The project “Development of an Industry Test Facility and Qualification Processes for in-line inspection (ILI) technology Evaluation and Enhancements” aims to expand knowledge of ILI technology performance and identify gaps where new technology is needed. Additionally, this project also aims to provide ILI technology developers, researchers and pipeline operators a continuing resource for accessing test samples with a range of pipeline integrity threats and vintages; and inline technology test facilities at the Technology Development Center (TDC) of Pipeline Research Council International, Inc. (PRCI), a PRCI managed facility available for future industry and PHMSA research projects. An ILI pull test facility was designed and constructed as part of this project based on industry state-of-the-art and opportunities for capability improvement. The major ILI technology providers, together with pipeline operator team members, reviewed the TDC sample inventory and developed a series of ILI performance tests illustrating one of multiple possible research objectives, culminating in 16-inch and 24-inch nominal diameter test strings. The ILI technology providers proposed appropriate inspection tools based on the types of the integrity threats in the test strings, a series of pull tests of the provided ILI tools were performed, and the technology providers delivered reports of integrity anomaly location and dimensions for performance evaluation. Quantitative measures of detection and sizing performance were confidentially disclosed to the individual ILI technology providers. For instances where ILI predictions were outside of claimed performance, the vendors were given a limited sample of actual defect data to enable re-analysis, thus demonstrating the potential for improved integrity assessment with validation measurements. In this paper, an evaluation of the ILI data obtained from repeated pull-through testing on the 16 and 24-inch pipeline strings at the TDC is performed. The resulting data was aligned, analyzed, and compared to truth data and the findings of the evaluation are presented.

With the increased number of In-Line Inspections (ILI) on pipelines, it is important to evaluate ILI tool performance to support making rational integrity decisions. API 1163 “In-Line inspection systems qualification” outlines an ILI data set validation process which is mainly based on comparing ILI data with field measurements. The concept of comparing ILI results with previous ILI data is briefly mentioned in API 1163 Level 1 validation and discussed in detail in CEPA metal Loss ILI tool validation guidance document. However, a different approach from API 1163 is recommended in the CEPA document. Although the methodologies of validating an ILI performance are available, other than determining whether an inspection data set is acceptable, the role of ILI validation in integrity management decision making is not well defined in these documents. Enbridge has reviewed API 1163 and CEPA methodologies and developed a process to validate metal loss ILI results. This process uses API 1163 as tool performance acceptance criteria while CEPA method is used to provide additional information such as depth over-call or under-call. The process captures the main concepts of both API 1163 and CEPA methodologies. It adds a new dimension to the validation procedure by evaluating different corrosion morphologies, depth ranges, and proximity to long seam and girth weld. The process also checks ILI results against previous ILI data sets and combines the results of several inspections. The validation results of one inspection provide information on whether the inspection data set is acceptable based on the ILI specification. This information is useful for excavation selection. Tool performance review based on several inspection data sets identifies the strength and weakness of an inspection tool; this information will be used to ensure the tool selection is appropriate for the expected feature types on the pipeline. Applications of the validation process are provided to demonstrate how the process can aid in making integrity decisions and managing metal loss threats.

Pipeline isolations and interventions using hot taps and in-line isolation tools are used widely across the oil and gas industry for the maintenance of pipelines, platforms and process plants. They may also be used to facilitate tie-ins for the connection of new facilities or the diversion of operating pipelines. They require a clear understanding of risk and the factors that can lead to failure, which can have a safety, environmental or business impact affecting both the operator and supplier. A fresh look at the risks and how they can be effectively managed was carried out. The reviews showed that whilst there was a strong emphasis on personal safety and technical standards there was a need to maintain an emphasis on overall process safety. Using a global contract for the provision of services for isolations and interventions BP has worked closely with leading Suppliers (Furmanite, STATS Group, TD Williamson, TEAM Industrial Services) in this area to develop a framework for driving improvement and consistent delivery of these services. The work builds on some of the best practices developed with improving success rates with In-Line Inspection (ILI) and develops the process from the definition of safe and successful isolations through to the importance of capturing lessons learnt. The paper develops the processes for the definition of safe and successful isolations and interventions by addressing: • Definition of success • The engagement process and requirements for information. • Development of a common risk model based on failure data across all of the Suppliers • Use of effective quality management systems and key performance metrics • Development of an industry competency framework for technicians • Use of a clear lessons learnt process and the importance of performance reviews. Safe and successful isolations and interventions require effective management, clear communication and systematic engagement. They are achieved through a relationship between the operator and the supplier that is built on trust, open conversation and a willingness to improve; where both operator and supplier work together with common objectives and a common understanding of risk. The process outlined in this paper creates an opportunity to raise standards across the industry, building on knowledge, experience and best practices.

