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When estimating pipeline burst pressure, one of the prevalent sources of uncertainty that needs to be factored into the calculation is the model error in the estimation of feature depth and length from the in-line inspection tool. Due to modeling technique limitation, as of today many ILI vendors have feature specific error bounds depending on the morphologies of the corrosion, this error can only be reported to operators as an overall error known as the ILI tool tolerance which is usually obtained from samples of excavation data or pull test data. At the most, the error is reported by classes based on corrosion morphologies specified by Pipeline Operators Forum. For example, a commonly reported corrosion depth sizing specification is ±10% of pipe wall thickness at 80% confidence for the General type of corrosion. This can be interpreted as that the error of each reported depth estimations is assumed to fall in a normal distribution with a mean equal to 0 and standard deviation equal to 7.8% of wall thickness. The shape of the distribution, the mean and standard deviation will then be used as constants to factor in the burst pressure calculation. However, these factors are never constant for a sample of defects in reality. In fact, they ought to be variables on an individual feature basis. An example of such an approach would be a feature specific error tolerance, this could be that the estimated depth of a feature is 36%wt in an interval of [30%, 48%] of wall thickness with 80% confidence. This is believed to greatly reduce the level of uncertainty when it comes to failure pressure estimation or other type of pipeline risk assessment. The advancement in Machine Learning today, deep learning with deep neural networks, allows feature-specific error tolerance to be obtained after analyzing visual imagery of MFL signal. In this paper we will describe a novel approach to predict the size of metal loss defects and more importantly the distribution associated with each prediction. We will then discuss the benefits of this approach has with respect to risk assessment such as failure pressure estimation.

The integrity of transmission oil pipelines are often managed through in-line inspections (ILI) at regular intervals. For the last two decades, such ILI-based integrity programs along with excavations and field non-destructive testing (NDE) have proven their effectiveness in terms of reliability. In a few cases, some pipes contain; for example, a unique cracking mechanism exhibited by short, deep axial cracks located in the vicinity of girth welds. These attributes pose sizing difficulties for ultrasonic crack ILI tools. Accordingly, operators may lean on supplemental integrity activities to prove the safety of the pipelines such as; but not limited to, hydrostatic testing, laboratory testing of cut-outs, qualitative ranking of features, borehole leak detection analysis, Just-Missed-Flaw (JMF) or Just Surviving Flaw (JSF) analysis, discharge and/or point pressure restrictions, and/or a mix between all the previous techniques. Moreover, it is the operators’ responsibility to evaluate the risk associated with their integrity plans. Hence, it is important to be able to analyze the reliability of such integrity activities quantitatively. This paper presents an event-tree approach which can augment standard ILI or hydrostatic test results and probabilistic analysis with non-ILI integrity measures under one umbrella. In this approach, the likelihood of failure for both leak and rupture modes can be comprehensively estimated. The event tree approach is used herein as an inductive analytical diagram in which failure events are analyzed using Boolean logic to examine a chronological series of subsequent integrity actions and consequences. The proposed approach is also designed to capture subject matter experts’ opinion into the analysis as part of the integrity management program. The work discusses a real practical application along with verification and validation elements of the proposed integrated approach.

Cracks in dents or linear anomalies interacting with dents are a major pipeline threat. These combined anomalies represent challenges to the Mechanical Engineers that design ILI tools as they need to keep the sensor in an optimal position towards the inner pipe wall. Ultrasonic Crack (UC) tools consist in a sensor plate with a fixed incidence angle that depends on the coupling medium. This plate is then attached to the skids; these are in constant contact with the internal pipe wall. When the tool interacts with a dent, the incidence angle is not optimal; therefore, detection of any interacting feature is compromised. By not having the optimum angles in the pipe wall, the amplitudes from the reflections caused by cracks will be attenuated. Depending on the magnitude of the attenuation, these might be below analysis thresholds meaning that an algorithm and/or analyst will not consider them as relevant signals. Up to this point, detection of interacting features sounds like a “guess “ or “luck”. So, how can we use UC inspection to detect the interacting features? How can operators manage their assets knowing that they have dents but there is an uncertainty if there are interacting features? To answer these questions, a systematic approach had to be used. It consisted of multiple phases where 1.- The mechanical design of the tool was understood, 2.- Simulation campaigns to understand the ultrasonic pulse while interacting with the dent, 3.- Pump tests with artificial features, and 4.- Pump test with real features. All of the data gathered through the different phases allowed the authors to understand the attributes from the features and conditions that influence detection and identification of cracks in dents. This derived in a performance specification stating the truth capabilities to detect interacting features in a dent. These learnings were applied to commercial inspections where the feedback loop is closed with the field verifications.

In-Line inspection (ILI) tools consisting of combined sensor technologies provide a unique opportunity for operators to understand the conditions of pipelines. There is also an additional opportunity to contrast and validate individual sensing techniques against each other when their functionalities and purposes overlap. By using multi-technologies ILI measurements for strain, a pipeline operator can gain further insight into the pipeline strain behavior at any point along the length of the inspection. This paper establishes the relationship between ILI axial strain measurement tool data and conventional geometric strain data obtained from inertial measurement unit (IMU) based on data collected during in-service inspection of a 12″ liquid pipeline. Within any pipeline section, the tool configuration with circumferentially spaced strain sensors allows the use of appropriate analysis techniques to decompose the longitudinal strain into its primary components (axial, bending and out of roundness). The axial strain measurement tool sensing system provides an indirect measurement of bending strain that can be compared to the geometric measurement of bending strain determined from the pipeline trajectory as determined from the IMU analysis. Flexural bending strain resulting from horizontal directional drilling (HDD) is investigated in this paper. Convergences and divergences between the measurement techniques are presented. Data available from different strain technologies mounted on ILI tools offers an opportunity to conduct a comparative study and to provide a better understanding of a pipeline’s strain condition. This paper will present the framework for understanding the different strain measurement technologies and an investigation into the pipeline prior strain history (effects from fabrication, hydrostatic testing and external loads) and their corresponding impact on the material state at the time of inspection.

Environmentally assisted cracking (EAC), more specifically, stress corrosion cracking (SCC) has been a pipeline integrity concern since the 1960s. However, there were not many options for pipeline operators to effectively manage this threat on gas and liquid pipelines. SCC and other crack type defects have become a threat which is more widely understood and can be appropriately managed through in-line inspection (ILI). The two primary technologies for crack detection, developed in the 1990s and early 2000s respectively, are ultrasonic (UT) and electromagnetic acoustic transducer (EMAT). Although EMAT was originally developed to find SCC on gas pipelines, it has proven equally valuable for crack inspections on liquid pipelines. A case study with a gas and natural gas liquid (NGL) operator, ONEOK Inc. (ONEOK) demonstrates the effectiveness of using EMAT ILI to evaluate the potential threat of crack and crack-like defects on a 48 mile (77.2 km), liquid butane pipeline. By utilizing both 10-inch (254 mm) multiple datasets (MDS) technology and 10-inch (254 mm) EMAT ILI tools, ONEOK proved the effectiveness of ILI to identify critical and sub-critical crack and crack-like defects on their pipeline. This paper will present on the findings from the two technologies and illustrate the approaches taken by the operator to mitigate crack type defects on this pipeline.

Pipeline in-line-inspections (ILI) are used to assess and track the integrity of pipelines, aiding in identifying a variety of features such as: metal loss, dents, out-of-roundness, cracks, etc. The presence of these features can negatively affect the operation, integrity, and remaining life of a pipeline. Proper interpretation of the impacts these features may have on a pipeline are crucial to maintaining the integrity of a pipeline. Several codes and publications exist to assess the severity of these features under known operating conditions, either through empirical formulations or more detailed analysis, in order to aid the operator in determining a corrective action plan. These empirical formulations are generally applicable to assess a singular defect but require a more detailed assessment to evaluate combined defects (i.e. dent in a bend). These detailed assessments typically require a higher level numerical simulation, such as Finite Element Analysis (FEA). This detailed FEA can be quite costly and time consuming to evaluate each set of combined features in a given ILI run. Thus, engineering judgement is critical in determining a worst-case scenario of a given feature set in order to prioritize assessment and corrective action. This study aims to assess dent features (many associated with metal loss) occurring in a pipe bend to determine a worst-case scenario for prioritization of a given feature listing. FEA was used to simulate a field bend of a given radius and angle in order to account for residual stresses in the pipe bend. A rigid indenter was used to form a dent of the approximate length, width, and depth from the ILI data. Separate models were evaluated considering the dent occurring in the intrados, extrados, and neutral axis of the pipe bend to evaluate the worst-case scenario for further assessment. The resulting stresses in the pipe bend-dent geometry, under proper loading were compared to the same dent scenario in a straight pipe segment to develop a stress concentration factor (SCF). This SCF was used in the API 579-1/ASME FFS-1 Fitness for Service (API 579) [1] methodology to determine the impact on the remaining life of the combined features.

