bluuebunny/crossref_metadata_2025_split huggingface dataset:
Benchmarking Pipeline Risk Assessment Processes
Authors: Tuft Peter , Yoosef-Ghodsi Nader , Bertram John 
Published: July 2013

The Australian pipeline design code AS 2885 is largely a risk-based standard, and its safety management study process is admirably suited to the needs of the Australian industry. However it is a unique process that has been developed in Australia and is not used anywhere else in the world. Successfully benchmarking it against other risk assessment methodologies would put the basis of the Australian approach on a footing that would be more difficult to challenge should a major pipeline disaster result in a public enquiry. And if the comparison reveals shortcomings in the AS 2885 process then there will be a sound basis for addressing those shortcomings to improve the process.
The APIA Research and Standards Committee and the Energy Pipelines CRC commissioned studies to compare the AS 2885 SMS process against two alternative methods:
• Reliability-based analysis.
• Quantitative risk assessment based on historical failure rates.
Each study looked at the same four pipeline segments spanning a variety of urban locations in which the consequences of a major pipeline failure would be very serious. Each of the four segments had previously been through the AS 2885 safety management study process and found to present a level of risk that was borderline tolerable. The objective of the studies was to determine whether the alternative risk assessment methods also found a level of risk that was similarly borderline tolerable.
This paper will present the results of the comparison studies, showing that all three methods produce broadly similar outcomes for risks that are close to the borderline between tolerable and intolerable. This is a welcome endorsement of the AS 2885 SMS process and reinforces its validity as a method for assessing and managing pipeline safety.
A Uniform Risk Methodology for Transmission Pipelines Transporting Chemicals
Authors: Spoelstra Margreet B. , Laheij Gerald M. H. 
Published: July 2013

In 2011 the Dutch Ministry of Infrastructure and the Environment (I&M) introduced new legislation for pipelines transporting dangerous substances. This legislation applies to pipelines transporting natural gas and to pipelines transporting oil products and deals amongst other things with the consequences of (new) pipelines on spatial planning. Risk methodologies have been revised in order to reflect new understandings in risk scenarios, failure frequencies and consequences. In the Netherlands operators and responsible authorities are now required to use these methodologies in risk calculations.
A risk methodology for pipelines transporting chemicals (substances other than natural gas or oil products) has currently been developed. These pipelines have a total length of about 3,000 kilometer and 18 different chemicals such as ethylene, hydrogen, chlorine and carbon dioxide are involved. This paper describes the risk methodology for underground pipelines transporting chemicals, including modeling aspects and failure frequencies. The application of measures to reduce the risk and some case analysis results are presented as well.
Risk Assessment of Modern Pipelines
Authors: Mihell James N. , Rout Cameron 
Published: July 2013

Proponents of new pipeline projects are often asked by regulators to provide estimates of risk and reliability for their proposed pipeline. On existing pipelines, the availability of operating and assessment data is generally considered to be essential to the task of performing an accurate and defendable risk or reliability assessment. For proposed or new pipelines, the absence of these data presents a significant challenge to those performing the analysis. The reliance on industry incident data presents problems, since the vast majority of loss-of-containment incidents relate to older pipelines in which the design, routing criteria, material properties, material manufacturing processes, and early operating practices differ significantly from those that are characteristic of modern pipelines. As a consequence, much of the available failure incident data does not accurately reflect the threats or the magnitudes of the threats that are associated with modern pipelines. In order to address this problem, ‘adjustment factors’ are often applied against incident data to try to account for threat differences between the source data and the intended application. The selection of these adjustment factors can often be quite subjective, however, and open to judgment; therefore, they can be difficult to justify.
With the rapidly growing practice of regular in-line inspection (ILI) on transmission pipelines, an extensive repository of ILI data has been accumulated — much of it relating to modern pipelines. Through the judicious selection of source data, ILI data sets can be mined so that an analogue data set can be created that constitutes a reasonable representation of the attributes of reliability of a specific new pipeline of interest. Key reliability properties, such as tool error distribution, feature incidence rate, feature size distribution, and apparent feature growth rate distribution can be derived from such analogue data. By applying these reliability properties in an analysis along with known pipeline design and material properties and their associated distributions, and by taking consideration of planned inspection intervals, a reliability basis can be derived for estimating pipeline risk and reliability. Estimates of risk and reliability that are derived in this manner employ methodologies that are repeatable, defendable, transparent, and free of subjectivity.
This paper outlines an approach for completing risk and reliability estimates on new pipelines, and presents the results of some sample calculations. The reliability estimates illustrated are based on an approach whereby corrosion feature size and growth rates are obtained from analogue ILI datasets, and treated as random variables. In that regard, they constitute the probability of exceeding a limit state that represents an approximation of the condition for failure.
Research on Pricing Formulation Method for Long Distance Natural Gas Pipeline Network Transporting
Authors: Li Xiaoyu , Xu Qiang , Zhao Minghua , Qian Chengwen , Jin Jing , Xi Jingjun 
Published: July 2013