This paper is based on some of the findings resulting from the PRCI project NDE-4E which examined the performance of various crack ILI technologies based on an industry data mining exercise. One of the project deliverables was an extensive database of crack in-line inspection (ILI) and excavation information collected from operators. This was used to characterize the field performance of ILI technologies with respect to detection, identification and sizing of crack features. Thousands of feature measurements were collected from several operating companies. The data were validated to ensure completeness, consistency and accuracy, and stored in a database. The main results to date are as follows: • Most profiles have shallow areas along the feature length — they are not semi-elliptical or parabolic in shape as usually assumed in burst pressure computations. Shallow regions increase the defect length, but do not increase the defect cross-section proportionally. • If it is assumed that the ILI tool requires a minimum depth before a portion of a feature is reported, it follows that the length reported by the ILI tool would differ from that observed in the field. This is due to the fact that the ILI tool would be reporting the length of the crack at some threshold depth and the field would be reporting the feature length at the surface. • Using depth profiles, an effective detection depth was calculated, that is the average depth at which the ILI length aligns with the profile. This was determined to be an average value of 0.88 mm for cracks and 0.83 mm for crack-fields which exceeds published ILI tool specification. • Shallow parts of a crack profile have significant impact on the field-measured length, but do not significantly impact the burst pressure. • For 83% of the data, the remaining strength factor (RSF) calculated using ILI data is within 10% of the RSF value calculated using field profiles. • Feature depth recorded in depth categories by the ILI tools show sensitivity to their proximity to long seam welds for crack-like features. • Overall, Burst pressure is more relevant to pipeline integrity than either length or depth individually and burst pressure calculated from ILI measurements is conservatively biased compared to burst pressure calculated from profile data.

New technologies for in-ditch non-destructive evaluation were lately developed and are becoming of mainstream use in the evaluation of external corrosion features for both In-Line-Inspection performance evaluation and pipeline integrity assessment. However, doubt was cast about the reliability and repeatability of these new technologies (hardware and processing software) when compared with those used in the traditional external-corrosion in-ditch measurement and the reliability of the pipeline integrity assessment calculations (P Burst ) embedded in their software when compared with industry-wide accepted calculation methods. Therefore, the primary objective of this study is to evaluate the variation and repeatability of the measurements produced by these new technologies in corrosion feature profiling and associated P Burst calculations. Two new 3D scanning systems were used for the evaluation of two pipe samples removed from service which contain complex external corrosion features in laboratory. The reliability of the 3D scanning system in measuring corrosion profiles was evaluated against traditional profile gage data. In addition, the associated burst pressures reported by the systems were compared with results obtained using industry-widely used calculation methods. Also, consistencies, errors and gaps in results were identified. In this paper, the approach used for this study is described first, the evaluation results are then presented and finally the findings and their implications are discussed.

In spite of current world economic climates, recognition that alternative energy sources to the traditional fossil fuels has to be explored and understood. One potential energy source being researched and developed is hydrogen gas. Currently the most economical method of transporting large quantities of hydrogen gas is through steel pipelines. It is well known that hydrogen embrittlement has the potential to degrade steel’s mechanical properties when hydrogen migrates into the steel matrix. Consequently, the current pipeline infrastructure used in hydrogen transport is typically operated in a conservative fashion. This operational practice is not conducive to economical movement of significant volumes of hydrogen gas as an alternative to fossil fuels. The degradation of the mechanical properties of steels in hydrogen service is known to depend on the microstructure of the steel. Understanding the levels of mechanical property degradation of a given microstructure when exposed to hydrogen gas under pressure can be used to evaluate the suitability of the existing pipeline infrastructure for hydrogen service and guide alloy and microstructure design for new hydrogen pipeline infrastructure. To this end, the microstructures of relevant steels and their mechanical properties in relevant gaseous hydrogen environments must be fully characterized to establish suitability for transporting hydrogen. Previously data from a US Department of Energy/private sector funded project to evaluate four commercially available pipeline steels alloy/microstructure performance in the presences of gaseous hydrogen was presented in 2010. Interest in this previous work from industry and the ASME B31.12 Hydrogen Piping and Pipeline Systems codes and standards committee resulted in additional funding for continued evaluation of additional pipeline steel alloys/microstructures in the presences of gaseous hydrogen. Samples from API grades X52 (1960’s and current vintage designs), X70 (1980’s and current vintage) and X80 along with various samples from an X52 induction bend pipe and one pressure vessel steel A516 Gr 70 are being evaluated. Microstructural characterization, fracture toughness and fatigue testing in the presence of gaseous hydrogen at 800 psig and 3,000 psig are being conducted. This paper will describe the fracture toughness results achieved to date on various commercially available pipeline steels used in the existing North American pipeline infrastructure in the presence of gaseous hydrogen at pressures relevant for transport in pipelines. Microstructures and fracture toughness performances will be compared between these in this study along with those published previously. In addition, recommendations for future work related to gaining a better understanding of steel pipeline performance in hydrogen service will be discussed.

