part of Pacific Gas and Electric Company’s (PG&E) on-going commitment to public safety, the company has begun a comprehensive engineering validation of its gas transmission facilities that will ultimately support the reconfirmation of maximum allowable operating pressure (MAOP) for these assets.
In addition to 6,750 miles of line pipe, PG&E’s gas transmission system contains over 500 station facilities. Since this set of facilities is not only large but diverse, and the validation effort for these facilities is expected to be an extensive, multi-year process, a methodology for the prioritization of the facilities needed to be developed to facilitate planning of the process for the efficient mitigation of risk. As a result, DNV GL was retained to develop and implement a risk-based prioritization methodology to prioritize PG&E’s gas transmission facilities for the engineering validation and MAOP reconfirmation effort. Ultimately, a weighted multiple criteria decision analysis (MCDA) approach was selected and implemented to generate the prioritization.
This MCDA approach consisted of the selection of relevant criteria (threats) and the weighting of these criteria according to their relative significance to PG&E’s facilities. Relevant criteria selected for inclusion in the analysis include factors that are important in order to assess both the short- and long-term integrity of the facility as a whole as well as the integrity of features for which design records cannot be located. The criteria selected encompass stable threats, time-dependent threats, as well as environmental impact. Enormous amounts of data related to design, operations, maintenance history and meteorological and seismic activity in addition to other environmental data were evaluated with this newly developed methodology to assess the relative risks of the facilities. Pilot field visits were performed to validate the selection of the various criteria and to confirm the outcome of the analysis.
The novelty of this approach lies in the prioritization of facilities in a coherent risk-based manner. The described approach can be used by operators of oil and gas facilities, either upstream, midstream or downstream.
Development of Key Performance Indicator for Management of Under Deposit Corrosion (UDC)
Authors: Garcia Alfonso , Place Trevor , Wood Stephen 
Published: November 2016

Hydrocarbons transported in transmission pipelines contain solid particles with micro-attached water. Subjected to flow conditions, these particles may have sufficient density to reach the pipe floor and enable bacteria growth and local Under-Deposit Corrosion (UDC), with this form of corrosion being one of the principal threats to the integrity of oil and gas transmission pipelines. NACE International has published a variety of UDC related standard practices to manage corrosion in the oil industry such NACE 61114, but few of them are representative of, or applicable to, low water cut hydrocarbon transmission pipelines. Further, there are presently no industry recognized key performance indicators (KPIs) suitable for managing UDC in low water cut hydrocarbon transmission pipelines.
Enbridge (the “Company”) operates North America’s largest interconnected liquid hydrocarbon transmission pipeline network. For the purposes of this paper, when the word ‘transmission’ is used to modify ‘crude oil’, ‘hydrocarbons’, or ‘pipelines’, it implies medium to long distance transport (100’s to 1000’s of km) as well as clean, “refinery-ready” crude oil (oil containing less than 0.5% sediment and water). This quality of oil renders it generally non-corrosive at pipeline operating conditions. However, if water wet particulates accumulate on the pipe floor, it can lead to UDC. The Company collects sludge samples produced during pigging operations on a regular basis to establish the composition of these materials and quantify bacterial population/activity. These solids represent an amalgamation of material removed from the pipe floor, and thus can be used as an indicator of the UDC threat in the pipeline. This paper builds upon previous work of the Company [1] by considering a larger data set in order to generate a more meaningful assessment of bacteria population/activity and provide better correlations with crystalline compounds, water content and elements found in the sludge.
This paper presents these data and associated statistical analysis, and proposes KPIs for evaluating the UDC threat based on numerous variables, including in-line inspection Magnetic Flux Leak (MFL) data (through signal to signal corrosion growth rates), sludge analysis, flow conditions and pipeline operation; this paper also suggests mitigation activities and intervals relative to these KPIs.
Personnel involved in pipeline integrity management (e.g. field operations, technical and management staff) may find the concepts, strategies and correlations presented herein to be useful in developing their own UDC management programs.
Analysis of Pressure Test Failure Performance for Vintage Pipe
Authors: Chen Jenny Jing , Williams Dan , Leewis Keith , Aguiar David 
Published: November 2016