With the completion of the second line project of West-East Gas Transmission in 2011, the third line of West-East Gas Transmission will be started soon and the fourth line and the fifth line will be started in recent five years. China will form one of the largest natural gas pipeline network in the world. The gas supply mode will be changed from single gas source and single-pipeline supply to multi-source and multi-pipeline supply through regulation and coordination, which will impact on existing pricing mechanism and operation mode of Chinese natural gas industry violently. Depending on the development trend of natural gas pipeline network, the regionalization management mode of natural gas pipeline will be implemented gradually. Chinese natural gas industry also needs to develop a new-type market-oriented operation mode with clear interfaces between production, transportation, distribution and customers so as to facilitate the optimal allocation of resources.
By the customized scientific research of CNPC (China National Petroleum Corporation), combining with existing pricing mechanism of natural gas pipeline and economic characteristics of long-distance natural gas pipeline transportation in China, the paper studied the pricing mechanism problem of combined transportation of multi-source and mutli-pipeline gas supply in the regionalization management mechanism, presented the idea of pricing formulation method of two kinds of pipeline network transportation based on standard rates of pipeline transportation and service cost rules, formed pricing formulation system of natural gas pipeline transportation, introduced the design idea, structural construction, distribution method and key points of natural gas pipeline transportation in details, and demonstrated the methods by example calculation. The methods presented in the paper can meet the pricing requirements of natural gas pipeline network transportation, remedy the defect in existing price accounting mechanism, solve the problem that the income and expenses among different interest bodies are not balanced, and facilitate the rapid development of natural gas pipeline business.
The First L555 (X80) Pipeline in Japan
Authors: Matsuhiro Yoshiyuki , Oguchi Noritake , Kurumura Toshio , Hamada Masahiko , Takahashi Nobuaki , Shirahama Atsuhi 
Published: July 2013

The construction of the first L555(X80) pipeline in Japan was completed in autumn, 2011.In this paper, the overview of the design consideration of the line, technical points for linepipe material and for girth welds are presented.
In recent years the use of high strength linepipe has substantially reduced the cost of pipeline installation for the transportation of natural gas. The grades up to L555(X80) have been used worldwide and higher ones, L690(X100) and L830(X120), e.g., are being studied intensively. In the areas with possible ground movement, the active seismic regions, e.g., pipeline is designed to tolerate the anticipated deformation in longitudinal direction.
In Japan, where seismic events including liquefaction are not infrequent, the codes for pipeline are generally for the grades up to L450(X65). Tokyo Gas Co. had extensively investigated technical issues for L555(X80) in the region described above and performed many experiments including full-scale burst test, full-scale bending test, FE analysis on the girth weld, etc., when the company concluded the said grade as applicable and decided project-specific requirements for linepipe material and for girth weld.
Sumitomo Metals, in charge of pipe manufacturing, to fulfill these requirements, especially the requirement of round-house type stress-strain (S-S) curve to be maintained after being heated by coating operation, which is critical to avoid the concentration of longitudinal deformation, developed and applied specially designed chemical composition and optimized TMCP (Thermo-Machanical Control Process) and supplied linepipe (24″OD,14.5∼18.9mmWT) with sufficient quality. It had also developed and supplied induction bends needed with the same grade.
Girth welds were conducted by Sumitomo Metal Pipeline and Piping, Ltd and mechanized GMAW (Gas Metal Arc Welding) was selected to achieve the special requirements, i.e., the strength of weld metal to completely overmatch the pipe avoiding the concentration of longitudinal strain to the girth weld, and the hardness to be max.300HV10 avoiding HSC (Hydrogen Stress Cracking) on this portion. Both of RT (Radiographic Test) and UT (Ultrasonic Test) were carried out to all the girth welds. These were by JIS (Japan Industrial Standards) and the project-specific requirements.
The 2D Spring Splines Procedure Application With Prescribed Accuracy for Determination of the Global (Pipe Centerline) as Well as the Local (Dent) Curvatures
Authors: Orynyak I. V. , Bohdan A. V. , Lokhman I. V. 
Published: July 2013