Natural gas is gaining popularity in the world as a high quality, clean burning alternative to oil and coal. The Mechanism of Drag Reduction in the natural gas pipelines is to control the radial pulsation of gas adjacent to pipeline wall effectively. The way to lower the pulsation intension of the gas in the thin layer along the wall is to use gas drag reduction agents, whose polar end absorbs fixedly to the surface and whose non-polar long chain suspends in natural gas so as to have a function of restraining the gas’ radial pulsation. The drag reduction agent molecule absorbed to the protruding is mainly to weaken the gas pulsation producing by virtue of roughness degree. The drag reduction agent molecule absorbed to and collected in the dents also has the function of lowering the equivalent roughness degree of the wall surface. A polymer-type natural gas drag reduction agent with polarity as well as nonpolarity long chain was studied. We synthesized polymers that contain long chain fatty acid (F) or long chain ester (E) as soft chain, and alkoxy residues or acylations as polar group, then studied the effects of this polymer-type gas drag reduction agent on the pipe wall, natural gas quality, station processes and equipments as well as post-processing. A test loop with control software was developed for evaluating natural gas drag reduction agents. An on-line injected system for natural gas reduction agent was established. The product was applied on natural gas pipelines in China. In No.1 oil production plant of Changqing oilfield, the drag reducing efficiency is 19.5%, and the flow increase rate is 12.4%. In pipeline from Lanzhou to Yinchuan, the drag reducing efficiency is all above 10%, and the flow increase rate is all above 5%.

Performance degradation monitoring of centrifugal compressor provides a means for the operators predict the behavior of their machines. Understanding the key principles in performance evaluation is essential for operators to benefit from this approach. In this paper, common performance degradation mechanisms found in centrifugal compressors for the oil and gas industry are outlined and related to their associated performance characteristics. Various analysis and evaluation techniques and approaches are elaborated with relevant requirements and assumptions for practical site application. A case study is also presented to demonstrate the application of performance degradation monitoring in a real-life operating environment. The benefits and limitations of the approach are also discussed. When combined with other condition monitoring approaches, this method provides a powerful tool to analyze and monitor centrifugal compressor performance which will then lead to useful recommendations for maintenance and operational interventions.

As a preventative management mode, integrity management which is significantly effective is now applicable in modern industry. Based on the successful application of integrity management for the pipeline, managers expect an extension of the integrity management program for the oil and gas stations such as pumping stations, so as to make the best arrangement of resources and guarantee the safety of station facilities. The differences between station integrity management system in China and abroad are analyzed. It is claimed that the oil and gas station integrity management is more difficult and complicated in China. An integrity management program is developed for the oil and gas stations in China. The authors summarily introduce the station integrity management framework, and determine the processes and elements of management. For the main parts of the stations are plenty of facilities, the authors attempt to carry out the management on each category of facilities in particular. According to the characteristics and working status, field facilities can be classified into three categories: static facilities, dynamic facilities, and electrical instruments. For all these facilities, integrity management approach consists of five steps: data collection, risk assessment, integrity assessment, repair & maintenance, and performance evaluation. Station integrity management system comprises five aspects: system documents, standards & specifications, supporting technologies, management platforms and applications. This paper should be considered as a reference for the oil and gas station integrity managers in the future.

Pipeline is the common mode for transporting oil, gas, and various petroleum products. Aging and corrosive environment may lead to formation of various defects such as crack, dent, gouge, and corrosion. The performance evaluation of field pipelines with crack defect is important. Accurate assessment of crack depth and remaining fatigue life of pipelines with crack defect is vital for pipeline’s structural integrity, inspection interval, management, and maintenance. An experimental based research work was completed at the University of Windsor for developing a semi-empirical model for estimating the remaining fatigue life of oil and gas pipes when a longitudinal crack defect has formed. A statistical approach in conjunction with fracture mechanics was used to develop this model. Statistical analysis was undertaken on CT specimen data to develop this fatigue life assessment model. Finite element method was used for determining the stress intensity factor. The fatigue life assessment model was then validated using full-scale fatigue test data obtained from 762 mm (30 inch) diameter X65 pipe. This paper discusses the test specimens and test data obtained from this study. Development and validation of the fatigue life assessment model is also presented in this paper.