In-line inspection (ILI) data processing is a crucial process on assessing the remaining capacity of corroded pipelines. It is used to generate the RBP (river bottom profile) or M AV (moving average) file which could be further used in the capacity calculations. There are large uncertainties regarding the qualities of ILI data itself, which are dependent on the accuracies of the ILI tool, the reporting method and the condition of the inspected pipelines et. al. It is thus required that the post-process of the ILI data should not add more uncertainties to the capacity check. Challenges exist on generating reliable RBP/MAV from the ILI data on general base. This paper originates from work during the in-house software development for corroded pipeline tool. Three different algorithms on filtering the ILI data are examined. They are the method recommended by DNV-RP-F101 (with modification), the median filter algorithm and the gaussian filter algorithm. The latter two algorithms are from standard methods for image denoising. A comparison study has been performed with several actual ILI data sets. Finally, conclusions and suggestions have been made, which may provide useful hints for industry application.

This paper presents a screening methodology that is used to reduce the amount of data requiring detailed analysis from that obtained during in-line inspection (ILI). The methodology uses ILI outputs (dimensions of flaws, orientation and distance from starting point) to generate a visualisation of the pits within the pipeline, a ranking of pits in terms of sphericity (roundness) and depth, to evaluate pit density and generate the models for finite element analysis. The rendering tool allows a clearer view of defects within the pipelines and provides a simplified way to focus on critical pits. For a particular case of in-field data provided by BP, the number of pits in a 12-inch riser of 11 km length was reduced from 1750 obtained to 43, 15 or 4 requiring analysis, depending on the level of conservatism introduced by the analyst. The tool will allow Oil and Gas owners and operators to reduce the immense amount of data obtained during pigging to a much less time-consuming set for flaw assessment.

Det Norske Veritas (U.S.A.), Inc. (DNV GL) prepared this paper in order to study the expected accuracy of in-line inspections (ILI) as a function of year, depth (both reported and field measured), and length, amongst other factors. DNV GL has access to a significant amount of data that span many different pipeline operators, ILI vendors, inspection years, and inspection technologies. DNV GL is well suited to complete this study as a result of our access to these various data sets. Over 3,000 individual comparisons of ILI and field depths and lengths spanning from 2010 through 2015 from 11 operators and 68 line segments were compiled to meet the objectives of this paper. Inspection technologies include axial magnetic flux leakage (MFL), ultrasonic wall thickness (UTWT), spiral MFL, and circumferential MFL. Based on the analyses conducted in this paper, the following conclusions were generated. • Axial MFL and UTWT inspections show significant improvements over the last several years. • Axial MFL inspection systems are capable of meeting a depth accuracy of +/−10% of the wall thickness with 80% certainty, but this has not always been the case. UTWT inspection systems are capable of meeting a higher depth accuracy. • Axial MFL inspection systems report more pits and circumferential grooves than UTWT systems. This could suggest UTWT systems are less sensitive to pits and circumferential grooves than axial MFL systems. • Both axial MFL and UTWT inspection systems routinely under call defects with field measured depths greater than 50 to 80% of the wall thickness. This is contrary to a widely held notion that ILI is conservative for deep defects. • ILI reported defect lengths do not correlate well to field measured defect lengths. In general, field measured defect lengths are greater than ILI reported defect lengths. • Depth accuracy tends to decrease slightly for very short defects (less than 1-inch) and for very long defects (greater than 40-inches). Based on these conclusions, the authors make the following recommendations: • Pipeline operators should dig more than the deepest reported defects to better understand the accuracy of the inspection tools being used and to determine whether deeper anomalies are being under called. • Pipeline operators should consider methods for evaluating change in corrosion depth from ILI survey to ILI survey to lessen the dependence on the accuracy of the ILI tools. This should include a raw data signal analysis in order to determine whether the general morphology (metal loss length and width) are changing between ILI surveys. • ILI reported defect lengths should be used in conjunction with field measured defect depths (if available) when performing failure pressure calculations. • Additional accuracy, especially for deeper defects, may only come with new tool developments. Industry support of such developments will be required to bring them to fruition.

This case study describes the crack management program for a pipeline that is NPS26, 7.1 mm wall thickness, Grade X52, flash welded and was constructed from 1954–1957. It transports light crude oil, and experiences pressure cycling though start-stop operations. Excavations have revealed that the pipeline’s flash welded seam contains a variety of manufacturing anomalies. While the majority of these anomalies are benign and stable, some exhibit the potential to grow due to the pressure cycling of the line. Furthermore, in 2010, the pipeline experienced a rupture and leak that were caused by cracks in the longitudinal seam weld. Correspondingly, the cracking threat has been actively managed using in-line inspection (ILI), excavation, and repair programs. The most recent ILI runs were conducted with ultrasonic crack detection (USCD / UTCD) and ultrasonic phased array crack detection (DUO) tools in 2009, 2012 and 2013. As a part of these ILIs, a comprehensive excavation program comprised of over 300 excavations was conducted to validate the ILI data and mitigate the cracking threat. Unity plots comparing the measurements from each excavated ILI feature with the corresponding field Non-Destructive Examination (NDE) measurements were evaluated to support quantification of the Probabilities of Identification, Detection, and Sizing for these inspections. The results revealed that the ILI results were not repeatable when comparing the data from the three inspections, and not meeting target specifications. Furthermore, advanced analysis was completed to combine the data and evaluate the tool performance reliability for the pipeline. The results showed that the crack ILI tools were not achieving the required reliability targets for the pipeline. Considering that ILI is often successfully used to support the crack management of pipelines for the vast majority of conditions, the 2010 failures were investigated to determine the causes for the unacceptable ILI performance. The investigation revealed that the distinct peaking, misalignments, and pipe mill grinding associated with the pipelines flash weld, caused challenges for the tool’s detection and sizing capabilities. Therefore in order to ensure the safety of this pipeline, mitigation in addition to crack ILI programs was deemed to be required. Some options included operating at a reduced pressure, hydrostatic testing, or pipeline replacement. Hydrostatic testing was selected as the preferred option for implementation. This was successfully completed in October 2015 and there were no leaks or ruptures that occurred during the hydrostatic testing. This demonstrated that the pre-test excavation programs, which targeted features exhibiting burst pressures below that of the hydrotest pressure, had mitigated the cracking threat on the pipeline. The results of the reliability analysis showed that the uncertainties associated with the ILI were higher than acceptable. However as there were no failures during the hydrotest the reliability analysis was conservative for this case in consideration that the pre-test excavation program was able to mitigate the cracking threat. Nonetheless, the process of reviewing and assessing the ILI-field comparisons and evaluating the ILI tool performance remains a critical component of crack ILI management. Conducting alternative mitigation to ILI for crack management, if required, also remains a critical component of crack ILI management. For this pipeline the cracking threat will be re-assessed within 5 years of the hydrostatic test to support continued safe and reliable operation.

In pipeline integrity threat management, the comparison of In-Line Inspection (ILI) and field results (trending) is typically used as an effective approach to determine the performance of ILI tool. ILI and field trending typically influences the integrity threat management of unmitigated features. Hence, pipeline operators should ensure collecting an adequate number of excavated ILI features from the field which are statistically relevant and represent the entire population of ILI data. The number of the trended data points is considered a sample from the entire population of ILI reported features. Nevertheless, it is considered a biased sample since it is drawn from the ILI population based on selective threat mitigation criteria. This paper describes several sampling methodologies with a focus on advantages and disadvantages of each approach. A Bayesian approach is introduced as an appropriate approach to the integrity sampling problem.