Systemic manufacturing defects in select vintage pipe pose challenges when assessing the integrity of pipeline systems comprised of such pipe. The common manufacturing technology and quality control practices in place at the time of manufacturing left some vintage line pipe prone to imperfections which could remain even after passing pressure tests in the mill or after construction. The lack of complete and reliable manufacturing records for some vintage line pipe limits granularity and adds integrity assessment uncertainties.
Up until 1984, the United States Department of Transportation (USDOT) Pipeline and Hazardous Materials Safety Administration (PHMSA) required operators to report incidents related to failed pressure tests for all pipelines at the time of installation. Performance with respect to the manufacturer and year of manufacture can therefore be extracted from these reported incidents. These performance records are essential when re-establishing the MAOP (or MOP) and confirming the fitness for service of older pipelines. The pressure test failure performance in the early incident records provides insight into pipeline integrity prioritization and mitigation activities for managing pipeline safety based on pipe manufacturer, production date and seam type.
Identification of Repair Coatings on Pipelines Using In-Line Inspection Technologies
Authors: Greig Andrew , Grillenberger Jörg 
Published: November 2016

One of the major issues in the pipeline industry is coating disbondment. A very large percentage of external corrosion and SCC is observed under disbonded coatings that shield Cathodic Protection (CP). This has been an ongoing issue with coated and cathodic protected pipelines since the initial use of these two protection methods. The various coating types and their typical failure scenarios, under various harsh environmental conditions, as well as their compatibility with cathodic protection when disbondment occurs, play a major role for recoating programs and selection of the coating type used for repairs and re-coating programs.
With the continued development and improvements of the “Electro-Magnetic Acoustic Transducer” (EMAT) in line inspection technology it is possible to locate disbonded coatings, without the need of exposing the pipeline. This way operators can assess the condition of the coatings applied to their pipeline systems at a comparable low cost. Inline inspection tools equipped with the “EMAT” technology are also capable of identifying the various coating types and coating conditions.1 The coating type identification process is not limited to coating types applied to whole joints. Field applied coatings covering the girth weld area or coating changes within a joint such as repairs can be identified as well. In the presented case study, the challenge was the identification of different coating types used as repairs or for re-coating procedures, within the 60 year history of the inspected pipeline system. At the beginning of the project the main coating types and obvious repairs were identified based on EMAT in line inspection data. In a combined effort, operator and in line inspection vendor compared the initially identified coating types with the known repair history of this pipeline system. Based on this shared combined information the coating type analysis could be finetuned and additional areas could be identified as repaired or re-coated.
The paper will outline different coating repair methods described by the operator and subsequently identified by the EMAT tool. This paper will also describe for each coating repair method the associated risks for the pipeline integrity.
Backfilling Onshore Abandoned Pipelines With Paste
Authors: Longo Sue , Cull Joshua 
Published: November 2016

According to the 2015 AER database there are approximately 473,000 km of high pressure pipelines in Alberta alone, ∼93,000 km of which have been discontinued. Of these 93,000 km of discontinued lines approximately half have been abandoned. When a pipeline is abandoned it is typically flushed out, marked and has all corrosion protection and monitoring systems removed.
In the absence of corrosion protection all pipelines will inevitably corrode. This can create long term issues for abandoned pipelines. Two of the critical issues are potential ground subsidence and the creation of unintended water conduits. Ground subsidence is caused when an abandoned pipeline corrodes to the point of allowing the surrounding soil to fall into the empty pipe. Ground stability issues can result depending on the size and depth of the pipeline. Stability issues can appear suddenly in the form of sinkholes, slow slumping troughs or cracks in the earth and anything in between. Regarding unintended water conduits the main concern centres on a pipeline under or near water crossings or in areas of saturated soil. The pipeline corrosion can eventually provide a mechanism for water (or other constituents) to enter and migrate through the empty pipe and then be discharged further down the line. This uncontrolled migration can potentially have environmental impacts depending on what gets transported and where it ends up being discharged.
One common industry method to protect abandoned lines from the issues described above is to backfill them with foam or grout. Backfilling areas of abandoned lines can help protect against ground instability and subsidence as the line corrodes away. Creating plugs or cutting/capping abandoned pipelines can protect against the possibility of water conduits. The use of paste technology is not common to the industry in this regard however it can provide many benefits over current foams and grouts. This paper will discuss paste technology and it use as a backfill option for pipeline abandonment.
Modeling Conflicts and Batch Quality Impacts in Pipeline and Crude Oil Storage Terminal
Authors: Juergensen Birgit , Ewanicke Ivan , Xi Thomas 
Published: November 2016