Nowadays, more and more pipeline operators vigorously promote the implementation of integrity management programs (IMPs for short) in order to improve the integrity of their pipeline systems. But how can the operators measure the performance of their pipeline IMPs? In other words, how can the operators evaluate the efficiency and effectiveness of their programs so as to make continuous improvement? The regulations and standards of pipeline integrity management just gave some requirements and recommendations on performance measurement, but no specific methods were presented. Normally, the pipeline operators measured the performance of IMPs on the base of their management objectives and local regulations’ requirements. The paper introduced the methodology and achievements of pipeline integrity management performance evaluation work conducted in PetroChina Pipeline Company. Considering the company’s specific integrity management goals and objectives, the metrics were established and applied to evaluate whether those goals had been achieved or not, and found out the shortage of the IMP for giving suggestions for improvement. Considering the input and output parameters of IMP, the performance measures system was set up. The input parameters included the input of workforce, facilities and other investments. The output parameters indicated the output of IMP, such as the accomplishment of the objectives, the quality of the work and the safety improvement through IMP. In order to clearly define the input and output parameters of IMP, the IMP was divided into nine parts, such as data management, high consequences areas identification, risk assessment, integrity assessment, corrosion prevention, defect repair, geo-hazards control, pipeline patrol, pipeline security. For each part, considering the management objectives, the “input-output” parameters metrics were set to measure the performance. In order to see the performance of IMP from a macroscopic perspective, a simplified index system was built which mainly focused on the safety improvement such as the number of leakage, failures, accidents and economic loss. The grading performance evaluation system could conveniently meet the different focus of different levels managers. In addition, in order to eliminate the influence of the different management difficulties to the performance of IMP, the paper built a set of adjustment factors to modify the investment parameters to make sure the evaluation results more objective and fair. At last, the paper showed the application results of the IMP performance evaluation conducted in PetroChina Pipeline Company and its branches.

The new CSA Standard, Security Management for Petroleum & Natural Gas Industry Systems, is changing the operational landscape throughout the oil and gas industry. This document focuses on an innovation that will help pipeline operators meet the new recommendations for monitoring and managing their remote assets as outlined in the new CSA standard. This paper includes an analysis of the current monitoring architecture that can be used for compliance with the new regulation as well as a detailed comparison of different architectures. New video surveillance architecture developments are also reviewed. The IntelliView technology uses software that turns passive cameras into video sensors capable of reporting video-based behavior exceptions based on user-defined rules. A hardware device known as a SmrtDVR sits on site and records the video in the highest quality (H.264) to ensure the images are clear for review and investigation. It acts like the brains of the system, able to think if the images it is seeing on the cameras are ones that it has been programmed to alert the pipeline operator about. Alerts can include: trip wire, loitering, object taken/left behind and man down. When an alarm is triggered, a real-time event notification is sent in an (optional) JPEG format to smart phones, monitoring stations and/or third party monitoring companies. These in-situ devices require minimal communication, power and IT infrastructure and notify operators with video driven alerts. A performance evaluation of the proposed system is presented that illustrates how IntelliView’s unique architecture is outperforming the current industrial practice.

The Energy Resources Conservation Board (ERCB) is the quasi-judicial agency that is responsible for regulating the development of Alberta’s energy resources. Its mandate is to ensure that the discovery, development, and delivery of Alberta’s energy resources takes place in a manner that is safe, fair, responsible, and in the public interest. The ERCB’s responsibilities include the regulation of over 400,000 km of high-pressure oil and gas pipelines, the majority of which is production field pipeline. ERCB regulations require pipeline licensees to report all pipeline failures, regardless of consequence, and thus a comprehensive data set exists pertaining to the failure frequency and failure causes of its regulated pipelines. Analysis has shown that corrosion is consistently the predominant cause of failure in steel production pipeline systems. Corrosion-resistant materials, such as fibre-composite pipe, thermoplastic pipe, and plastic-lined pipe have long been explored as alternatives to steel pipe, and have in fact been used in various forms for many years. The ERCB has encouraged the use of such materials where appropriate and has co-operated with licensees to allow the use of various types of new pipeline systems on an experimental basis, subject to technical assessment, service limitations, and periodic performance evaluations. This paper will review the types of composite pipe materials that have been used in Alberta, and present statistical data on the length of composite pipe in place, growth trends, failure causes and failure frequency. As the purpose of using alternative materials is to improve upon the performance history of steel, a comparison will be done to determine if that goal is being achieved.

Integrity management regulations require operators of high-pressure gas pipelines to consider various threats to pipeline integrity including time-dependent degradation due to corrosion. Depending on factors including age and operating pressure, a pipeline will require periodic integrity assessment. Methods available for assessing external corrosion are in-line inspection, pressure testing, or Direct Assessment, which is the subject of this paper. An analysis was conducted on data from a large diameter gas transmission pipeline built in the 1960’s. A 30Km section was investigated, using data spanning an 18-year period. The records analyzed included above ground surveys, high-resolution in-line inspection surveys, and site investigations. Assuming the in-line inspection represents true condition, it was found that the above ground surveys produced indications at between 80% and 90% of the in-line inspection features. Approximately 35% of the survey indications did not correspond to in-line inspection features. This information should benefit those wishing to implement Direct Assessment programs using Structural Reliability Analysis techniques.