The problem of smoothing the spatial line based on position measurements of discrete points exists in cases where a) the positions of points are determined with some errors, b) the goal of smoothing is not a continuous position itself but the higher derivatives of it. It is a very common problem in many engineering applications. With respect to the pipeline industry this problem is very prominent at least in two cases but regretfully many researchers do not pay due attention to it at all.
First, the Geopigs are widely used for the determination of spatial position of the pipe centerline points. This information inter alia may be (and in fact are widely) used for the calculation of the global centerline curvatures which are proportional to the global bending strains. Second, the maximum strain levels of the dents are calculated based on the local geometry of the dent as determined by radial sensor measurements from the in line inspection survey. Note, that in both cases mathematically the curvatures are the second derivatives of the function of global (pipeline) or local (dent) positions.
The input information about the global X–Y–Z position of each consecutive point of axis line as well as the local radial position of the dent points are given with some error. This leads to a huge noise in predicted curvatures which can overrun the useful information. The amplitude of errors of calculation is inversely proportional to the squared distance between the points of measurement. The application of any smoothing procedure may lead to the loss of the useful information about real curvatures. Thus tradeoff between the smoothing of the noise and the loss of accuracy presents a big problem in the pipeline industry.
Two quantitative parameters are introduced here to allow performing such a tradeoff. First parameter characterizes the standard deviation (also referred to as standard in the following) of the random value of the position measurement accuracy by the devices, ρ. Second parameter is the requested accuracy of the curvature determination and is defined in terms of the standard deviation of the bending stress, σ or strain, ε. The spatial beam on elastic foundation model is used to fit the measured point positions to the spatial curve. Its main characteristic is the specific compliance of the foundation α which is determined based on two above root-mean-square errors ρ and σ. The corresponding formulas and tables based on the solution for the elastic beam are obtained. The bigger the allowed error in bending stress σ the lesser is required compliance of the foundation, α. In turn this leads to the smaller value of characteristic wave length of solution and the possibility to retain more useful information about the actual short length stresses in the pipeline.
Some practical examples of applications of the procedure are given.
Determination of Significant Risk Threshold of Upstream Pipelines
Authors: Lu Hong 
Published: July 2013

The pipeline risk assessment has been part of the integrity management in the industry in today’s environment of increasing regulatory and public oversight. One of the widely used risk assessment method is the score index method. This method has been used for more than two decades and is widely accepted in the pipeline industry. The input data is relatively easy to acquire. The method provides details of mitigation options and relative risk values. However, this method does not provide the simple decision making process.
In risk management, it is always the question to choose the most cost effective mitigation option to use limited resources. On the basis of score index risk assessment method, a method to correlate the probability of failure score with actual failure probability, and leak impact factor score with actual failure consequence in monetary units has been developed. This method applies the monetarily calibrated consequence factor to the probability of failure to obtain a normalized and calibrated risk in monetary unit. By comparing the cost of an estimated mitigation program, the decision can be made.
Recent regulations in Canada require that risk assessment must have a method to determine the significant risk threshold. Even though some industrial standards have some recommended methods or benchmark data for failure probability, there is no published method to determine the threshold of high risk. Some pipeline companies have the in-house personnel to develop an advanced method to meet regulation requirement. However, many pipeline companies need to have a practical and economical method to determine the significant risk threshold to meet regulation requirement, and to effectively allocate resources. This paper develops a method to determine the significant risk threshold that can be used as a decision-making criterion in pipeline risk management.
This process is practical for industrial application, especially for upstream companies where operators have limited resources for advanced risk assessment. A case study is presented using this method based on upstream pipelines.
Tools and Methods for Internal Pipe Coating Evaluation for Gas Transmission Systems
Authors: Botros K. K. , Piazza M. , Abayarathna D. 
Published: July 2013

The option of internally coating a new pipeline, or a section of an existing pipeline has emerged in recent years as competition in the energy marketplace grows more intense and coating technologies have advanced from 100% solvent-base to 100% dry-based. Internally coated pipes would mean additional capital cost, but will result in lower pressure losses, hence lower compression power, lower fuel consumption and lower emission. Therefore, there is a trade-off that needs to be assessed, which is the subject of the present paper.
The present paper first provides a proposed standardized method to report the internal wall roughness parameters that could be used to compare bare vs. different coating technologies in a consistent manner. The second part of the paper focuses on evaluating the impact and performance of internal coatings on flow efficiency in energy transmission pipeline systems. A tool and methods were developed to evaluate all of the various options specific to internal pipe coating (including bare pipe option) using a Life Cycle Cost (LCC) economic tool developed for this purpose. The incremental Cumulative Present Value Cost of Service (iCPVCOS) associated with the application of the various coating technologies, as well as quantification of the relative benefits of each compared to a bare pipe, are the main outcome of the tool. This provides an impetus to sound design and selection of the most cost effective technology for internally coating the pipes, whether for new or existing pipeline systems. Examples of various scenarios involving a 2900 km pipeline coated using different internal coating technologies are discussed.
Evaluation of Leak/Rupture Behavior for Axially Part-Through-Wall Notched High-Strength Line Pipes
Authors: Amano Toshihiko , Makino Hiroyuki 
Published: July 2013