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.

In-Line inspection tools (ILI) including Magnetic Flux Leakage (MFL) and Ultrasonic (UT) technologies are commonly used to detect/measure potential anomalies in oil and gas pipelines. Some of ILI reported anomalies are usually selected for excavation and validated through field non-destructive examination techniques (NDE). It is a fact that both ILI and NDE readings are contaminated with measurement errors. Such errors are usually originated from inherent tool limitations and capabilities, measurement techniques, and/or human factors. The intend of this paper is to calibrate the corrosion ILI data relative to NDE measurement given estimated statistical errors from both tools. Commonly, a graphical representation is used to compare ILI versus field measurements; namely, a unity plot. Herein, a linear relationship between ILI and NDE measurements is assumed. Such an assumption leads to another assumption of having a linear relationship between the ILI measurement and true value. Similarly, NDE measurement has the same relationship with the true value. An advanced statistical approach based on linear regression and maximum likelihood is used to determine the uncertainty of both ILI and NDE measurement errors. This method is based on first quantifying the uncertainty of ILI and field measurement and then calibrating the ILI data relative to the field using the estimated tools errors. The tool error estimation is based on reducing the relative error between ILI and field measurements. The calibration methodology implements advanced statistics to improve both accuracy and precision of measurement data. The proposed process is validated through results from successive ILI programs. The proposed calibration can be easily adopted in ubiquitous computing spreadsheet environment and be applied to both corrosion and crack measurements.

The most common methods currently available for detecting cracks and linear features in pipelines are Ultrasonic Crack Detection (USCD) ILI and Electromagnetic Acoustical Transducer (EMAT) ILI. A third ILI technology using Spiral MFL with hard spot detection capability has also showed capability for detecting linear features within deformations that are not readily detectable by USCD or EMAT tools. Any measurement technology, including ILI and field NDE tools, has a range of accuracy and detection capability. This paper analyzes and compares the performance of these ILI tools against the measurements obtained from field investigations. It will be shown that each technology has its own limitations, and features detected by one tool could be missed by the other tool. Consequently, until one existing or new ILI technology has demonstrated its ability to catch all the features within its stated specification, employing multiple ILI technologies is an effective method to compensate for the weaknesses of any one particular ILI tool and ensure a higher level of safety for pipelines. An additional benefit of running multiple ILI tools is the opportunity for providing feedback of dig results to the different ILI vendors which could help them improve their own tool detection and sizing capabilities.

Pacific Gas & Electric Company (PG&E) operates multiple gas transmission pipelines on the San Francisco Peninsula, a significant portion of which operate at low Maximum Allowable Operating Pressure (MAOP), typically below 300 psig and are challenging to inspect using traditional ILI technology. This paper describes PG&E’s use of Non-Traditional robotic ILI technology to inspect numerous cased pipelines located in High Consequence Areas in the highly populated and dense urban area between the San Francisco International Airport (SFO) and central San Francisco. Examples will be provided for pipeline segments installed in various casing types, including sections inserted through utility infrastructure that was made available for use as a gas pipeline casing. Examples include pipe that was installed in the 1940’s and cased pipe installed without corrosion test stations. In some instances, the length of cased pipe sections were several hundred feet long and traversed locations difficult to access, such as major highway crossings and cased spans above water crossings. These inspections were executed in 2015 on 24 separate pipeline segments totaling more than 12,000 feet of pipeline. This paper explains how the inspection team utilized current technology and identified Non-Traditional ILI (NT ILI) as the preferred method. It also explains how the locations were scoped, project parameters and program strategy were developed, NT ILI tool selection, project outcomes, and lessons learned. An overview of the advantages of NT ILI methods to perform these cased pipeline inspections in-lieu of External Corrosion Direct Assessment (ECDA) and Traditional ILI will be discussed. This paper is applicable to Track 3 (Pipelines & Facilities Integrity) and also to Track 2 (Project Management, Design, Construction & Environmental Issues), and will be of interest to Pipeline Operators, Integrity Management Engineers, and Project Managers. The intent is to share PG&E’s experience utilizing Non-Traditional robotic ILI tools to perform difficult pipeline inspections in casings, as well as practical advice on scoping, planning, and execution of non-traditional ILI projects.

Since the market launch of Ultrasonic crack detection tools, the conventional crack depth sizing is based on four depth classes or buckets. A more differentiated, continuous depth sizing is becoming increasingly relevant for the pipeline operators and especially for pipelines with large populations of planar anomalies (SCC colonies, lack-of-fusion in ERW seam-welds, etc.). The ILI industry is introducing a continuous crack depth sizing. Next to the better differentiation and the linearity of the depth reporting, the main advantage of the continuous depth sizing is the direct comparability to the results of the field verifications. The continuous depth sizing improves the ability to assess the performance validation of the depth sizing and thus, contributes to a general improvement of the crack depth sizing. This paper describes the development and implementation of a continuous crack depth sizing approach and shows its advantages in comparison to the conventional depth classes. A sizing model is introduced, making use of an empirically derived function, that relates the amplitude measurement to the defect depth. The continuous depth sizing applies to crack-like defects with depths ranging from 1mm to 4mm. The parameters of the model are derived from performance tests based on artificial flaws. In addition, the model is validated by means of field verification results. The depth sizing accuracy and confidence levels are obtained from the performance test data in accordance to API 1163 [1] and POF 2009 [2]. In addition, the paper discusses the extraction of the crack depth profiles from inspection data, making use of the newly developed continuous depth sizing model. In comparison to standard reporting of maximum depth and length, crack depth profiles deliver more accurate and more valuable input to the integrity assessment for pipeline operators. Examples of a direct comparison of these crack depth profiles to field verification data are included.

Colombia is a country located in a geographical area with great geological diversity, where every day the effects of climate change increases the probability of the failure of buried pipelines due to the movement of land or the instability associated with them. That is why the use of geometric In Line Inspection (ILI) intelligent tools with the inertial module is important for the diagnosis of structural integrity of pipelines and is associated with an integrity management program due to the geotechnical threats present throughout its path. It decreases maintenance costs due to pump stoppage for unscheduled repairs, anticipating the solution, and mitigating and controlling deformations in the pipeline caused by geotechnical ground displacements. OCENSA-Pipeline Central SA (Colombia) has developed, through its experience, a program to manage integrity by determining the structural expense in specific sections due to displacement of the pipeline caused by ground movement through the use of the Geometric ILI tools and MFL inertial module. This paper specifically presents the use of the tool in decision-making based on OCENSA’s preset study limits for deformations in the elastic range and plastic building material of the pipeline. In 1997 OCENSA was among the first companies in Latin America to use Inertial Geo-positioning technology; today there are sectors which have been inspected with this technology as many as five times, in which pipe displacement of up to 5 meters has been found. The case study presented refers to a geographical point on the route of the pipeline located in the Andes, at the site of the movement known as the “La negra” ravine, near the town of Puente Nacional, where movements of the pipeline associated with geotechnically unstable slope conditions were detected by In line inspection (ILI) Geometric and inertial modules, beginning in 2004. Since that time, integrity management was conducted in order to reduce the chances pipeline failure will materialize in this area of geotechnical instability.

Oil and gas pipelines that pass through mountainous terrain are subject to an increase in the number of sections affected by the bending deformation’s resulting from external forces, which, when coupled with the construction and operational processes of the systems, cause mechanical damage to the pipelines that has led to containment losses, resulting in operational cost overruns and harmful effects on the environment and on nearby communities, while leaving at high risk the integrity of the petroleum infrastructure. By using primary data obtained through so-called “smart” in-line inspections or intelligent line inspections (ILIs), the occurrence and magnitude of these deformations and displacements of the pipelines can be determined. With the aid of geotechnical analytical techniques, this information can facilitate the interpretation of the processes that induce these thrusts. The starting point is the existing knowledge of the characteristics of the installation of the pipelines and of the clearances permitted by the rules and/or reference standards of the industry. The next step consists of comparing that data against the XYZ Data inertial mapping data (obtained through rotations of the XGP geometric tool) in one or more ILI runs, as part of the mechanical analysis procedure. As a recommended practice, an algorithm is developed for handling the ILI data, showing in parallel the geotechnical zoning data, illustrating it with a study algorithm.