The problem of identifying and forecasting potential scheduling conflicts and the impact to quality and delivery targets is a very real and complex problem. The most effective way to meet the above business objective is to develop a terminal simulation model that combines elements of a mass balance system (MBS), operational rules/procedures and operator behavioral patterns.
This paper is a case study describing the approach in designing a detailed pipeline tank terminal simulation model with an objective to identify and quantify complex and possibly unresolvable operating conflicts/events occurring given a current pipeline, tank or terminal configuration and then comparing this with other configuration options. In addition, the model will be able to measure quality impacts (measured by quantifying the volume of degraded product) that results from resolving the operating conflicts for each evaluated configuration.
We will demonstrate how the resultant model allows a terminal operator to effectively understand quality impacts to batches delivered through the pipeline tank terminal as a function of operational procedures and system configuration changes.
Determination of Brittle-to-Ductile Transition Temperatures of Large-Diameter TMCP Linepipe Steel With High Charpy Energy by Use of Modified West Jefferson Testing
Authors: Hioe Y. , Wilkowski G. , Fishman M. , Myers M. 
Published: November 2016

In this paper the results will be presented for burst tests from a Joint Industry Project (JIP) on “Validation of Drop Weight Tear Test (DWTT) Methods for Brittle Fracture Control in Modern Line-Pipe Steels by Burst Testing”. The JIP members for this project were: JFE Steel as founding member, ArcelorMittal, CNPC, Dillinger, NSSMC, POSCO, Tenaris, and Tokyo Gas.
Two modified West Jefferson (partial gas) pipe burst tests were conducted to assess the brittle-to-ductile transition temperature and brittle fracture arrestability of two 48-inch diameter by 24.6-mm thick X65 TMCP line-pipe steels. These steels had very high Charpy energy (350J and 400J) which is typical of many modern line-pipe steels. In standard pressed-notch DWTT specimen tests, these materials exhibited abnormal fracture appearance (ductile fracture from the pressed notch prior to brittle fracture starting) that occurs with many high Charpy energy steels. Such behavior makes the transition temperature difficult to determine.
The shear area values versus temperature results for these two burst tests compared to various modified DWTT specimens are shown. Different rating methodologies; DNV, API, and a Best-Estimate of steady-state fracture propagation appearance were evaluated.
The Use of Hydrotesting and EMAT Inline Inspection Technology for the Integrity Management of Stress Corrosion Cracking (SCC) in Gas Pipelines
Authors: Hryciuk Pedro M. , Carzoglio Eduardo , Minellono Jose A. , Martinetto Leonardo , Guillen Pedro M. , Grillenberger Joerg 
Published: November 2016

This paper describes the activities and stages completed as part of the Integrity Management Program for SCC in the natural gas system of Transportadora de Gas del Norte (TGN-Argentina) which started in 2000. This document focuses in a pipeline section of the system, which suffered an in-service failure in 2002 due to high pH SCC.
This event triggered a series of activities, whose results are detailed in this paper. These activities involved soil analysis to determine the susceptibility to develop SCC along the system pipelines. For susceptible sections, the program included hydrostatic testing to levels of 100% and 110% of SMYS followed by replacement of degraded coating.
The paper also details the experience in the use of new internal inspection tools with EMAT technology. The capability of the EMAT tool to detect and size SCC defects and the possibility of discriminating between SCC colonies that have been recoated and those that may still be active due to degraded coating is discussed. Finally, the severity of SCC cracks detected by in-line inspection is assessed using API 579 methodology, and the feasibility of using this assessment results to determine the critical SCC defect sizes for detection by ILI tools is analyzed.