Concerning the fracture assessment of high strength linepipes for natural gas transportation, it is necessary to take into consideration not only the crack arrestability of running ductile fractures but also the characteristics of ductile fracture initiation from defects which can cause fracture propagation. The original leak/rupture criteria proposed by Kiefner et al. have been widely used in many industries and worked well for ordinary grade pipes. However, as pointed out by D.-J. Shim et al., recent modern line pipes have some unusual characteristics that differ from older materials. Kawaguchi et al. also revealed that the leak/rupture prediction using Charpy V-notch (CVN) absorbed energy-based equation was not applicable to pipes having CVN energy (Cv) greater than 130 J and flow stress greater than X65.
To verify the leak/rupture criteria using CVN absorbed energy-based equation for high strength linepipes with higher Charpy energy, hydrostatic burst tests were conducted for API 5L X100 linepipes with an axial part-through-wall (PTW) notch. Based on the relationship between the axial PTW notch length/depth and hoop stress, Leak-Before-Break (LBB) criteria was experimentally determined. A series of tests demonstrated that the CVN-based equation underestimates the failure stress for X100 linepipes i.e., the predicted failure stress is 0.943 times the experiment on average and the flow stress dependent equation has a tendency to overestimate the failure stress for longer notched pipes. Concerning the leak/rupture behavior, it is observed that the flow stress-dependent curve for through-wall (TW) notch overestimates the leak/rupture boundary and the toughness-dependent curve for TW notch is relatively close to the leak/rupture boundary.
Failure Investigation of a Natural Gas Transmission Pipeline
Authors: Chauhan Vinod , Fordyce Ian , Gilliver James , Peravali Sudhakar , Connell Andrew , Thompson Ian , Saleh Hadi , Ng Paul , Laksana Arie , Lalan Dadang , Komaruddin M. 
Published: July 2013

PT Transportasi Gas Indonesia (TGI) own and operate a 536 km long natural gas pipeline in South Sumatra, Indonesia which transports natural gas from ConocoPhillips’s gas field in Grissik, South Sumatra to Chevron Pacific Indonesia’s station facilities in Duri. On 29th September 2010, an event occurred that resulted in a release of gas from the pipeline. In response to the emergency, the affected section of the pipeline was isolated by closing block valves upstream and downstream of the leak. The incident was brought under control by TGI on the same day and there were no reported injuries or fatalities. Failure was located in a girth weld on a 28 inch diameter pipe section, which had spread into the adjacent pipe material. Subsequently a failure investigation was requested by TGI. The investigation included a fracture examination and materials testing of the failed girth weld and parent pipe; a geotechnical investigation; and an engineering critical analysis (ECA) of the failure. This paper describes the multidisciplinary works undertaken to investigate the cause of the incident.
The primary observation of this failure investigation is that no single factor contributed to the failure that occurred. The pipeline at the rupture location had been subjected to high bending stresses when the pipeline was laid and the stresses were exacerbated following consolidation and creep settlement of the underlying swamp material. The field joint coating had been compromised, leading to the formation of near neutral stress corrosion cracking (SCC). Initial cracking from the SCC had then extended to the point where the remaining ligament then failed by plastic collapse. It was judged that the settlement may also have been enhanced by a recent earthquake.
Essential Elements of an Effective SCC Direct Assessment Program
Authors: Rapp S. C. , Marr J. E. , Martinez F. H. , Vervake G. , Batte A. D. 
Published: July 2013

Stress Corrosion Cracking (SCC) Direct Assessment in accordance with the guidance set out in NACE SP0204 is an accepted method for assessing the threat of SCC in High Consequence Areas in the US, as prescribed for gas transmission pipelines by CFR 192 Sub-part O. Although operators have used excavations as part of their integrity management strategies for SCC for many years, the formalized method for gathering, interpretation and application of information that is set out in NACE SP0204 has only been applied for less than ten years.
During a recent Joint Industry Project involving eight major North American natural gas transmission operators, the current status and application of SCC Direct Assessment has been reviewed. Several of these operators have developed in-house procedures incorporating the relevant guidance from NACE, CEPA and ASME, and over 160 SCC Direct Assessment excavations in accordance with the requirements of NACE SP0204 have been undertaken during the last five years. This paper reviews the development of the procedures, their in-field application and the use of the interpreted data to further refine the SCC Direct Assessment processes.