Intelligent inline inspections (ILI) are widely used to guarantee a safe operation of pipelines. The inline inspection provides reliable data in an economic way. Historically, magnetic flux leakage technology (MFL) was one of the main technologies applied in pipeline systems. Within the last few years some minor improvements have been introduced in the existing MFL tool fleets, mainly focusing on a higher resolution. Nevertheless, a general restriction based on the physical basics finally limits the sizing capabilities of corrosion defects, esp. for complex shaped defects. Ultrasonic (UT) is currently the most accurate and reliable In-Line Inspection technology available in the market. These UT ILI Tools record data while travelling through the entire pipeline from Launcher to Receiver. In most cases, the Pipeline Operator does not need to make major adjustments to their pipeline. The latest generation of UT tools offers high inspection velocities — consequently a reduction of medium flow and loss of production can be avoided. In addition, a very high resolution of transducers in axial and circumferential direction provides excellent input for accurate pressure calculations, e.g. based on Riverbottom profiles or even 3D Finite element modeling. Using UT as the inspection method greatly increases the confident level of the inspection survey results. This in turn will give Pipeline Operators a greater peace of mind that their true pipeline condition is known thereby reducing unnecessary and costly digs and repairs. The authors will present some basic background information about ultrasound inspection technologies. State of the art solutions are presented for crack and wall thickness tools. Combining different technologies in one tool offers additional benefit. One single inspection tool with corrosion and crack transducers enables pipeline operators to operate their system safe with a minimized impact. Finally, the authors will present some special solutions for high pressure deep water applications and multi diameter pipeline systems.

In-line inspection (ILI) tools play an important role within integrity management and substantial investment is made to continuously advance performance of the existing technologies and, where necessary, to develop new technologies. Performance measurement is typically focused for the purpose of understanding the measured performance in relation to the ILI vendor specification and for the determination of residual uncertainty regarding pipeline integrity. These performance measures may not provide the necessary insight into what type of investment into a technology is necessary to further reduce residual uncertainty regarding pipeline integrity, and beyond that, what investment, as an operator, results in an effective and efficient reduction in uncertainty. The paper proposes a reliability based approach for investigating uncertainty associated with ultrasonic crack ILI technology for the purpose of identifying efficient investment into the technology that results in an effective and measurable improvement. Typical performance measures and novel performance measurement methods are presented and reviewed with respect to what information they can provide to assist in investment decisions. Finally, general observations are made regarding Enbridge’s experience using ultrasonic crack ILI technology and areas currently being investigated.

Managing the threat of Stress Corrosion Cracking (SCC) in natural gas pipelines continues to be an area of focus for many operating companies with potentially susceptible pipelines. This paper describes the validation process of the high-resolution Electro-Magnetic Acoustical Transducer (EMAT) In-Line Inspection (ILI) technology for detection of SCC prior to scheduled pressure tests of inspected line pipe valve sections. The validation of the EMAT technology covered the application of high-resolution EMAT ILI and determining the Probability Of Detection (POD) and Identification (POI). The ILI verification process is in accordance to a API 1163 Level 3 validation. It is described in detail for 30″ and 36″ pipeline segments. Both segments are known to have an SCC history. Correlation of EMAT ILI calls to manual non-destructive measurements and destructively tested SCC samples lead to a comprehensive understanding of the capabilities of the EMAT technology and the associated process for managing the SCC threat. Based on the data gathered, the dimensional tool tolerances in terms of length and depth are derived.Copyright © 2014 by ASME

It is important to validate the accuracy of in-line inspection (ILI) tools to know how many excavations are needed to maintain the integrity of a pipeline segment. Performing sufficient excavations is important to ensure there are no defects left in the pipeline that have even a remote chance of failure. In some cases additional excavations may be necessary to ensure safety where in other cases no excavations may be necessary. This paper looks at using spatially recorded metal-loss data collected “in-the-ditch” to measure the accuracy of ILI tool results. Examples of spatial in-ditch data are laser scans for external corrosion and UT scans for internal corrosion. Spatially mapped metal loss, because all of the corrosion area is mapped, has the advantage of allowing more comparisons to be made for a given corrosion area and also allows the interaction among corrosion pits to be studied for examining burst pressure calculation accuracy. From our studies we find the depth error for shallow corrosion 10%–20% wt deep is often not representative of deeper corrosion in the same pipeline and the interaction criteria for ILI tools needs to be larger than the interaction criteria for in-ditch data. Examples are shown with these types of results, and by interpreting the results in conjunction with API 1163, certain ILI runs are shown that require no excavations where others may require additional excavations than suggested by normal +/−10% wt ILI data.Copyright © 2014 by ASME

Cracks or crack-like defects have been associated with failures in gas transmission pipelines and gas distribution piping systems, some incidents being consequential. Cracks are identified in natural gas pipeline safety regulations and safety standards as conditions that must be dealt with, however critical sizes or other specific evaluation criteria are not generally given. A hydrostatic test pressure to specified margins above the operating pressure could establish a benchmark for critical sizes that are a potential threat to the integrity of the pipe. Cracks that are too small to fail at the hydrostatic test pressure may still remain present in the pipeline. Ideally, determination of a sufficient margin of safety to identify defects that should be monitored after taking into consideration the potential growth of crack or crack like defects that are too small to fail a hydrostatic test pressure will address defects of concern that may remain present in the pipeline. The development of an integrated robotic internal inspection tool that can be used to accurately detect and size cracks or crack like features in natural gas pipelines is of mutual interest to pipeline regulators and operators. NDE technology carried by inline inspection tools should be at least capable of identifying cracks or crack like features that would fail in a hydrostatic pressure test or could potentially grow to failure with a high degree of probability prior to the next ILI reassessment. The tool and its integrated software algorithms must be capable of indicating the location, position, orientation, size, and characteristics of defects of interest or concern to minimize validation and/or repair costs and to preserve the overall integrity of pipelines in a gas transmission operator’s integrity management program. This paper develops criteria for the minimum detection requirements of cracks or crack-like defects by an ILI tool to ensure equivalent integrity to that provided by a hydrostatic pressure test performed to standard requirements. The critical defect sizes will be estimated using fracture mechanics (e.g., the Modified NG-18 equation) considering different toughness categories. The paper addresses the challenge of variability in the real material properties through two approaches. The first approach is to conduct three sets of analyses for each material grade based on the lower 5% percentile, mean and upper 95% percentile properties. The second approach is to conduct the analysis based on Monte Carlo simulations to generate random combinations of material properties as well as crack dimensions.

The occurrence of low-frequency Electric Resistance Welded (LF-ERW) or Electric Flash Welded (EFW) line pipe imperfections has been the root cause of many integrity management initiatives to minimize and mitigate the risk of pipeline failure across the oil & gas pipeline industry. Since their first appearance in the 1920s, defects in or near the LF-ERW and EFW seam repeatedly lead to either hydrostatic test or in-service failures. Where in the past In-Line Inspection (ILI) technologies might have experienced limitations in addressing vintage ERW line pipe defects, modern smart ILI technologies show enhanced capabilities. High resolution Electro-Magnetic Acoustic Transducer (EMAT) and Circumferential Magnetic Flux Leakage (CMFL) ILI technologies have advanced in the recent years enabling more challenging inspections. This paper summarizes the inspection results of 22″ ERW line pipe defects detected and reported by EMAT and CMFL. Correlation of ILI and manual NDE data enables evaluation of current ILI capabilities and improvement of current defect assessment methods.Copyright © 2014 by ASME

Pipeline dents and mechanical damage remain an integrity threat within the Oil & Gas pipeline industry. Such features typically consist of a localized deformation of the pipe wall. Under certain conditions, cracking may develop within or adjacent to the area of deformation due to stress concentration factors resulting from the deformation itself or from secondary damage such as a scrape or gouge. Conventional inline inspection technologies consistently to date have not explicitly addressed inspection capabilities for cracking within dents. This paper presents the results of a collaborative technical effort to assess and advance the abilities of EMAT inline inspection technologies to identify and characterize such mechanical damage features as found in liquid pipelines. The background and application of these advanced technologies for the targeted threats is discussed, as well as the experimental testing performed and results achieved.

With the current generation of in-line inspection (ILI) tools capable of recording terabytes of data per inspection and obtaining millimeter resolution on features, integrity sciences are becoming awash in a sea of data. However, without proper alignment and relationships, all this data can be at best noise and at worst lead to erroneous assumptions regarding the integrity of a pipeline system. This paper will explore the benefits of a statistical alignment method utilizing joint characteristics, such as length, long seam orientation (LSO), wall thickness (WT) and girth weld (GW) counts to ensure precision data alignment between ILI inspections. By leveraging the “fingerprint” like morphology of a pipeline system many improvements to data and records systems become possible including but not limited to: • Random ILI Tool performance errors can be detected and compensated for. • Repair history and other records become rapidly searchable. • New statistically accurate descriptions are created by leveraging the sensitivities of various ILI technologies. One area of material data improvement focused on within this paper relates to long seam type detection through ILI tools. Due to the differing threat susceptibility of various weld types, it is accordingly important to identify the long seam weld types for integrity management purposes. Construction records of older vintage lines do not always contain information down to the joint level; therefore, ILI tools may be leveraged to increase the accuracy of construction records down to this level. In this paper, the possibility of ILI tools, such as magnet flux leakage tools, ultrasonic crack tools, and ultrasonic metal loss tools, to distinguish different types of longitudinal seam welds is also discussed.

To support pipeline integrity initiatives, Spectra Energy (Spectra) undertook to verify the pipeline coating condition on certain pipeline assets by performing DCVG or ACVG surveys on Class 2 and Class 3 locations and in HCA’s. The process undertaken was to consider the alignment of coating anomaly indications with ILI anomaly indications and to compare the results of direct examinations to anomaly indications. The alignment and comparison of the data is based upon the analysis of DCVG, ACVG, CIS and ILI data. The results of the direct examinations at the sites in the affected segments were reviewed to evaluate the condition of the pipelines as it relates to specific severity of the identified coating anomalies. This paper will discuss the results and findings of those studies.

This paper presents guidelines to enable a pipeline operator to assess whether the results of a metal loss in-line inspection (ILI) should be deemed acceptable. Acceptance depends on passing two checks, Verification and Validation. Verification is the process which ensures that all planning, preparation, execution, and analysis of the inspection were conducted according to ILI vendor processes to meet specification and prescribed industry standards. It assumes that a successful run is a consequence of good planning, preparation, execution and analysis. Validation is the process by which the results of an ILI run are compared to independent measurements. The Validation process depends on the results of the ILI and available information. Passing both the Verification and Validation checks is required to accept of the ILI run.Copyright © 2012 by ASME

Crack inspection of pipelines using liquid-coupled ultrasonic technology has established itself as an accepted ILI (in-line inspection) technology that is routinely applied by many operators. The inspection is based on the pulse-echo technique using 45° shear waves which provide very good detection sensitivity. While length sizing of cracks is reasonably precise, the accuracy of (amplitude-based) depth sizing is limited to some extent. Apart from the crack size, the methods applied for crack assessment have to take into account the geometry of the actual pipe, the relevant material properties and the loading conditions. The work presented is based on the FAD method (Failure Assessment Diagram) being the most common technique for assessment of crack-like defects in pipes. It is shown how the assessment results depend on the quantities determined by ILI (e.g. crack size, wall thickness) and their associated measurement uncertainties. Using a deterministic approach the sensitivity with regard to the different parameters can be compared quantitatively. Probabilistic crack assessment based on the combination of the FAD method with Monte Carlo simulations is well suited for taking into account the statistical distribution of the measuring tolerances. It allows, for example, the calculation of statistical properties such as the probability of failure as will be demonstrated for realistic defect situations.

Pipeline operators often deal with the large numbers of dents that require further consideration, and are required to prioritize these dents for further investigation and repair. Code guidance is clear on the relative severity of dents based on a depth or associated with welds, corrosion, gouging or cracking. It allows the pipeline operators to prioritize their dig lists and limit the number of “investigative digs” by omitting plain and shallow dents. However, the dent depth criterion has limitations, experiences learned in the past have shown that a dent prioritization based on depth alone, may still leave a significant number of dents in the pipeline which may pose a threat, particularly from local static strain and fatigue. In recent years, strain and fatigue analyses have been included in the assessment of severity of dents in order to better prioritize and effectively repair dents which represent a threat to the structural integrity of pipelines. However, strain analyses require tedious calculation of dent curvature at each data point from ILI reported dent profile. When a large numbers of dents require to be prioritized by strain severity, using this detail calculation is impractical. Therefore, a screening methodology is required to reliably identify candidate dents that require detail strain assessment. In this paper, an aspect-ratio based screening methodology is developed and applied to over 7,000 dents reported by an In-Line Inspection (ILI) caliper tool for a 265 miles long pipeline section. A total of 263 shallow dents which could have injurious strain level were identified and ranked for detail strain and fatigue calculations. In-ditch investigation of 20 dents with LaserScan profiling showed that the developed screening methodology provides an effective tool to capture all the dents with strain equal and 6.5% at 95% confidence level.

The importance of comparing in-line inspection (ILI) calls to excavation data should not be underestimated. Neither should it be undertaken without a solid understanding of the methodologies being employed. Such a comparison is not only a key part of assessing how well the tool performed, but also for an API 1163 evaluation and any subsequent use of the ILI data. The development of unity (1-1) plots and the associated regression analysis are commonly used to provide the basis for predicting the likelihood of leaks or failures from unexcavated ILI calls. Combining such analysis with statistically active corrosion methods into perhaps a probability of exceedance (POE) study helps develop an integrity maintenance plan for the years ahead. The theoretical underpinnings of standard regression analysis are based on the assumption that the independent variable (often thought of as x) is measured without error as a design variable. The dependent variable (often labeled y) is modeled as having uncertainty or error. Pipeline companies may run their regressions differently, but ILI to field excavation regressions often use the ILI depth as the x variable and field depth as the y variable. This is especially the case in which a probability of exceedance analysis is desired involving transforming ILI calls to predicted depths for a comparison to a threshold of interest such as 80% wall thickness. However, in ILI to field depth regressions, both the measured depths can have error. Thus, the underlying least squares regression assumptions are violated. Often one common result is a regression line that has a slope much less than the ideal 1-1 relationship. Reduced Major Axis (RMA) Regression is specifically formulated to handle errors in both the x and y variables. It is not commonly found in the standard literature but has a long pedigree including the 1995 text book Biometry by Sokal and Rohlf in which it appears under the title of Model II regression. In this paper we demonstrate the potential improvements brought about by RMA regression. Building on a solid comparison between ILI data and excavations provides the foundation for more accurate predictions and management plans that reliably provide longer range planning. This may also result in cost savings as the time between ILI runs might be lengthened due to a better analysis of such important data.

Many pipelines are vulnerable to multiple threats and damage types such as internal and/or external corrosion, axial and/or circumferential cracking, laminations, gouging, dents, ovalities and wrinkles. These different types of damage may occur in isolation or can occur coincidental at the same location in the pipeline. Whilst two or more of these feature types may be coincident in the pipeline, the different feature types often require detection by different ILI technologies which are quite often run at different times and even by different ILI vendors. It is important to identify where different types of features are coincident: • Discrimination and sizing of certain feature types can be adversely affected and hence uncertainties may be higher at these locations. • Evaluation of feature severity should account for the types of feature present and any interaction between features. • To aid the excavation and repair planning processes. It can be difficult and time consuming to identify the exact location where multiple features may be coincident with each other because this requires accurate alignment, accounting for positional tolerances, matching and overlay of data from ILI runs of different technologies and often from several years apart. This paper describes an approach to identify where coincidental features occur within a pipeline by: • Combining and overlaying multiple ILI technologies and data sets in a common interface. • Allowing different proximity tolerances to be used to account for positional accuracy in the determination of coincident feature groups. • Enabling the identification of the ILI reported features (e.g., cracks, internal and external corrosion, dents, mill faults including laminations, gouges etc.) that could be coincident and therefore may interact. Case studies are used to illustrate the approach and to evaluate the results obtained.

The purpose of this paper is to present a non-traditional pipeline mechanical damage ranking system using multiple-data-set in-line inspection (ILI) tools. Mechanical damage continues to be a major factor in reportable incidents for hazardous liquid and gas pipelines. While several ongoing programs seek to limit damage incidents through public awareness, encroachment monitoring, and one-call systems, others have focused efforts on the quantification of mechanical damage severity through modeling, the use of ILI tools, and subsequent feature assessment at locations selected for excavation. Current generation ILI tools capable of acquiring multiple-data-sets in a single survey may provide an improved assessment of the severity of damaged zones using methods developed in earlier research programs as well as currently reported information. For magnetic flux leakage (MFL) type tools, using multiple field levels, varied field directions, and high accuracy deformation sensors enables detection and provides the data necessary for enhanced severity assessments. This paper will provide a review of multiple-data-set ILI results from several pipe joints with simulated mechanical damage locations created mimicing right-of-way encroachment events in addition to field results from ILI surveys using multiple-data-set tools.Copyright © 2012 by ASME

In-line inspection by inertial mapping techniques is an essential tool for pipeline operators in areas susceptible to geohazards. The detection of previously unknown movements can provide early warning of the presence of a hazard. Positional change and the nature of the loading process can be monitored using the results of multiple inspections over time. Structural modelling is required to fully evaluate the integrity of the pipeline and whether a failure condition is being approached. Finite element techniques can be used, including the effects of soil-pipe interaction, axial forces and operational loads. This enables the prediction of future performance, based on trends from multiple inspections, so that mitigation or intervention methods are efficiently designed and scheduled. This paper considers some key aspects of the analysis process. The use of ILI mapping data to detect small movements below the tool measurement tolerance is examined. The importance of structural analysis is demonstrated by consideration of the axial force component. The inherent variability of the soil surrounding the pipe and its influence on the load transfer effects is illustrated, together with the issues of significant interaction within the transition zones of landslides or faults.

Pipelines that cross mountainous areas are susceptible to ground movement loading from landslides. In-line inspection using inertial mapping tools provides an excellent method of evaluating the current pipeline integrity. A single inspection only gives an indication of the pipeline integrity at a single point in time. Multiple inspections over a period of time can be used to estimate positional change and the nature of the loading process. An essential element of pipeline integrity management in geohazard areas is the ability to determine future performance so that intervention methods are correctly designed and scheduled and resources are efficiently administered. This requires the reliable prediction of the future development of pipeline integrity based on trends in the mapping data from multiple inspections. The approach developed by the authors to predict the future integrity of pipelines affected by ground movements is set out in this paper. It involves inertial mapping data from multiple inspections and calculates future strains in the pipeline using finite element analysis. Unlike methods based on interpreting inspection data alone, the finite element model includes the effects of soil-pipe interaction and axial pipeline stress together with the operational loads to provide a more complete assessment of pipeline integrity. The method is illustrated through the use of a case study.

Magnetic Flux Leakage inspection tools are generally calibrated on a series of manufactured defects. This has been shown to give good results on a wide range of defects in varying wall thicknesses, velocities and pipeline conditions. Significant improvements in sizing performance can be achieved if sizing algorithms can be optimized on high resolution field data with low uncertainty that more closely reflects the actual line specific corrosion dimensions and profiles. The effects of defect profile can be significant to the MFL signal response. In order to achieve this goal, very high resolution and accurate field measurement techniques are needed to map the combined profile of a significant number of corrosion defects. This paper discusses a process for developing high performance sizing algorithms that consistently better industry standards for MFL sizing performance in areas of high density or complex corrosion in both oil and gas pipelines through the incorporation of high resolution laser scan technology. Complex corrosion may be considered as an area wherein individual corrosions interact together such that they no longer behave as a single corrosion and the MFL response experiences a superposition of leakage signals. A review of the methodology will be discussed and the results demonstrated through case studies from both Enbridge Pipelines Inc. and TransCanada Pipelines Ltd. where high-resolution field data was used as the basis for sizing model optimization.Copyright © 2012 by ASME

Pipeline seam welds are often inspected using ultrasonic In-Line Inspection (ILI) technologies. The measurement performance specification of an ultrasonic ILI tool is based on simple, planar, machined notches which are very reproducible, but are not representative of the complex flaw morphologies that occur naturally in seams such as hook cracks and tilted lack of fusion flaws. In order to assess ILI performance on naturally occurring flaws, “in-the-ditch” Nondestructive Testing (ITD NDT) is performed to validate a subset of the population of ILI reported features. Due to the limited number, type, and dimensional (height and length) uncertainty of these flaws, the field validation approach has limitations in terms of efficiency and accuracy in determining ILI detection capabilities and sizing performance. Recently, specialized synthetic flaw fabrication technology has been developed and provides complex, natural crack-like morphologies with reliable and reproducible size dimensions. Effective validation spools with flaws (of representative geometries) can be achieved through engineered designs that consider the number, size and shape of manufactured flaws. This enables owners to quickly and reliably assess the performance of both ILI tools and ITD NDT operators. Assessing performance with the synthetic flaw approach provides results that are more comprehensive and cost-effective compared to the typical field validation approach alone. This is because the flaw population is designed rather than randomly selected from excavation data. This paper addresses the design, use and field experience with validation spools. This paper will present the performance of ILI tools and UT examiners based on synthetic flaw qualification exams, and how this supports related ILI and operator validation work.

To ensure the safe transportation of energy, Canadian pipeline operators spend roughly $1.5 billion every year on pipeline integrity. The most practiced form of pipeline integrity is the use of inline inspection (ILI) tools. To ensure that an ILI inspection occurs with minimal to no complications, operators often utilize tracking techniques for the runs. These techniques can be costly and have large safety risks and environmental impacts due to the nature of using manpower to perform the operation. Using advanced Intemet of Things (IOT) telemetry devices, the tracking of ILI tools can be completed from remote locations by installing IOT devices semi-permanently along a pipeline right -of-way. This advancement has ensured the efficient, safe and reliable tracking of ILI tools while eliminating risks involved with conventional tracking. Furthermore, the current generation of IOT telemetry devices offers a tailored suite of ILI tracking sensors such as magnetics, ultrasonic frequency, extremely low frequency (22 Hz), and geophone. This multi sensor tracking solution increases an operator’s confidence in pig passages and flow rate estimations which allows the operator to optimize pump station bypassing. Finally, the IOT telemetry devices are supported by Global System for Mobile Communications (GSM) and satellite link which has ensured global coverage to remotely track tools. The communication module for the semi-permanent tracking solution is decided based on network availability and endpoints. This paper will present a comprehensive analysis that compares conventional ILI tracking to cutting-edge IOT telemetry ILI tracking and illustrates improvements in operational efficiency, operational risk, overall safety, environmental impact, and cost-effectiveness. In addition, case studies from recent tracking runs will be shared to demonstrate advancements in IOT telemetry, tracking sensor technology, dynamic user interface capabilities, advanced data dissemination methods, and high precision benchmarking.

Pipeline operators use different approaches, often in combination, to ensure the safe operation of an asset. Historically, hydrostatic testing is the most accepted methodology for assessing critical flaws in a pipeline system, achieved by stressing the pipeline above the standard operating limits. By design, a release during this test removes a critical flaw from the system. There are significant drawbacks to this type of assessment. Such drawbacks include high costs of implementation, feature growth, previously blunt defects sharpening and system downtime. Driven by the operator (Marathon Pipe Line) to investigate alternative approaches, a consortium of (4) parties formed to develop and validate an alternative and enhanced solution. The research and execution of the project was structured in (4) phases. • Phase I — Determine which crack morphologies are challenging to ILI technology in terms of detection and depth determination and test initial improvements to ILI technology. This included loop testing improved crack detection ILI robots and destructive assessment with pipe samples to identify gaps in ILI technology and analysis techniques. • Phase II — Assess vendor improved ILI technology on the operating pipelines using advanced in the ditch non-destructive evaluation (NDE) methods and destructive testing of pipe samples from the pipelines. Identify the additional improvements if necessary. • Phase III — Implement specific improvements to ILI technology that are completed based on Phase I and II results. Validate the new ILI platform on the specific pipeline. • Phase IV — Determination whether the new ILI platform can provide equivalent pipe seam system reliability to hydrostatic testing. A probabilistic approach will be used that would account for the expected statistical distribution of pipe properties, fatigue crack growth rates, position along the pipeline, and flaw sizes. This paper is a summary of the research and work for this ILI In Lieu of a Hydrostatic Testing initiative.

The current finite element (FE) assessment methods of dented pipes are based on specific dent profiles, which are generally created based on the shape of indenters. However, the actual dent profile in real case scenarios is mostly irregular in shape, depending on the cause of damage. In this paper, FE analyses of dented pipes using inline inspection (ILI) data are presented. Based on the ILI data, the dent profile is generated by applying the nodal displacements to all the pipe nodes. The validation of this nodal displacement approach is discussed in this paper. Besides, a parametric study is carried out to study the behavior of dent for different dent depth, pipe geometry, and pipe grades. The significance of residual stresses generated during the dent formation on the behavior of dented pipe during the service life is also discussed. Finally, the remaining life estimation of dented pipes according to the API 579-1 is presented using FE analysis results.

Inline Inspection Internal Measurement Unit (ILI IMU) data analysis is a well understood but often under-utilized technology for detecting, defining, assessing and monitoring soil to pipeline interactions. The technology has been successfully used to detect landslide interactions since 1996 [1]. Operators can be provided with a vendor analysis (initial bending strain or run to run movements) and/or processed raw data for either internal or third-party raw data Analysis [2]. Vendor Analysis typically identifies major soil/pipeline interactions but primarily reports dig related settlements [3] and static construction related features. Raw data analysis is typically used to define interactions and provide detailed pipe shapes and deformations within targeted pipeline segments. An approach for determining ILI IMU analysis/data requirements for individual ILI run segments for any size of pipeline system is presented. Guidelines for analysis are provided for Operators to optimize efforts based on the hazards encountered in individual pipelines or pipeline systems. The process includes feature screening, integrity/geotechnical specialist review and risk control/mitigation measures, if required. To facilitate the feature screening process, a classification system for ILI IMU features is presented based on their type, activity and source modified from the system presented in [3].

Gas transmission pipeline operators increasingly rely on Electro-Magnetic Acoustic Transducer (EMAT) technology to reliably detect, identify and size stress corrosion cracking (SCC) anomalies in their pipeline system. However, scheduling EMAT in-line inspection (ILI) on every pipeline in the system is not always practicable or achievable in an expeditious manner. A means of conducting a preliminary assessment of the SCC threat on pipelines without EMAT ILI data in an objective and quantifiable manner is useful for understanding the threat level and for prioritizing or deciding on outstanding EMAT inspections. A wealth of system-specific SCC field data from historical integrity excavations across the pipeline system typically exists in a pipeline operator’s dataset and can be readily leveraged for quantitatively estimating the SCC threat reliability in other, similar (“like-in-kind”) parts of the pipeline system. This system-specific data, based on actual SCC findings from integrity excavations, is an improved and more granular alternative to applying industry-wide SCC statistics to estimates of SCC reliability levels on pipelines without EMAT ILI data. This paper presents a robust and direct limit state approach for estimating the SCC reliability level in pipelines that have not yet had an EMAT ILI completed by leveraging system-wide SCC field findings from historical integrity excavations.

In-line inspection is a non-destructive assessment method commonly used for defect assessment and monitoring of pipelines. The passage of an ILI tool through an excavated or exposed section of a pipe during an integrity assessment can excite vibrations and exert substantial forces, stress, and deflections on the pipe due to the weight and speed of the ILI tool. When the excitation frequency due to the ILI tool movement is close to the natural frequency of the overall structure, the dynamic stress generated within the pipe can be large enough to the extent that it imposes integrity concern on the line. This research aims to study effects of the ILI tool passage through floating and partially supported pipes under a variety of boundary and loading conditions. A finite element method is used to model the pipe with moving ILI tool. The model is developed based on Timoshenko beam theory with planar degrees-of-freedom and the differential equations of motion are solved numerically to predict displacement, strain, stress, and frequency responses of the pipe. The model is further validated using a lab-scale experimental setup. The comparison of the simulation to experimental results show how the proposed model is capable of predicting pipe dynamics, effectively.

Axial Strain Inline Inspection has transitioned from an experimental to commercial technology that will develop significantly as the industry requires. Axial strain tool measures total elastic longitudinal strain on a pipeline including: imposed strains due to manufacturing; construction/cold bending; backfilling; and loading associated with abnormal forces such as ground movement and settlement. The technology is based on magnetostriction, which measures the permeability and magnetic induction of ferromagnetic materials. Magnetostriction is well understood, but the application of the technology to active pipelines is relatively recent. Currently, Inertial Measurement Unit (IMU) inline inspections (ILI) effectively identify areas of localized bending strains and can be used for monitoring of pipeline movements run to run, but they do not detect axial strain associated with either tensile or compressive loading. Currently, axial strain modules are mounted behind Magnetic Flux Leakage (MFL) platforms and have either 4 or 8 probes that provide circumferential readings typically at 0.5 to 1 m intervals. Data is either considered “trend” or “calibrated” depending on whether representative test samples are available. Interpretations are provided by the vendor in the form of Axial Strain Variation which is the averaged value of a set of readings with the hoop strain component removed. Additionally, data from each probe is analyzed to establish the maximum and minimal longitudinal strains (εmax/εmin) with locations around the circumference of the pipeline. Given the potential complexity of locked-in strains, simple calculations using sinusoidal bending relationships do not apply. Therefore, curve fitting analysis is required to determine the circumferential strains. This paper includes operational learnings from the analyses of data from eight (8) Axial Strain ILI runs within variable terrain on some natural gas transmission and gathering pipelines in British Columbia by verifying strains due to known abnormal loading as well as identifying previously unknown features (landslides, in particular). In addition, sources of error, data anomalies, current limitations and potential improvements of the technology are discussed.

This paper describes a novel technique for the detection of cracks in pipelines. The proposed in-line inspection technique has the ability to detect crack features at random angles in the pipeline, such as axial, circumferential, and any angle in between. This ability is novel to the current ILI technology offering and will also add value by detecting cracks in deformed pipes (i.e. in dents), and cracks associated with the girth weld (mid weld cracks, rapid cooling cracks and cracks parallel to the weld). Furthermore, the technology is suitable for detection of cracks in spiral welded pipes, both parallel to the spiral weld as well as perpendicular to the weld. Integrity issues around most features described above are not addressed with ILI tools, often forcing operators to perform hydrostatic tests to ensure pipeline safety. The technology described here is based on the use of wideband ultrasound inline inspection tools that are already in operation. They are designed for the inspection of structures operating in challenging environments such as offshore pipelines. Adjustments to the front-end analog system and data collection from a grid of transducers allow the tools to detect cracks in any orientation in the line. Description of changes to the test set-up are presented as well as the theoretical background behind crack detection. Historical development of the technology will be presented, such as early laboratory testing and proof of concept. The proof of concept data will be compared to the theoretical predictions. A detailed set of results are presented. These are from tests that were performed on samples sourced from North America and Europe which contain SCC features. Results from ongoing testing will be presented, which involved large-scale testing on SCC features in gas-filled pipe spools.

Integrity reliability science plays a major role in the integrity management of transmission piping, which is piping that traverses long distances across the continent, at high pressures, and can experience high pressure cycling. This science can be applied to non-transmission piping such as lateral piping, which traverses between a transmission line and a facility, or between two facilities, at lower pressures and with lower pressure cycling. Laterals are susceptible to the same threats as transmission lines (internal corrosion, external corrosion, cracking, geotechnical hazards, etc.). However, due to their operation, laterals are only highly susceptible to internal and external corrosion. While site specific conditions may result in a high susceptibility of a geotechnical hazard, this threat is outside of the scope of this paper. On transmission piping, corrosion is generally managed with In-Line Inspection (ILI), Non-Destructive Examination (NDE), and corresponding repairs (e.g. sleeving) to assess and mitigate. With laterals, there can be limited ILI and NDE data. As such, the data used in the quantitative reliability framework for these threats is not available and this creates a gap in the process. This paper addresses this gap through the application of semi-quantitative reliability analysis for internal and external corrosion on laterals along with a risk-based integrity decision making framework. The proposed approach is designed to enable pipeline and facility operators to make effective decisions around lateral integrity programs given the available data, and to better understand the limitations of integrity decision making. Moreover, the paper expands the discussion around the difference between risk-informed and risk-based integrity decision making in order to provide a guideline for optimal and safe integrity management programs considering different criteria. Case studies that include limited or no ILI or NDE information are used to demonstrate the application of semi-quantitative and quantitative reliability assessment of laterals along with the exploration of challenges in calibrating the two assessment methods to provide an example of how reliability science can be applied to laterals and how this can be used in effective decision making given such limitations.

TransCanada was faced with a significant challenge to inspect a 941 km NPS 48 pipeline. The options for the inline inspection (ILI) were multiple segments which would cause an increased cost with new pigging facilities required and a delay to the ILI schedule or attempt to pig the longest natural gas pipeline section in North America. The extraordinary proposal would require a massive 48″ combination Magnetic Flux Leakage (MFL) tool to traverse a high-speed gas pipeline 941km from Burstall, Saskatchewan to Ile des Chenes, Manitoba, Canada. Given the alternative of the installation of 3 additional launcher and receiver stations and the risk to overall project schedule from extended inspection operations, TransCanada took the bold decision to perform an MFL inspection in a single pass. However, as expected, this option created a new set of challenges to guarantee first run success in one of the harshest environments for an ILI tool and in a line where the cleanliness condition was unknown. This last factor, was a critical concern as the volumes of debris that could be collected with the highly aggressive MFL tool brushes, could easily and very quickly have led to very significant debris build up during inspection that at best would likely cause degraded data leading to an unwanted re-run and at worst the possibility of a stuck pig and subsequent retrieval program. From a project perspective either occurance was considered to be mission critical — if either occurred there was no easy solution to collecting the much needed condition data of the pipeline. In July 2017, a successful VECTRA HD GEMINI inspection was completed. This paper discusses the main program risks, mitigation steps taken over and above a standard ILI run. Key considerations and actions taken relating to additional engineering and tool modifications to various components of the inspection vehicle itself will be discussed. Lastly, insight will be given into an extensive smart cleaning program developed with the ILI vendor, using a combination of mechanical cleaning associated and debris level assessment, specifically designed and tailored for the project to ensure that the pipeline was both ready for ILI and that cleaning had reached optimum for ILI so that full, high quality MFL data would be collected the first time.

In the pipeline industry, a widely accepted methodology for integrity crack management involves running ultrasonic In-Line Inspection (ILI) technologies. After an ILI tool run is completed, the performance of the tool is typically validated by excavating the pipeline and conducting in-the-ditch investigations. Ultrasonic Non-Destructive Evaluation (NDE) techniques are used in the field to characterize and measure crack-like features. These in-the-ditch measurements are compared back to ILI results in order to validate tool performance and drive continuous technology improvements. Since validation of the ILI tool relies on NDE measurements, acquiring accurate and representative data in the field is a critical step in this integrity crack management approach. Achieving an accurate field inspection comes with its challenges, some of which relate to complex long seam weld conditions present in older vintage pipelines including: weld misalignment, weld trim issues, and dense populations of manufacturing anomalies. In order to better understand the challenges associated with complex long seam weld conditions, an evaluation and comparison of the performance of NDE technologies currently available was conducted. In this study, a portion of a Canadian pipeline with complex long seam weld conditions was cut-out and removed from service. Multiple NDE crack inspection technologies and methods from three different vendors were used to assess the condition of the long seam weld. Conventional Ultrasonic Testing (UT), Phased Array Ultrasonic Testing (PAUT), Time of Flight Diffraction (TOFD), and variations of Full Matrix Capture Ultrasonic Testing (FMCUT) were used to assess the long seam weld and their results were compared. The performance of all NDE technologies is baselined by comparing them with destructive examination of sections of the long seam weld. The newer NDE assessment methodologies were shown to be consistently more accurate in characterizing long seam features.

Pipeline operators rely extensively on in-line inspection (ILI) systems and other forms of non-destructive examination (NDE) as the basis for meeting the continual assessment requirements to evaluate pipeline integrity. The verification of ILI prediction accuracy involves correlating ILI data to direct inspection/assessment information using traditional NDE methods such as Ultrasonic Testing (UT), Phased Array Ultrasonic Testing (PAUT), and Electromagnetic Testing (ET). Substantial effort has been taken to establish and consider measurement tolerances for ILI systems, but not as much attention has been placed on understanding the tolerances of NDE technologies. Through studies conducted by Pipeline Research Council International, Inc. (PRCI) these NDE methods have been shown to have inconsistencies and inaccuracies in sizing and characterizing pipe wall and weld seam crack-like anomalies. Effectively managing the uncertainty in NDE measurements and selection of the appropriate technologies for anomaly verification is as important to continuous improvement in pipeline integrity management programs as ILI tool tolerance. A primary goal for pipeline operators is to develop field-ready NDE methods for full volumetric characterization of pipeline anomalies. The inability of traditional NDE methods to accurately provide a three-dimensional (3D) image of a pipe wall features in the field leads to critical decisions being made based on imprecise tools, with layers of conservatism being included in the analysis for both NDE and ILI measurements. The lack of precision often leads to conservative and therefore excessive repair digs, unnecessary pipe replacements, and in some cases hydrostatic pressure testing of the pipeline to verify the system integrity. This paper presents the results of a research project that includes comparative analysis of seam anomaly characterization data from an ILI system, traditional NDE inspection, Computed Tomography (CT), and metallurgical results. CT is the only current method that has shown consistency in providing accurate 3D profile measurements of an anomaly comparable to destructive testing and direct measurement of anomaly characteristics. The CT results presented in this paper represent the potential for field ready inspection capabilities as the data were obtained from full circumference measurement of pipe samples rather than plate samples, which have typically been studied in prior analysis of CT methods. Obtaining accurate data on anomaly dimensions is critical to understanding and improving the application of ILI and NDE data to drive integrity decisions. Improved results in the field will lead to improved decision-making to protect the environment and public safety.

Pipeline integrity management commonly leverages nondestructive inspection of pipeline defects via inline inspection (ILI) and assessment of the resultant data. Key parameters for dent analysis include the feature geometry measured by caliper tools and the presence/severity of any interacting features (such as cracks or areas of corrosion) which can be measured with a variety of technologies (such as magnetic flux leakage or ultrasonic tools). Dent profile measurements can be especially susceptible to noise due to the measurement techniques employed, signal quality, and overall tool performance. Analytical methods for strain assessment of dents can employ curve/surface fitting techniques to estimate the curvature and calculate the strain of the dent based on the fitted curve/surface. Noise in the measured profile can result in local areas of high perceived strain, which could lead to misinterpretation of a dent’s true severity, especially when using automated or purely analytical assessment methods. A deterministic strain-based approach for evaluating the severity of dented pipelines has been presented previously which leverages multi-dimensional B-spline functions to more accurately apply the non-mandatory ASME B31.8 equations for dent assessment. The approach presented previously requires relatively smooth dent profile information to minimize the effects of signal noise. While low pass filters can effectively eliminate noise in the signal, they may also lead to loss of accuracy (e.g. excessive smoothing can reduce the depth and sharpness of a measured dent’s profile). This paper discusses how low pass filters can be optimally used to smooth the raw ILI signals to allow for analytical representation of the dent shape without underestimating its severity. The conclusion of this venture is a detailed workflow for the analytical assessment of dented pipelines for the rapid characterization of the severity of deformation in pipelines with limited computational demand. This type of assessment allows for initial ranking and assessment of large and complex pipeline systems to select features requiring more detailed assessment or mitigation.